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

FORM 10-K/A

(Amendment No. 2)

ý	Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	for the fiscal year ended December 31, 2005.

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		(I.R.S. Employer
incorporation or organization)		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 is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No ý

Indicate by check mark if the registrant is not required file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No ý

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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one)

Large accelerated filer o Accelerated filer ý Non-accelerated filer o

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

The aggregate market value of Common Units held by non-affiliates of the registrant on June 30, 2005, was approximately $383,456,000.

As of June 15, 2006, the number of the registrant’s Common Units and Subordinated Units were 11,079,219 and 1,800,000, respectively.

DOCUMENTS INCORPORATED BY REFERENCE: None.

Explanatory Note

This Amendment No. 2 on Form 10-K/A amends and restates certain disclosure items in our annual report on Form 10-K for the year ended December 31, 2005, which we originally filed on March 16, 2006, as amended by Amendment No. 1 to our annual report on Form 10-K/A, which we filed on March 31, 2006, in response to comments we received on May 19, 2006 from the staff of the Securities and Exchange Commission (“SEC”).

This Form 10-K/A updates disclosure related to material weaknesses in our internal controls over financial reporting in Item 1A “Risk Factors” and Item 9A “Controls and Procedures.” In addition, this Form 10-K/A removes an incorrect reference to Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended under “Forward-Looking Statements.”

Except for the foregoing restated information, the Form 10-K/A continues to describe conditions as of the date of the original filing and we have not updated the disclosures contained herein to reflect events that occurred at a later date. Other events occurring after the original filing or other disclosures necessary to reflect subsequent events have been addressed in reports filed with the SEC subsequent to the date of the original filing. In addition, we have included as exhibits to this amendment new certifications of our Chief Executive Officer and Chief Financial Officer.

MarkWest Energy Partners, L.P.

Form 10-K

Table of Contents

PART I
Item 1.	Business
Item 1A.	Risk Factors
Item 1B.	Unresolved Staff Comments
Item 2.	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
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
MTBE		methyl tertieary butyl ether
Net operating margin (a non-GAAP financial measure)		revenues less purchased product costs
NGLs		natural gas liquids, such as propane, butanes and natural gasoline
NA		not applicable
Tcf		one trillion cubic feet of natural gas

Forward-Looking Statements

Statements included in this annual report on Form 10-K that are not historical facts are forward-looking statements. We use words such as “may,” “believe,” “estimate,” “expect,” “intend,” “project,” “anticipate,” and similar expressions to identify forward-looking statements.

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

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

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

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

• the availability of crude oil refinery runs to feed our Javelina off-gas processing facility;

• the availability of NGLs for our transportation, fractionation and storage services;

• our dependence on certain significant customers, producers, gatherers, treaters, and transporters of natural gas, including MarkWest Hydrocarbon;

• the risks that third-party oil and gas exploration and production activities will not occur or be successful;

• prices of natural gas and NGL products, including the effectiveness of any hedging activities;

• competition from other NGL processors, including m ajor energy companies;

• changes in general economic, market or business conditions in regions where our products are located;

• our ability to identify and complete organic growth projects or acquisitions complementary to our business;

• the success of our risk management policies;

• continued creditworthiness of, and performance by, contract counterparties;

• operational hazards and availability and cost of insurance on our assets and operations;

• the impact of any failure of our information technology systems;

• the impact of current and future laws and government regulations;

• liability for environmental claims;

• damage to facilities and interruption of service due to casualty, weather, mechanical failure or any extended or extraordinary maintenance or inspection that may be required;

• the impact of the departure of any key executive officers; and

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

This list is not necessarily complete. Other unknown or unpredictable factors could also have material adverse effects on future results. The Partnership does not update publicly any forward-looking statement with new information or future events. Investors are cautioned not to put undue reliance on forward-looking statements as many of these factors are beyond our ability to control or predict. You should read “Risk Factors” included in Item 1A of this Form 10-K for further information.

PART I

ITEM 1. BUSINESS

General

MarkWest Energy Partners, L.P. is a publicly traded Delaware limited partnership formed by MarkWest Hydrocarbon, Inc. on January 25, 2002, to acquire most of the assets, liabilities and operations of the MarkWest Hydrocarbon Midstream Business. We are a master limited partnership engaged in the gathering, transportation and processing of natural gas; the transportation, fractionation and storage of NGLs; and the gathering and transportation of crude oil. We are the largest processor of natural gas in the Appalachia region. We also have a large natural gas gathering and transmission business in the southwestern United States, built primarily through acquisitions and investments: Pinnacle Natural Gas, the Lubbock transmission pipeline and the Foss Lake gathering system, all in 2003; the Carthage gathering system in East Texas in July 2004; a non-controlling, 50% interest in Starfish Pipeline Company, LLC and the Javelina entities’ natural gas processing and fractionation facility and pipeline in Corpus Christi, Texas, both in 2005.

MarkWest Energy Partners generates revenues for providing gathering, processing, transportation, fractionation, and storage services. The partnership believes that the largely fee-based nature of its business and the relatively long-term nature of its contracts provide a relatively stable base of cash flows. As a publicly traded partnership, we have access to, and regularly utilize, both equity and debt capital markets as a source of financing, as well as that provided by our credit facility and the ability to use common units in connection with acquisitions. Our limited partnership structure also provides tax advantages to our unitholders.

We conduct our operations in three geographical areas: the Southwest, the Northeast and the Gulf Coast. Our assets and operations in each of these areas are described below.

• Southwest Business Unit

• East Texas. We own the East Texas System, consisting of natural gas-gathering system pipelines, centralized compressor stations, and a natural gas processing facility and NGL pipeline that are currently under construction.

• Western Oklahoma. We own the Foss Lake gathering system and the Arapaho gas-processing plant, located in Roger Mills and Custer counties of western Oklahoma. The gathering portion consists of a pipeline system that is connected to natural gas wells and associated compression facilities.

• Other Southwest. We own 17 natural gas-gathering systems located in Texas, Louisiana, Mississippi and New Mexico, including the Appleby Gathering System in Nacogdoches, Texas. In addition, we own four lateral pipelines in Texas and New Mexico.

• Northeast Business Unit

• Appalachia. We are the largest processor of natural gas in the Appalachian Basin with fully integrated processing, fractionation, storage and marketing operations. Our Appalachian assets include five natural gas-processing plants, an NGL pipeline, an NGL fractionation plant and two caverns for storing propane.

• Michigan. We own and operate a crude oil pipeline in Michigan, which we refer to as the Michigan Crude Pipeline. We also own a natural gas-gathering system and a natural gas-processing plant in Michigan.

• Gulf Coast Business Unit

• Javelina. We own and operate the Javelina Processing Facility, a natural gas processing facility in Corpus Christi, Texas, which processes off-gas from six local refineries. The facility processes approximately 125 to 130 MMcf/d of inlet gas, but is expected to process up to its capacity of 142 MMcf/d as refinery output continues to grow.

Industry Overview, Competition

MarkWest Energy Partners provides services in most areas of the natural gas gathering, processing and fractionation industry. The following diagram illustrates the typical natural gas gathering, processing and fractionation process:

The natural gas gathering process begins with the drilling of wells into gas bearing rock formations. Once 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 has a widely varying composition, depending on the field, the formation reservoir or facility from which it is produced. The principal constituents of natural gas are methane and ethane. 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. It must be gathered, compressed and transported via pipeline to a central facility, and then processed to remove the heavier hydrocarbon components and other contaminants that interfere with pipeline transportation or the end-use of the gas. Our business includes providing these services either for a fee or a percentage of the NGLs removed or gas units processed. The industry as a whole is characterized by regional competition, based on the proximity of gathering systems and processing plants to producing natural gas wells, or to facilities that produce natural gas as a by-product of refining crude oil.

MarkWest Energy also provides processing and fractionation services to crude oil refineries in the Corpus Christi, Texas, area through its Javelina Gas Processing and Fractionation facility. While similar to the natural gas industry diagram outlined above, the following diagram illustrates the significant gas processing and fractionation processes at the Javelina Facility:

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. Raw natural gas from the wellhead is gathered at a processing plant, typically located near the production area, where it is dehydrated and treated, and then processed to recover a mixed NGL stream. In the case of our Javelina facilities, the natural gas inputs to our processing plant are a byproduct of the crude oil refining process.

The removal and separation of individual hydrocarbons by processing is possible because of differences in physical properties. Each component has a distinctive weight, boiling point, vapor pressure and other physical characteristics. Natural gas may also be diluted or contaminated by water, sulfur compounds, carbon dioxide, nitrogen, helium or other components.

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, primarily 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 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. It remains, therefore, in the natural gas stream. Ethane, however, is produced and sold in our East Texas and Oklahoma operations.

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

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

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

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

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 the ability to obtain a satisfactory price for products recovered. Competitive factors affecting our fractionation services include availability of capacity, proximity to supply and industry marketing centers, and cost efficiency and reliability of service. Competition for customers is based primarily on price, delivery capabilities, flexibility, and maintenance of high-quality customer relationships.

Our competitors include:

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

• major integrated oil companies;

• medium and large sized independent exploration and production companies;

• major interstate and intrastate pipelines; and

• a 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 to 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.

We believe our competitive strengths include:

• Strategic and growing position with high-quality assets in the Southwest and the Gulf Coast. Our acquisitions have allowed us to establish and expand our presence in several long-lived natural gas supply basins in the Southwest, particularly in Texas and Oklahoma and the Gulf Coast. Our two acquisitions in 2005 represent a substantial expansion of this strategy by providing direct access to the prolific Gulf Coast region. All of our major acquisitions in these regions have been characterized by several common critical success factors that include:

• an existing strong competitive position;

• access to a significant reserve or customer base with a stable or growing production profile;

• ample opportunities for long-term continued organic growth;

• ready access to markets; and

• close proximity to other acquisition or expansion opportunities.

Specifically, our 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. They also feature new, low-cost gathering systems that provide producers with 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 growing throughput volumes on our East Texas, Appleby, and Western Oklahoma areas of operations. We believe that both Starfish and Javelina, our 2005 acquisitions, will offer similar opportunities in their areas as well.

• Leading position in the Appalachian Basin. We are the largest processor of natural gas in Appalachia. We believe our significant presence and asset base 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.

• Stable cash flows. We believe our numerous fee-based contracts and our active commodity risk management program provide us with stable cash flows. For the year ended December 31, 2005, we generated approximately 49% of our net operating margin from fee-based services. Net operating margin is a non-GAAP financial measure. For a discussion of net operating margin and a reconciliation to income from operations, please see “Our Contracts.” These 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. We also believe that an active commodity risk management program is a significant component of providing stable cash flows as our commodity exposure grows with our expanding operations.

• Common carrier crude oil pipeline in Michigan. We own a common carrier crude oil gathering pipeline in Michigan. Our pipeline receives oil directly from in-state well production and is connected to Enbridge pipeline for transportation to interstate destinations. 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.

• Long-term Contracts. We believe our 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, 2005, approximately 54% of our net operating margin was tied to long-term contracts. In East Texas, approximately 77% of our current gathering volumes as of December 31, 2005, 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 16 and 24 years, respectively. Approximately 45% 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 with remaining terms from 5 to 11 years. In Michigan, our natural gas transportation, treating and processing agreements have remaining terms of 10 to 22 years.

• Experienced management with operational, technical and acquisition expertise. Each member of our executive management team has substantial experience in the energy industry. Our facility managers have extensive experience operating our facilities. Our operational and technical expertise has enabled us to upgrade our existing facilities, as well as to design and build new ones. 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 eight acquisitions. We intend to continue to use our management’s experience and disciplined approach in evaluating and acquiring assets to grow through accretive acquisitions – those acquisitions expected to increase our throughput volumes and cash flow distributable to our unitholders.

• Financial strength and flexibility. During 2005, we issued approximately $100.0 million of equity. Our goal is to maintain a capital structure with approximately equal amounts of debt and equity on a long-term basis.

As of December 31, 2005, we have available borrowing capacity of approximately $74.8 million under our $250.0 million revolving 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.

Our primary business strategy is to grow our business and increase distributable cash flows to our common unitholders, improving financial flexibility and increasing our ability to access capital to fund our growth. We plan to accomplish this through the following:

• Increasing utilization of our facilities. We hope to add to, or provide additional services to, our 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. In the meantime, we continue to develop additional capacity at several of our facilities, which enables us to increase throughput with minimal incremental costs.

• Expanding operations through internal growth projects. By expanding our existing infrastructure and customer relationships, we intend to continue growing in our primary areas of operation to meet the anticipated need for additional midstream services. During 2005, we spent approximately $70.8 million of growth capital to expand several of our gathering and processing operations. Projects included a new 200 MMcf/d gas processing facility and related liquids pipeline in East Texas, initial construction of the Blocker Field gathering system, also in East Texas, as well as compression and gathering capacity to support increasing throughput volumes in the fields associated with our Appleby gathering system in East 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 and on January 1, 2006 the aforementioned East Texas processing facility began operation.

• Expanding operations through strategic acquisitions. We intend to continue pursuing strategic acquisitions of assets and businesses in our existing areas of operation that leverage our current asset base, personnel and customer relationships. During 2005, we spent approximately $398.3 million, including net working capital, to acquire Javelina and $41.7 million to acquire a 50% non-controlling interest in Starfish, two strategic assets in the Gulf Coast region. We will also 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.

The Partnership engages in risk management activities in order to reduce the effect of commodity price volatility related to future sales of natural gas, ethane, propane and crude. It may utilize a combination of fixed-price forward contracts, fixed-for-floating price swaps and options available in the over-the-counter market, and futures contracts traded on the New York Mercantile Exchange. The Partnership monitors these activities through enforcement of our risk management policy (see Item 7A, “Commodity Price Risk”).

To better understand our business and the results of operations discussed in Item 6, “Selected Financial Data” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation,” it is important to have an understanding of three factors:

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

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

• the nature of our relationship with MarkWest Hydrocarbon, Inc.

Our Contracts

We generate substantially all of our revenues and net operating margin (defined as revenues less purchased product costs – see explanation of net operating margin below) from natural gas gathering, processing and transmission; NGL transportation, fractionation and storage; and crude oil gathering and transportation. We have a variety of contract types. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described below.

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

• Percent-of-proceeds arrangements. Under these arrangements, 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 arrangements, our revenues and net operating margins generally increase as natural gas prices and NGL prices increase, and our revenues and net operating margins decrease as natural gas and NGL prices decrease. The most common arrangement is a percent of liquids (or “POL”) contract.

• Percent-of-index arrangements. Under these arrangements, 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. The net operating margins we realize under these arrangements decrease in periods of low natural gas prices, because these net operating margins are based on a percentage of the index price. Conversely, our net operating margins increase during periods of high natural gas prices.

• Keep-whole arrangements. Under these arrangements, we gather natural gas from the producer, process the natural gas to extract NGLs, sell the NGLs to third parties and pay the producer, in the form of processed gas or its cash equivalent, for the full thermal equivalent volume of raw natural gas we received from the producer. Accordingly, our net operating margin is a function of the difference between the value of the extracted NGLs that we sell and the cost of the processed gas that would replace the thermal equivalent value of those NGLs. The profitability of these arrangements is subject not only to the commodity price risk of natural gas and NGLs but also to the price of natural gas relative to the price of NGLs. Our net operating margins increase under these arrangements when the value of NGLs is high relative to the cost of a thermal equivalent amount of natural gas, and our net operating margins decrease when the cost of natural gas is high relative to the value of a thermal equivalent amount of NGLs.

• Settlement margin. Typically, we are allowed to retain a fixed percentage of the volume gathered to cover the compression fuel charges and deemed line losses. When our gathering systems operate more efficiently than specified, per contract allowance, we can retain the difference for our own account.

• Condensate sales. During the gathering process, thermodynamic forces contribute to changes in operating characteristics of the natural gas flowing through the pipeline. As a result, hydrocarbon dew points are reached, causing condensation of hydrocarbons in the high-pressure pipelines. Condensate collected in the system is sold at a monthly crude-oil index-based price, and we keep the proceeds.

The terms of our contracts vary based on gas quality, 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 due to 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 affect our financial results.

At December 31, 2005, our primary exposure to keep-whole contracts was limited to our Arapaho (Oklahoma) processing plant and our East Texas processing contracts. At the Arapaho plant inlet, the Btu content of the natural gas meets the downstream pipeline specification, meaning it does not need to be processed to remove contaminants; 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 small portion of the operating costs of the plant.

Approximately 25% of the gas processed in East Texas for producers was processed under keep-whole terms. Our keep-whole exposure in this area was offset to a great extent because the East Texas agreements provide for the retention of natural gas as a part of the gathering and compression arrangements with all producers on the system. This excess gas helps offset the amount of replacement natural gas purchases required to keep our producers whole on an MMbtu basis, thereby creating a partial natural hedge. The net result is a significant reduction in volatility for these changes in natural gas prices. The remaining volatility for these contracts results from changes in NGL prices. The Partnership has an active commodity risk management program in place to reduce the impacts of changing NGL prices.

Management evaluates contract performance on the basis of net operating margin (a “non-GAAP” financial measure), which is defined as income (loss) from operations, excluding facility expenses, selling, general and administrative expense, depreciation, amortization, impairments and accretion of asset retirement obligations. These charges have been excluded for the purpose of enhancing the understanding, by both management and investors, of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance, for purposes of planning and forecasting future periods. Net operating margin does not have any standardized definition and, therefore, is unlikely to be comparable to similar measures presented by other reporting companies. Net operating margin results should not be evaluated in isolation of, or as a substitute for, our financial results prepared in accordance with United States GAAP. Our usage of net operating margin, and the underlying methodology in excluding certain charges, is not necessarily an indication of the results of operations that may be expected in the future, or that we will not, in fact, incur such charges in future periods. The following reconciles this non-GAAP financial measure to income from operations, the most comparable GAAP financial measure (in thousands):

	December 31,
	2005		2004		2003
Revenues	$	499,084	$	301,314	$	117,430

Purchased product costs	366,878		211,534		70,832

Net operating margin	132,206		89,780		46,598

Facility expenses	47,972		29,911		20,463
Selling, general and administrative expenses	21,573		16,133		8,598
Depreciation	19,534		15,556		7,548
Amortization of intangible assets	9,656		3,640		—
Accretion of asset retirement obligation	159		13		—
Impairments	—		130		1,148
Income from operations	$	33,312	$	24,397	$	8,841

For the year ended December 31, 2005, the following table summarizes the percentages of revenue and net operating margin we generated by types of contracts, exclusive of the impact of commodity derivatives:

	Fee-Based		Percent-of- Proceeds(1)		Percent-of- Index(2)		Keep-Whole(3)		Total
Revenues	13	%	12	%	34	%	41	%	100	%
Net operating margin	49	%	15	%	29	%	7	%	100	%

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

(2) Includes settlement margin, condensate sales and other types of arrangements tied to natural gas prices.

(3) Includes settlement margin, condensate sales and other types of arrangements tied to both NGL and natural gas prices.

Recent Acquisitions

Since our initial public offering, we have completed eight acquisitions for an aggregate purchase price of approximately $794 million, net of working capital. The following table sets forth information regarding each of these acquisitions:

Name	Assets	Location	Consideration (in millions)		Closing Date
Javelina	Gas processing and fractionation facility	Corpus Christi, TX	$	398.3	November 1, 2005

Starfish (1)	Natural gas pipeline, gathering system and dehydration facility	Gulf of Mexico/Southern Louisiana	$	41.7	March 31, 2005

East Texas	Gathering system and gas procession assets	East Texas	$	240.7	July 30, 2004

Hobbs	Natural gas pipeline	New Mexico	$	2.3	April 1, 2004

Michigan Crude Pipeline	Common carrier crude oil pipeline	Michigan	$	21.3	December 18, 2003

Western Oklahoma	Gathering system	Western Oklahoma	$	38.0	December 1, 2003

Lubbock Pipeline	Natural gas pipeline	West Texas	$	12.2	September 2, 2003

Pinnacle	Natural gas pipelines and gathering systems	East Texas	$	39.9	March 28, 2003

(1) Represents a 50% non-controlling interest.

Our Relationship with MarkWest Hydrocarbon, Inc.

We were formed by MarkWest Hydrocarbon to acquire most of its natural gas gathering and processing assets and NGL transportation, fractionation and storage assets. Under a Services Agreement between MarkWest Hydrocarbon and us, MarkWest Hydrocarbon acts in a management capacity, rendering day-to-day operational, business, asset management, accounting, personnel and related administrative services to us. In return, we reimburse MarkWest Hydrocarbon for all expenses incurred on our behalf.

In addition, we entered into various agreements with MarkWest Hydrocarbon in connection with the 2002 closing of our initial public offering. Specifically, we entered into:

•		an Omnibus Agreement Company governing potential competition and indemnification obligations among us and the other parties to the agreement;

•		a Gas Processing Agreement governing our obligations with respect to the processing of natural gas at our Kenova, Boldman and Cobb processing plants;

•		a Pipeline Liquids Transportation Agreement governing our obligations with respect to the transportation of mixed NGLs to our Siloam fractionation facility;

•		a Fractionation, Storage and Loading Agreement governing our obligations with respect to the unloading and fractionation of NGLs and the storage of the NGL products at our Siloam facility; and

•		a Natural Gas Liquids Purchase Agreement which governs our 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.

For a more detailed description of these agreements, please see “Part III, Item 13—Certain Relationships and Related Transactions.”

Segment Reporting

Segments. We have six segments, based on geographic areas of operations, described below. For further information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Our Contracts,” included in Item 7 of this Form 10-K, and “Financial Statements and Supplementary Data,” included in Item 8 of this Form 10-K.

Southwest Business Unit

• East Texas. We own the East Texas System, consisting of natural gas-gathering system pipelines, centralized compressor stations, and a natural gas processing facility and NGL pipeline that are 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 consist of the Cotton Valley, Pettit and Travis Peak formations, which together form one of the largest natural gas-producing regions in the United States. The Carthage Field has an estimated 18 Tcf of remaining recoverable reserves, and cumulative historical production in excess of 12 Tcf.

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

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

Northeast Business Unit

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

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

Gulf Coast Business Unit

• Javelina. On November 1, 2005, we acquired 100% of the equity interests in Javelina Company, Javelina Pipeline Company and Javelina Land Company, L.L.C., which were owned 40%, 40% and 20%, respectively, by subsidiaries of El Paso Corporation, Kerr-McGee Corporation, and Valero Energy Corporation. The Javelina entities own and operate a natural gas processing facility in Corpus Christi, Texas, which treats and processes off-gas from six local refineries. The facility was constructed in 1989 to recover hydrogen and up to 28,000 barrels per day of NGLs, including olefins (ethylene and propylene), ethane, propane, mixed butane and pentanes. The facility processes approximately 125 to 130 MMcf/d of inlet gas, but is expected to process up to its capacity of 142 MMcf/d as refinery output continues to grow.

The following summarizes the percentage of our revenue and net operating margin generated by our assets, by geographic region, for the year ended December 31, 2005:

	East Texas		Oklahoma		Other Southwest		Appalachia		Michigan		Gulf Coast		Total

Revenue	17	%	43	%	21	%	13	%	3	%	3	%	100	%
Net Operating Margin	36	%	15	%	11	%	21	%	7	%	10	%	100	%

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.

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.

In general, the Federal Energy Regulatory Commission (“FERC”) has jurisdiction over natural gas pipelines and operators that provide natural gas pipeline transportation services in interstate commerce. Section 1(b) of the Natural Gas Policy Act (“NGA”), however, exempts natural gas-gathering facilities from the jurisdiction of FERC. We own a number of natural gas pipelines that we have evaluated, and concluded they meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to the agency’s jurisdiction. Additionally, our intrastate natural gas pipeline operations generally are not subject to rate regulation by FERC, although they are regulated by various agencies of the states in which they are located, principally the Texas Railroad Commission, or TRRC.

Our Appalachian pipeline carries NGLs across state lines. The primary shipper on the pipeline is MarkWest Hydrocarbon, which has entered into agreements with us providing for a fixed transportation charge for the term of the agreements. They expire on December 31, 2015. We are the only other shipper on the pipeline. As we neither operate our Appalachian pipeline as a common carrier, nor hold it 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. The likelihood of other entities seeking to utilize our Appalachian pipeline is remote, so it should not be subject to regulation by the FERC in the future. We cannot provide assurance, however, that FERC will not at some point determine that such transportation is within its jurisdiction, or that such an assertion would not adversely affect our results of operations. In such a case, we would be required to file a tariff with FERC and provide a cost justification for the transportation charge. Regardless of any FERC action, however, MarkWest Hydrocarbon has agreed to not challenge the status of our Appalachian pipeline or the transportation charge during the term of our agreements. With respect to the Partnership’s Michigan Crude Pipeline, in response to a shipper inquiry to the Federal Energy Regulatory Commission and following unsuccessful FERC-requested rate structure discussions with the shippers, FERC recently requested that we file a tariff. The Partnership filed a tariff with the agency establishing a cost-of-service rate structure to be effective starting January 1, 2006. Two shippers and a producer protested the filing. The Partnership vigorously defended its tariff, and on December 29, 2005, the Commission rejected the protestors’ request for interim rates and accepted the Partnership’s filing. The new rate structure became effective January 1, 2006. The Commission established hearing procedures for the tariff filing, but held them in abeyance pending the outcome of FERC-sponsored settlement discussions, which the parties now have been referred to under the agency’s procedures. The Partnership cannot predict whether the FERC tariff protest or any settlement will adversely affect its Michigan Crude Pipeline results of operations.

Environmental Matters

General. Our processing and fractionation plants, pipelines, and associated facilities are subject to multiple environmental obligations and potential liabilities under a variety of federal, state and local laws and regulations. These include, 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, and solid and hazardous waste management. Failure to comply with these requirements may expose us to fines, penalties and/or interruptions in our operations that could influence our results of operations. If an accidental leak, spill or release of hazardous substances occurs 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. We could also be required 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 that may have released or disposed of hazardous substances or wastes. Any or all of this could materially affect our results of operations and cash flows.

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. We cannot ensure, however, 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. These arise out of a September 1994 “Administrative Order by Consent for Removal Actions” with EPA Regions II, III, IV, and V; and an “Agreed Order” entered into with the Kentucky Natural Resources and Environmental Protection Cabinet in October 1994. The previous owner/operator has accepted sole liability and responsibility for, and indemnifies 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 lease or purchase of the real property. In addition, the previous owner/operator has agreed to perform all the required response actions at its 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.

Pipeline Safety Regulations

Our pipelines are subject to regulation by the U.S. Department of Transportation (“DOT”) under the Pipeline Safety Act of 1992, as amended (“Pipeline Safety Act”), and the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”), as amended; and the Pipeline Integrity Management (“PIM”) in High Consequence Areas (Gas Transmission Pipelines) amendment to 49 CFR Part 192, effective February 14, 2004, relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The Pipeline Safety Act requires the Research and Special Programs Administration of the DOT to consider environmental impacts, as well as its traditional public safety mandate, when developing pipeline safety regulations. The DOT’s pipeline operator qualification rules require minimum qualification requirements for personnel performing operations and maintenance activities on hazardous liquid pipelines. 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 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. The Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) amendment to 49 CFR Part 192 (PIM) requires operators of gas transmission pipelines to ensure the integrity of their pipelines through hydrostatic pressure testing, the use of in-line inspection tools or through risk-based direct assessment techniques. While we believe that our pipeline operations are in substantial compliance with applicable requirements, due to the possibility of new or amended laws and regulations, or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with the requirements will not have a material adverse effect on our results of operations or financial positions.

On November 8, 2004, a leak and release of vapors occurred in a pipeline transporting NGLs from the Partnership’s Maytown gas processing plant to the Partnership’s Siloam fractionator. This pipeline is owned by a third party, and leased and operated by the Partnership’s 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. Pursuant to a Corrective Action Order issued by the federal Office of Pipeline Safety (“OPS”) on November 18, 2004 and amended November 24, 2004, OPS required pipeline and valve integrity evaluation, testing and repair efforts, which MarkWest successfully completed on the affected pipeline segment. Based on, among other things, the successful integrity testing of the affected pipeline, OPS authorized a partial return to service of the affected pipeline in October 2005. Our partial return to service has allowed us to transport substantially all of the volumes through the pipeline that were being transported prior to the incident. We believe we should be able to satisfy relevant requirements to return to full service and are working with OPS. We anticipate filing a request with OPS in the near future to return to full service.

Employee Safety

The workplaces associated with the processing and storage facilities and the pipelines we operate are also subject to oversight from the federal Occupational Safety and Health Administration, (“OSHA”), as well as comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard-communication standard requires that we maintain information about hazardous materials used or produced in 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, 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. Our general partner, or its affiliates, employs approximately 235 individuals to 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 was renewed on July 11, 2005, for a term of three years. The agreement covers only hourly, non-supervisory employees. We consider labor relations to be satisfactory at this time.

Available Information

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.” You can find more information about us at our Internet website, 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 or furnish such material with the Securities & Exchange Commission.

ITEM 1A. 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 suffer.

Our future growth will depend in part on our ability to integrate our recent acquisitions, as well as our ability to acquire additional assets and businesses at competitive prices. We recently completed the Starfish and Javelina acquisitions, which geographically expanded our operations into offshore and onshore Gulf of Mexico operations. We cannot guarantee that we will successfully integrate these, or any other, acquisitions into our existing operations, or that we will achieve the desired profitability and anticipated results from such acquisitions. Failure to achieve such planned results could adversely affect our financial condition and results of operations.

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

•		operating a significantly larger combined organization and integrating additional midstream operations into our existing operations;
•		difficulties in the assimilation of the assets and operations of the acquired businesses, especially if the assets acquired are in a new business segment or geographical area;
•		the loss of customers or key employees from the acquired businesses;
•		the diversion of management’s attention from other existing business concerns;

• the failure to realize expected synergies and cost savings;

• coordinating geographically disparate organizations, systems and facilities;

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

• consolidating corporate and administrative functions.

Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Following an acquisition, we may discover previously unknown liabilities 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. If so, our operation of these new assets could cause us to incur increased costs to attain or maintain compliance with such requirements. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

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

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

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

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

We have substantial indebtedness and other financial obligations.

Subject to the restrictions governing our indebtedness and other financial obligations, and the indenture governing our outstanding notes, we may incur significant additional indebtedness and other financial obligations.

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

•		make it more difficult for us to satisfy our obligations with respect to our existing debt;

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

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

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

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

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

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

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

Our profitability depends on the volume of natural gas we gather, transmit and process, and NGLs we transport and fractionate at our facilities. A decrease in natural gas or refinery off-gas supplies 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 facilities for fractionation, storage, transportation and sale. This would 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 our areas of operations, the amount of reserves underlying the wells and the rate at which production from a well declines. 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 a reduction of the amount of natural gas we gather, transmit and process, and the amount of NGLs we transport and fractionate. Over time, as the current wells exhaust, this could cause us to abandon our gathering systems and, possibly, cease gathering operations. As a consequence of such declines, our revenues would drop.

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

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

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

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

The fees charged to third parties under our gathering, processing, transmission, transportation, fractionation and

storage agreements may not escalate sufficiently to cover increases in costs. The agreements may not be renewed or may be suspended in some circumstances.

Our costs may increase at a rate greater than the fees we charge to third parties. Furthermore, third parties may not renew their contracts with us. Additionally, some third parties’ obligations under their agreements with us may be permanently or temporarily reduced due to certain events, some of which are beyond our control, including force majeure events wherein the supply of either natural gas, NGLs or crude oil are curtailed or cut off. Force majeure events include (but are not limited to): revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of equipment or 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 suffer.

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 diligent in attempting to ensure that we issue credit to only credit-worthy customers. Even if our credit review and analysis mechanisms work properly, however, we may experience losses in dealing with operators and other parties. 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 gatherers, processors, pipelines, fractionators, and the price of, and demand for, natural gas, NGLs and crude oil in the markets we serve. Our competitors include large oil, natural gas, refining and petrochemical companies, some of which have greater financial resources, more numerous or greater capacity pipelines, processing and other facilities, and greater access to natural gas and NGL supplies than we do. Additionally, our customers that gather gas through facilities that are not otherwise dedicated to us may develop their own processing and fractionation facilities in lieu of using our services. Certain of our competitors may also have advantages in competing for acquisitions, or other new business opportunities, because of their financial resources and synergies in operations.

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

Our profitability is affected by the volatility of 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 products and natural gas prices have been volatile 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;

• demand for natural gas and NGL products in localized markets;

• imports of crude oil, natural gas and NGLs;

• seasonality;

• the condition of the U.S. economy;

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

• domestic government regulation, legislation and policies.

Our net operating margins under many of our various types of commodity-based contracts are directly affected by changes in NGL product prices and natural gas prices, thus are more sensitive to volatility in commodity prices than our fee-based contracts. Additionally, our purchase and resale of gas in the ordinary course of business exposes us to significant risk of volatility in gas prices due to the potential difference in the time of the purchases and sales, and the existence of a difference in the gas price associated with each transaction. Finally, changes in natural gas prices may indirectly affect 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.

Our commodity derivative activities may reduce our earnings, profitability and cash flows.

Our operations expose us to fluctuations in commodity prices. We utilize derivative financial instruments related to the future price of crude oil, natural gas and certain NGLs with the intent of reducing volatility in our cash flows due to fluctuations in commodity prices.

We account for derivative instruments in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities. The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. We have a policy to enter into derivative transactions related to only a portion of the volume of our expected production or fuel requirements and, as a result, we will continue to have direct commodity price exposure to the unhedged portion. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk.” Our actual future production or fuel requirements may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our hedging activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our hedging policies and procedures are not properly followed. It is possible that the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

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

As we discuss in our Managements Report on Internal Control over Financial Reporting in Part II, Item 9A, “Controls and Procedures” of this Form 10-K we have identified, and the audit report on management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting of Deloitte & Touche LLP as of December 31, 2005 confirmed the presence of, material weaknesses in our internal controls over financial reporting. In particular, our control environment did not sufficiently promote effective internal control over financial reporting through the management structure to prevent a material misstatement. Furthermore, we did not have adequate internal controls and processes in place to allow independent validation of data or control and review of our management’s assertions with respect to the completeness, accuracy and validity of commodity derivative transactions.

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

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

We are fully committed to remediating the material weaknesses described above, and we believe that we are taking the steps that will properly address these issues. Further, our Audit Committee has been and expects to remain actively involved in the remediation planning and implementation. However, the remediation of the design of the deficient controls and the associated testing efforts are not complete, and further remediation may be required. While we are taking immediate steps and dedicating substantial resources to correct these material weaknesses, they will not be considered remediated until the new and improved internal controls operate for a period of time, are tested and are found to be operating effectively. Pending the successful completion of such testing and the hiring of additional personnel, we will perform mitigating procedures. If we fail to remediate any material weaknesses, we could be unable to provide timely and reliable financial information, which could have a material adverse effect on our business, results of operations or financial condition.

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

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

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

•		inadvertent damage from construction and farm equipment;

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

•		fires and explosions; and

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

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

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

Some of our gas, liquids and crude oil transmission operations are subject to rate and service regulations under FERC or various state regulatory bodies, depending upon jurisdiction. FERC generally regulates the transportation of natural gas and oil in interstate commerce, and FERC’s regulatory authority includes: facilities construction, acquisition, extension or abandonment of services or facilities; accounts and records; and depreciation and amortization policies. Intrastate natural gas pipeline operations are generally not subject to regulation by FERC, and the Natural Gas Act (“NGA”) specifically exempts some gathering systems. Yet such operations may still be subject to regulation by various state agencies. The applicable statutes and regulations generally require that our rates and terms and conditions of service provide no more than a fair return on the aggregate value of the facilities used to render services. FERC rate cases can involve complex and expensive proceedings. For more information regarding regulatory matters that could affect our business, please see Item 1, Regulatory Matters.

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

Columbia Gas is the previous or current owner of the property on which our Kenova, Boldman, Cobb and Kermit facilities are located and is the previous operator of our Boldman and Cobb facilities. Columbia Gas has been or is currently involved in investigatory or remedial activities with respect to the real property underlying the Boldman and Cobb facilities pursuant to an “Administrative Order by Consent for Removal Actions” entered into by Columbia Gas and the U.S. Environmental Protection Agency and, in the case of the Boldman facility, an “Agreed Order” with the Kentucky Natural Resources and Environmental Protection Cabinet.

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

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

Numerous governmental agencies enforce complex and stringent laws and regulations on a wide range of environmental, safety and other regulatory matters. We could be adversely affected by increased costs due to stricter pollution-control requirements or liabilities resulting from non-compliance with operating or other regulatory permits. New environmental laws and regulations might adversely influence our products and activities. Federal, state and local agencies also could impose additional safety requirements, any of which could affect our profitability. In addition, we face the risk of accidental releases or spills associated with our operations. These could result in material costs and liabilities, including those relating to claims for damages to property and persons. Our failure to comply with environmental or safety-related laws and regulations could result in administrative, civil and criminal penalties, the imposition of investigatory and remedial obligations and even injunctions that restrict or prohibit our operations. For more information regarding the environmental, safety and other regulatory matters that could affect our business, please see Item 1, Regulatory Matters, Environmental Matters, and Pipeline Safety Regulations.

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

All of the natural gas we process, gather and transmit is delivered into pipelines for further delivery to end-users. If these pipelines cannot, or will not, accept delivery of the gas due to downstream constraints on the pipeline, we will be forced to limit or stop the flow of gas through our pipelines and processing systems. In addition, interruption of pipeline service upstream of our processing facilities would likewise limit or stop flow through our processing facilities. Likewise, if the pipelines into which we deliver crude oil are interrupted, we will be limited in, or prevented from conducting, our crude oil transportation operations. Any number of factors beyond our control could cause such interruptions or constraints on pipeline service, including necessary and scheduled maintenance, or unexpected damage to the pipeline. Because our revenues and net operating margins depend upon (1) the volumes of natural gas we process, gather and transmit, (2) the throughput of NGLs through our transportation, fractionation and storage facilities and (3) the volume of crude oil we gather and transport, any reduction of volumes could result in a material reduction in our net operating margin.

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

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

• unscheduled turnarounds or catastrophic events at our physical plants;

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

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

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

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

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

Our operations require skilled and experienced laborers with proficiency in multiple tasks. In recent years, a shortage of workers trained in various skills associated with the midstream energy business has caused us to conduct certain operations without full staff, which decreases our productivity and increases our costs. This shortage of trained workers is the result of the previous generation’s experienced workers reaching the age for retirement, combined with the difficulty of attracting new laborers to the midstream energy industry. Thus, this shortage of skilled labor could continue over an extended period. If the shortage of experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our products and services, which could adversely affect our profitability.

Risks Related to Our Partnership Structure

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

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

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

MarkWest Hydrocarbon and its affiliates own and control our general partner. MarkWest Hydrocarbon and its affiliates also own a significant limited partner interest in us. A number of officers and employees of MarkWest Hydrocarbon and our general partner also own interests in the Partnership. Conflicts of interest may arise between MarkWest Hydrocarbon and its affiliates, including our general partner and the Partnership. 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 the Partnership or utilizes the Partnership’s assets for processing, transportation or fractionation services we provide. MarkWest Hydrocarbon’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of MarkWest Hydrocarbon.

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

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

• Our general partner controls the enforcement of obligations owed to the Partnership 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 the Partnership.

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

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

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.

• 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 unitholders by prematurely eliminating their contractual right to distributions over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

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

Unitholders’ voting rights are restricted by the Partnership Agreement provision. It states that any units held by a person who owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their

transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be voted on any matter. In addition, the Partnership Agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

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

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

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

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

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

Our Partnership Agreement contains provisions that 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 hold common units, 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.

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

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

• the conversion of subordinated units into common units;

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

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

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

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

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

• our unitholders’ proportionate ownership interest in the Partnership 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 the Partnership, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units.

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

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

Our general partner usually has unlimited liability for 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

The locations, approximate capacity, and throughput of our gas-processing plants as of and for the year ended December 31, 2005, are as follows:

Gas Processing Facilities:

			Design	Year Ended December 31, 2005
Facility	Location	Year of Initial Construction	Throughput Capacity (Mcf/d)	Natural Gas Throughput (Mcf/d)	Utilization of Design Capacity		NGL Throughput (gal/day)
East Texas:
East Texas processing plant	Panola, County, TX	2005	200,000	NA	NA		NA

Western Oklahoma:
Arapaho processing plant	Custer County, OK	2000	90,000	76,000	84	%	167,000

Appalachia:
Kenova Processing Plant (1)	Wayne County, WV	1996	160,000	131,000	82	%	NA
Boldman Processing Plant (1)	Pike County, KY	1991	70,000	43,000	61	%	NA
Maytown Processing Plant	Floyd County, KY	2000	55,000	63,000	115	%	NA
Cobb Processing Plant	Kanawha County, WV	2005	25,000	24,000	96	%	NA
Kermit Processing Plant (2)	Mingo County, WV	2001	32,000	NA	NA		NA

Michigan:
Fisk Processing Plant	Manistee County, MI	1998	35,000	6,600	19	%	16,000

Gulf Coast:
Javelina processing plant (3)	Corpus Christi, TX	1989	142,000	102,000	72	%	22,100

(1) A portion of the gas processed at Maytown and Boldman plants, and all of the gas processed at Kermit plant, is further processed at Kenova plant to recover additional NGLs.

(2) The Kermit processing plant is operated by a third party solely to prevent liquids from condensing in the gathering and transmission pipelines upstream of our Kenova plant. We do not receive Kermit gas volume information but do receive all of the liquids produced at the Kermit facility.

(3) We acquired the Javelina processing plant on November 1, 2005.

The location, approximate capacity, and throughput of our fractionation facility as of and for the year ended December 31, 2005, is as follows:

Fractionation Facility:

				Year Ended December 31, 2005
Facility	Location	Year of Initial Construction	Design Throughput Capacity (gal/d)	NGL Throughput (gal/day)	Utilization of Design Capacity
Appalachia:
Siloam fractionation plant	South Shore, KY	1957	600,000	430,000	72	%

The name, approximate length in miles, geographical location, and throughput of our pipelines as of and for the year ended December 31, 2005, are as follows:

Natural Gas Pipelines:

				Design	Year Ended December 31, 2005
Facility	Location	Miles	Year of Initial Construction	Throughput Capacity (Mcf/d)	Natural Gas Throughput (Mcf/d)	Utilization of Design Capacity		NGL Throughput (gal/day)
East Texas:
East Texas gathering system	Panola County, TX	311	1990	350,000	321,000	92	%	NA

Western Oklahoma:
Foss Lake Gathering System	Roger Mills and Custer County, OK	240	1998	90,000	76,000	84	%	NA

Other Southwest:
Appleby Gathering System	Nacogdoches County, TX	139	1990	40,000	33,000	83	%	NA
Other Gathering Systems (4)			Various	52,570	16,500	31	%	NA

Michigan:
90-mile Gas Gathering Pipeline	Manistee, Mason and Oceana Counties, MI	90	1994–1998	35,000	6,600	19	%	15,600

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

NGL Pipelines:

				Design	Year Ended December 31, 2005
Pipeline	Location	Miles	Year of Initial Construction	Throughput Capacity (gal/day)	NGL Throughput (gal/day)	Utilization of Design Capacity
Appalachia:
Maytown to Institute (5)	Floyd County, KY to Kanawha County, WV	100	1956	250,000	120,000	48	%
Ranger to Kenova (6)	Lincoln County, WV to Wayne County, WV	40	1976	831,000	120,000	14	%
Kenova to Siloam	Wayne County, WV to South Shore, KY	40	1957	831,000	273,000	33	%

East Texas:
E. Texas Liquidline	Panola County, Texas	37.5	2005	630,000	—	NA

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

(6) NGLs transported through the Ranger to Kenova pipeline are combined with NGLs recovered at the Kenova facility and the combined NGL stream is transported in the Kenova to Siloam pipeline to Siloam.

Michigan Crude Pipeline :

Year Ended December 31, 2005

Pipeline

Location

Miles

Design
Throughput
Capacity (gal/day)

NGL
Throughput
(gal/day)

Utilization of
Design Capacity

Michigan:

Michigan Crude Pipeline

Manistee County, MI to Crawford County, MI

150

60,000

14,200

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 determined necessary, permits, leases, license agreements and franchise ordinances from public authorities to cross over or under, or to lay facilities in or along water courses, county roads, municipal streets and state highways, as applicable. We also have obtained easements and license agreements from railroad companies to cross over or under railroad properties or rights-of-way. Many of these authorizations and grants are revocable at the election of the grantor. In some cases, property on which our pipelines were built was purchased in fee or held under long-term leases. 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. We believe that we have obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business. We also believe we have satisfactory title or other right to all of our material land assets. Title to these properties is subject to encumbrances in some cases; however, we believe that none of these burdens will materially detract from the value of these properties or from our interest in these properties, or will materially interfere with their use in the operation of our business.

We have pledged substantially all of its assets to secure the debt of our subsidiary, MarkWest Energy Operating Company, L.L.C. (the “Operating Company”), as discussed in Note 10 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

ITEM 3. LEGAL PROCEEDINGS

MarkWest Energy Partners, in the ordinary course of business, is subject to a variety of risks and disputes normally incident to its business, a defendant in various lawsuits and a party to various other legal proceedings. We maintain insurance policies with insurers in amounts and with coverage and deductibles as we believe are reasonable and prudent. We cannot assure, however, that the insurance companies will promptly honor their policy obligations or that the coverage or levels of insurance will be adequate to protect us from all material expenses related to potential future claims for property loss or business interruption to the Partnership or for third party claims of personal and property damage, or that the coverage or levels of insurance it presently has will be available in the future at economical prices.

In early 2005, the Partnership and several of its affiliates were served with two lawsuits, Ricky J. Conn, et al. v. MarkWest Hydrocarbon, Inc. et al .(filed February 7, 2005),. and Charles C. Reid, et al. v. MarkWest Hydrocarbon, Inc. et al., (filed February 8, 2005), presently removed to and under the jurisdiction of the U.S. District Court for the Eastern District of Kentucky, Pikeville Division. The Partnership was served with an additional lawsuit, Community Trust and Investment Co., et al. v. MarkWest Hydrocarbon, Inc. et al., filed November 7, 2005 in Floyd County Circuit Court, Kentucky, that added five new claimants but essentially alleged the same facts and claims as the earlier two suits. These actions are for third-party claims of property and personal injury damages sustained as a consequence of an NGL pipeline leak and an ensuing explosion and fire that occurred on November 8, 2004. The pipeline was owned by an unrelated business entity and leased and operated by the Partnership’s subsidiary, MarkWest Energy Appalachia, LLC. It transports NGLs from the Maytown gas processing plant to the Partnership’s Siloam fractionator. The fire from the leaked vapors resulted in property damage to five homes and injuries to some of the residents. The pipeline owner, the U.S. Department of Transportation, Office of Pipeline Safety (“OPS”), and the Partnership continue to investigate the incident.

The Partnership notified its general liability insurance carriers of the incident and of the filed Kentucky actions in a timely manner and is coordinating the defense of these third-party lawsuits with the insurers. At this time, the Partnership believes that it has adequate general liability insurance coverage for third-party property damage and personal injury liability resulting from the incident. To date, the Partnership has settled with several of the claimants for third-party property damage claims (damage to residences and personal property), in addition to reaching settlement for some of the personal injury claims. These settlements have been paid for or reimbursed under the Partnership’s general liability insurance. As a result, the Partnership has not provided for a loss contingency.

Pursuant to OPS regulation mandates and to a Corrective Action Order issued by the OPS on November 18, 2004, pipeline and valve integrity evaluation, testing and repairs were conducted on the affected pipeline segment before service could be resumed. Based on, among other things, the successful integrity testing of the affected pipeline, OPS authorized a partial return to service of the affected pipeline in October 2005. MarkWest is currently preparing its application for return to full service.

The Partnership has filed an independent action captioned MarkWest Hydrocarbon, Inc., et al. v. Liberty Mutual Ins. Co., et al. (District Court, Arapahoe County, Colorado, Case No. 05CV3953 filed August 12, 2005)), as removed to the U.S. District Court for the District of Colorado, Civil Action No. 1:05-CV-1948, on October 7, 2005), against its All-Risks Property and Business Interruption insurance carriers as a result of the insurance companies’ refusal to honor their insurance coverage obligation to pay the Partnership for certain expenses. These include the Partnership’s internal expenses and costs incurred for damage to, and loss of use of the pipeline, equipment, products, the extra transportation costs incurred for transporting the liquids while the pipeline was out of service, the reduced volumes of liquids that could be processed, and the costs of complying with the OPS Corrective Action Order (hydrostatic testing, repair/replacement and other pipeline integrity assurance measures). These expenses and costs have been expensed as incurred and any potential recovery from the All-Risks Property and Business Interruption insurance carriers will be treated as “other income” if and when they are received. The Partnership has not provided for a receivable for these claims because of the uncertainty as to whether and how much the Partnership will ultimately recover under these policies. The Partnership has also asserted that the cost of pipeline testing,

replacement and repair are subject to an equitable sharing arrangement with the pipeline owner, pursuant to the terms of the pipeline lease agreement.

On September 27, 2005, a lawsuit captioned C.F. Qualia Operating, Inc. v. MarkWest Pinnacle, L.P., (District Court of Midland, Texas, 385^th Judicial District, Case No. CV-45188), was served on a Partnership subsidiary, MarkWest Pinnacle, L.P., alleging breach of contract, conversion, fraud and breach of implied duty of good faith with respect to a dispute on volumes of gas purchased by the Partnership under a gas purchase agreement. Under the gas purchase agreement, MarkWest Energy Partners paid the Plaintiff based on volumes of gas measured at the wellhead (delivery point). Plaintiff claims that it is entitled to a prorated portion of any system gain, i.e., that is to be paid for more gas than it actually sold and delivered to the Partnership. MarkWest Energy Partners has filed an Answer to the Complaint denying Plaintiff’s allegations and has asserted a counter-claim for declaratory judgment on the contract terms as being clear and unambiguous as to payment being limited to those measured at the wellhead, that Plaintiff’s claims are without merit, and that MarkWest also may have overpaid Plaintiff based on, among other things, the wet versus dry Btu measurements. Discovery has just begun, and at this time, the Partnership is not able to predict the ultimate outcome of this matter. As a result, the Partnership has not provided for a loss contingency.

The Partnership acquired the Javelina gas processing, transportation and fractionation business located in Corpus Christi, Texas (the “Javelina Business”) on November 1, 2005. The Javelina Business was a party with numerous other defendants to four lawsuits brought by plaintiffs who had residences or businesses located near the Corpus Christi industrial area, an area which included the Javelina gas processing plant, and several petroleum, petrochemical and metal processing and refining operations. These suits, styled Victor Huff v. ASARCO Incorporated, et al. (Cause No. 98-01057-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in March 3, 1998); Hipolito Gonzales et al. v. ASARCO Incorporated, et al., (Cause No. 98-1055-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in 1998); Jason and Dianne Gutierrez, individually and as representative of the estate of Sarina Galan Gutierrez (Cause No. 05-2470-A, 28^TH Judicial District, severed May 18, 2005, from Gonzales v. Asarco Incorporated, above); and Jesus Villarreal v. Koch Refining Co. et al., (Cause No. 05-01977-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed April 27, 2005) set forth claims for personal injury or property damage, harm to business operations and nuisance type claims, allegedly incurred as a result of operations and emissions from the various industrial operations in the area. The Hipolito Gonzales action is subject to a settlement in principle reached in a mediation held December 9, 2005. The Partnership’s involvement and engagement in the other cases has been limited to this point, but the actions have been and are being vigorously defended and, based on initial evaluation and consultations, it appears at this time that these actions should not have a material impact on the Partnership.

In response to a shipper inquiry to the Federal Energy Regulatory Commission (“FERC”) regarding the Partnership’s Michigan Crude Pipeline, and following unsuccessful FERC-requested rate structure discussions with the shippers, FERC recently requested that we file a tariff. The Partnership filed on November 18, 2005 a tariff with FERC establishing a cost of service rate structure to be effective starting January 1, 2006. Two shippers and a producer filed a joint protest to the FERC filing with the Commission, and the Partnership filed a response to this joint protest vigorously defending its filing and opposing the protest. The Commission issued an order on December 29, 2005, rejecting the protestor’s request for interim rates and accepting the Partnership’s filing, and the new rates and rate structure became effective January 1, 2006. The Commission established hearing procedures for the tariff filing, but held them in abeyance pending the outcome of FERC sponsored settlement discussions, which the parties have been referred to under the FERC procedures. The Partnership and the shippers subsequently negotiated a settlement, that resulted in the Partnership filing a new tariff which, for the most part, returns the rates to those in effect prior to the effective date of the November 18, 2005 tariff filing, and established such rates for a prospective three year period.

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, 2005.

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 2005 and 2004.

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

December 31, 2005	$	50.95	$			42.01	$	0.82		$	0.82		February 8, 2006	February 14, 2006
September 30, 2005	$	53.50	$			47.18	$	0.82		$	0.82		November 8, 2005	November 14, 2005
June 30, 2005	$	51.54	$		46.51		$		0.80	$		0.80	August 9, 2005	August 15, 2005
March 31, 2005	$	52.50	$		45.25		$		0.80	$		0.80	May 10, 2005	May 16, 2005

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

As of December 31, 2005, there were approximately 151 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. Pursuant to the terms of the partnership agreement, 1,200,000 of these units were converted into common units during 2005. 1,800,000 subordinated units were outstanding as of December 31, 2005. There were 2 holders of record of our subordinated units as of December 31, 2005.

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 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 currently 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 are 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. A portion of the subordinated units, however, 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, 1,200,000 subordinated units converted into common units, 600,000 on August 15, 2005, and an additional 600,000 on November 15, 2005.

ITEM 6. SELECTED FINANCIAL DATA

On May 24, 2002, the Partnership completed its initial public offering and, thereafter, became the successor to MarkWest Hydrocarbon Midstream Business (“Midstream Business”). The selected financial information for the Partnership was derived from the audited consolidated financial statements as of and for the years ended December 31, 2005, 2004 and 2003. The selected financial information for the Partnership for the year ended December 31, 2002, is derived from audited consolidated and combined financial statements of the Partnership and the Midstream Business. The selected historical financial information of the Midstream Business, as of and for the years ended December 31, 2001, is 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.”

	Partnership												MarkWest Hydrocarbon Midstream Business
	Year Ended December 31,
	2005			2004			2003			2002			2001
	(1)			(2)			(3)
	(in thousands, except per unit amounts)

Statement of Operations:
Revenues	$	499,084		$	301,314		$	117,430		$	70,246		$	93,675
Operating expenses:
Purchased product costs	366,878			211,534			70,832			38,906			65,483
Facility expenses	47,972			29,911			20,463			15,101			13,138
Selling, general and administrative expenses	21,573			16,133			8,598			5,411			5,047
Depreciation	19,534			15,556			7,548			4,980			4,490
Amortization of intangible assets	9,656			3,640			—			—			—
Impairments	—			130			1,148			—			—
Accretion of asset retirement obligation	159			13			—			—			—
Total operating expenses	465,772			276,917			108,589			64,398			88,158
Income from operations	33,312			24,397			8,841			5,848			5,517
Interest income	367			87			14			5			—
Interest expense	(22,469		)	(9,236		)	(3,087		)	(1,128		)	(1,307		)
Loss from unconsolidated affiliates	(2,153		)	(65		)	—			—			—
Amortization of deferred financing costs	(6,780		)	(5,236		)	(984		)	(291		)	—
Miscellaneous income (expense)	78			15			(25		)	52			—
Income before income taxes	2,355			9,962			4,759			4,486			4,210
Provision (benefit) for income taxes	—			—			—			(17,175		)	1,624
Net income	$	2,355		$	9,962		$	4,759		$	21,661		$	2,586
Net income per limited partner unit:
Basic	$	0.02		$	1.31		$	0.95		$	4.86		$	0.86
Diluted	$	0.02		$	1.31		$	0.94		$	4.83		$	0.86
Cash distributions declared per limited partner unit	$	3.28		$	2.97		$	2.47		$	1.23		NA

Balance Sheet Data (at December 31):
Working capital	$	11,944		$	10,547		$	2,457		$	1,762		$	18,240
Property, plant and equipment, net	492,961			280,635			184,214			79,824			82,008
Total assets	1,046,093			529,422			212,871			87,709			104,891
Total long-term debt	601,262			225,000			126,200			21,400			19,179
Partners’ capital	307,175			241,142			64,944			60,863			65,429

Cash Flow Data:
Net cash flow provided by (used in):
Operating activities	$	42,090		$	42,275		$	21,229		$	33,502		$	(524	)
Investing activities	(469,308		)	(273,176		)	(112,893		)	(2,056		)	(8,997		)
Financing activities	423,060			246,411			97,641			(28,670		)	9,521

Other Financial Data:
Sustaining capital expenditures (4)	$	2,181		$	1,163		$	1,041		$	511		$	576
Expansion capital expenditures(4)	68,569			29,304			1,903			1,634			9,075
Total capital expenditures	$	70,750		$	30,467		$	2,944		$	2,145		$	9,651

(1) We completed our investment in Starfish on March 31, 2005, and acquired Javelina (Gulf Coast) on November 1, 2005.

(2) We acquired our East Texas System in late July 2004.

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

We acquired our Arapaho processing plant in December 2003.

We acquired our Pinnacle gathering systems in late March 2003.

We acquired our Lubbock pipeline (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.

We acquired our Michigan Crude Pipeline in December 2003.

(4) 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

	Partnership				MarkWest Hydrocarbon Midstream Business
	Year Ended December 31,
	2005	2004	2003	2002	2001
	(1)	(2)	(3)

Operating Data:
*Southwest:*
East Texas
Gathering systems throughput (Mcf/d)	321,000	259,300	NA	NA	NA
NGL product sales (gallons)	126,476,000	41,478,000	NA	NA	NA

Oklahoma
Foss Lake gathering systems throughput (Mcf/d)	75,800	60,900	57,000	NA	NA
Arapaho NGL product sales (gallons)	60,903,000	45,273,000	2,910,000	NA	NA

Other
Appleby gathering systems throughput (Mcf/d)	33,400	27,100	23,800	NA	NA
Other gathering systems throughput (Mcf/d)	16,500	17,000	20,500	NA	NA
Lateral throughput volumes (Mcf/d)	81,000	75,500	32,100	NA	NA

*Appalachia:*
Natural gas processed for a fee (Mcf/d)	197,000	203,000	202,000	202,000	192,000
NGLs fractionated for a fee (Gal/day)	430,000	475,000	458,000	476,000	423,000
NGL product sales (gallons)	41,700,000	42,105,000	40,305,000	38,813,000	—

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

*Gulf Coast:*
Natural gas processed for a fee (Mcf/d)	115,000	NA	NA	NA	NA
NGLs fractionated for a fee (Gal/day)	19,400	NA	NA	NA	NA

(1) – (3) See footnotes above.

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

Management’s Discussion and Analysis (“MD&A”) contains statements that are forward-looking and should be read in conjunction with “Selected Consolidated Financial Data” and our consolidated financial statements and accompanying notes included elsewhere in this report. These statements are based on current expectations and assumptions that are subject to risks and uncertainties. Actual results could differ materially from those expressed or implied in the forward-looking statements as a result of a number of factors.

Overview

We reported net income of $2.4 million for the year ended December 31, 2005, or $0.02 per diluted limited partner unit, compared to net income of $10.0 million, or $1.31 per diluted limited partner unit, for the year ended December 31, 2004.

This decrease in net income compared to 2004 was primarily attributed to:

• Expenses incurred in our testing and repair program on the Appalachian Liquids Pipeline System (“ALPS”), as well as additional trucking costs for moving product while the line was out of service, which was approximately $5.9 million higher than 2004.

• Decreased liquids fractionation in Appalachia, primarily due to ALPS being out of service and upstream interruptible customer curtailments in 2005.

• Increased SG&A expense related to ongoing audit and compliance requirements and non-cash compensation expense.

• Reduced throughput volumes on our systems in Michigan.

• Higher interest expense related to increased borrowing to fund acquisitions.

These items were partially offset by the following:

• Improved gathering volumes on our Carthage, Appleby and Western Oklahoma systems compared to the prior year.

• Improved processing margins relative to the prior year.

• Higher NGL and gas prices on our equity gallons and volumes.

On January 25, 2006, the board of directors of the general partner of the Partnership declared the Partnership’s quarterly cash distribution of $0.82 per unit for the fourth quarter of 2005. The fourth quarter distribution was paid on February 14, 2006, to unitholders of record on February 8, 2006.

Impact of Recent Acquisitions on Comparability of Financial Results

In reviewing our historical results of operations, you should be aware of the impact of our recent acquisitions, which fundamentally affect the comparability of our results of operations over the periods discussed.

Since our initial public offering, we have completed eight acquisitions for an aggregate purchase price of $794.4 million, net of working capital. Four of these acquisitions occurred in 2003 and their results are included in the results of operations from the acquisition date.

• The Pinnacle acquisition closed on March 28, 2003, for consideration of $39.9 million.

• The Lubbock pipeline acquisition (also known as the Power-Tex Lateral pipeline) closed September 2, 2003, for consideration of $12.2 million.

• The Western Oklahoma acquisition closed December 1, 2003, for consideration of $38.0 million.

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

Two acquisitions occurred in 2004 and their results are included in the results of operations from the acquisition date.

• The Hobbs acquisition closed April 1, 2004, for consideration of $2.3 million. As a result, only nine months of activity for Hobbs is reflected in the results of operations for the year ended December 31, 2004.

• The East Texas acquisition closed on July 30, 2004, for consideration of $240.7 million, so only five months of activity for East Texas is reflected in the results of operations for the year ended December 31, 2004.

Two acquisitions occurred in 2005 and are included in the results of operations from the acquisition date.

• The Starfish acquisition closed on March 31, 2005, for consideration of $41.7 million. As a result, the acquisition is not reflected in our results of operations in 2004. Nine months of Starfish activity is reflected in results of operations for the year ended December 31, 2005.

• The Javelina acquisition closed on November 1, 2005, for consideration of $357.0 million, plus $41.3 million for net working capital. As a result, only two months of activity for Javelina is reflected in the results of operations for the year ended December 31, 2005.

Our Relationship with MarkWest Hydrocarbon, Inc.

We were formed by MarkWest Hydrocarbon to acquire most of its natural gas gathering and processing assets, and NGL transportation, fractionation and storage assets. MarkWest Hydrocarbon remains one of our largest customers. For the year ended December 31, 2005, it accounted for 13% of our revenues and 20% of our net operating margin. This represents a decrease from the year ended December 31, 2004, when MarkWest Hydrocarbon accounted for 20% of our revenues and 32% of our net operating margin. We expect to continue deriving a significant portion of our revenues from the services we provide under our contracts with MarkWest Hydrocarbon for the foreseeable future; however, as our other operations grow, the relative contribution from MarkWest Hydrocarbon will continue to decline. At December 31, 2005, MarkWest Hydrocarbon and its subsidiaries, in the aggregate, owned a 21% interest in the Partnership, consisting of 1,633,334 subordinated limited partner units, which represents a 12% interest in the Partnership; 836,162 common partner units, which represents 7% interest; and 89% of the general partner, which owns a 2% interest in the Partnership and associated incentive distribution rights.

Under a Services Agreement, MarkWest Hydrocarbon acts in a management capacity rendering day-to-day operational, business and asset management, accounting, personnel and related administrative services to the Partnership. In return, the Partnership reimburses MarkWest Hydrocarbon for all expenses incurred on behalf of the Partnership.

Results of Operations

Segment Reporting

Our six geographical segments are: East Texas, Oklahoma, Other Southwest, Gulf Coast, Appalachia and Michigan. We capture information in this MD&A by geographical segment, except that certain items below the “Operating Income” line are not allocated to our business segments because management does not consider them in its evaluation of business unit performance. In addition, selling, general and administrative expenses are not allocated to individual business segments since management evaluates each business segment based on operating income before selling, general and administrative expenses. The segment information appearing in Note 18 to the consolidated financial statements, Segment Information, is presented on a basis consistent with the Partnership’s internal management reporting, in accordance with SFAS No. 131, Disclosure about Segments of an Enterprise and Related Information.

Year Ended December 31, 2005, Compared to Year Ended December 31, 2004

East Texas

	Year Ended December 31,				Change
	2005		2004		%
	(in thousands)
Revenues	$	86,196	$	21,932	293	%

Operating expenses:
Purchased product costs	39,024		3,669		964	%
Facility expenses	10,463		3,229		224	%
Depreciation	4,836		1,489		225	%
Amortization of intangible assets	8,293		3,446		141	%
Accretion of asset retirement obligation	33		13		154	%
Total operating expenses before selling, general and administrative expenses	62,649		11,846		429	%

Operating income before selling, general and administrative expenses	$	23,547	$	10,086	133	%

Revenues. Revenues increased 293% during the year ended December 31, 2005, relative to the comparable period in 2004. The Partnership acquired the East Texas System on July 30, 2004. As a result, the Partnership reflected only five months of activity during 2004. The remaining increase is attributed to price increases and growth in gathering volumes and associated liquid production.

Purchased Product Costs. Purchased product costs increased 964% during the year ended December 31, 2005, relative to the comparable period in 2004, primarily due to the fact that we acquired the East Texas System on July 30, 2004. The remaining increase is attributed to price increases.

Facility Expenses. Facility expenses increased 224% during the year ended December 31, 2005, relative to the comparable period in 2004 primarily due to the fact that we acquired the East Texas System on July 30, 2004. In addition, repair expense increased as a result of a global overhaul of our compressors. Compensation expense also increased due to the hiring of additional staff to operate our new plants.

Depreciation. Depreciation expense increased 225% during the year ended December 31, 2005, relative to the comparable period in 2004 primarily due to the fact that we acquired the East Texas system on July 30, 2004. We also experienced an increase in property, plant and equipment of 41%, primarily for the construction of a new processing plant and gathering systems, which were put into service on January 1, 2006.

Amortization of Intangible Assets. Amortization of intangible assets increased 141% during the year ended December 31, 2005, relative to the comparable period in 2004, primarily due to the fact that we acquired the East Texas System on July 30, 2004.

Oklahoma

	Year Ended December 31,				Change
	2005		2004		%
	(in thousands)
Revenues	$	213,947	$	133,636	60	%

Operating expenses:
Purchased product costs	193,787		118,325		64	%
Facility expenses	4,927		3,659		35	%
Depreciation	2,385		2,059		16	%
Accretion of asset retirement obligation	63		—		NA
Total operating expenses before selling, general and administrative expenses	201,162		124,043		62	%

Operating income before selling, general and administrative expenses	$	12,785	$	9,593	33	%

Revenues. Revenues increased 60% during the year ended December 31, 2005, relative to the comparable period in 2004 due to increased inlet volumes, and higher natural gas prices.

Purchased Product Costs. Purchased product costs increased 64% during the year ended December 31, 2005, relative to the comparable period in 2004, primarily as a result of increased gas prices and throughput volumes.

Facility Expenses. Facility expenses increased 35% during the year ended December 31, 2005, relative to the comparable period in 2004 primarily due to higher maintenance and rent expense from additional compressors on our Oklahoma system and increased utility expenses.

Depreciation. Depreciation expense increased 16% during the year ended December 31, 2005, relative to the comparable period in 2004 due to the addition of compressors at our Butler compressor station and additional well connections in the field.

Other Southwest

	Year Ended December 31,				Change
	2005		2004		%
	(in thousands)
Revenues	$	106,661	$	69,464	54	%

Operating expenses:
Purchased product costs	92,602		55,519		67	%
Facility expenses	4,990		3,694		35	%
Depreciation	3,383		3,099		9	%
Amortization of intangible assets	68		194		(65	)%
Accretion of asset retirement and lease obligation	22		—		NA
Total operating expenses before selling, general and administrative expenses	101,065		62,506		62	%

Operating income before selling, general and administrative expenses	$	5,596	$	6,958	(20	)%

Revenues. Revenues increased 54% during the year ended December 31, 2005, relative to the comparable period in 2004 due to an increase in natural gas volumes, primarily on the Appleby and Edwards gathering systems, along with a substantial increase in Texas natural gas prices.

Purchased Product Costs. Purchased product costs increased 67% during the year ended December 31, 2005, relative to the comparable period in 2004, primarily due to increased volumes and prices on the Appleby and Edwards gathering systems.

Facility Expenses. Facility expenses increased 35% during the year ended December 31, 2005, relative to the comparable period in 2004, primarily due to increased compressor maintenance and rent expense due to additional compressors on the Appleby system.

Depreciation. Depreciation increased 9% for the year ended December 31, 2005, relative to the comparable period in 2004 due to new compressor assets added during 2004 and early 2005.

Gulf Coast

	Year Ended December 31,				Change
	2005		2004		%
	(in thousands)
Revenues	$	13,832	$	—	NA

Operating expenses:
Purchased product costs	—		—		NA
Facility expenses	2,152		—		NA
Depreciation	1,078		—		NA
Amortization	1,295		—		NA
Total operating expenses before selling, general and administrative expenses	4,525		—		NA

Operating income before selling, general and administrative expenses	$	9,307	$	—	NA

The increase in the above categories is the result of our acquisition of Javelina Systems in 2005.

Appalachia

	Year Ended December 31,				Change
	2005		2004		%
	(in thousands)
Revenues:
Affiliated parties	$	64,922	$	59,026	10	%
Unaffiliated parties	1,758		1,632		8	%
Total revenues	66,680		60,658		10	%

Operating expenses:
Purchased product costs	38,435		30,031		28	%
Facility expenses	19,360		13,444		44	%
Depreciation	3,187		4,329		(26	)%
Impairment	—		130		NA
Accretion of asset retirement obligation	41		—		NA
Total operating expenses before selling, general and administrative expenses	61,023		47,934		27	%

Operating Income (loss) before selling, general and administrative expenses	$	5,657	$	12,724	(56	)%

Revenues. Revenues increased 10% during the year ended December 31, 2005, relative to the comparable period in 2004 primarily as a result of price increases. An inlet volume decrease of $0.5 million offset this increase.

Purchased Product Costs. Purchased product costs increased 28% during the year ended December 31, 2005, relative to the comparable period in 2004 due to a price increase. The remainder of the increase is attributable to trucking costs of approximately $2.0 million incurred to transport product from our Maytown and Boldman plants to our Siloam fractionation plant as a result of the November 2004 pipeline failure.

Facility Expenses. Facility expenses increased 44% during the year ended December 31, 2005, relative to the comparable period in 2004, primarily due to $5.0 million of repairs and refurbishment costs.

Depreciation. Depreciation expense decreased 26% during the year ended December 31, 2005, relative to the comparable period in 2004 due to accelerated Cobb plant depreciation recorded in 2004.

Michigan

	Year Ended December 31,					Change
	2005			2004		%
	(in thousands)
Revenues	$	12,496		$	15,624	(20	)%

Operating expenses:
Purchased product costs	3,030			3,990		(24	)%
Facility expenses	6,080			5,885		3	%
Depreciation	4,665			4,580		2	%
Total operating expenses before selling, general and administrative expenses	13,775			14,455		(5	)%

Operating income (loss) before selling, general and administrative expenses	$	(1,279	)	$	1,169	(209	)%

Revenues. Revenues decreased 20% during the year ended December 31, 2005, relative to the comparable period in 2004. The reduction is primarily due to lower natural gas transport and processing volumes and, consequently, corresponding reductions in natural gas liquids sales volumes resulting from production declines.

Purchased Product Costs. Purchased product costs decreased 24% during the year ended December 31, 2005, relative to the comparable period in 2004 due to reduced natural gas liquids production purchases stemming from production declines.

Facility Expenses. Facility expenses increased 3% during the year ended December 31, 2005, relative to the comparable period in 2004, primarily due to increased regulatory and professional consulting expenses.

Depreciation. Depreciation expense increased 2% during the year ended December 31, 2005, relative to the comparable period in 2004 due to crude oil pipeline and equipment additions depreciated in 2005.

Consolidated Financial Information

	Year Ended December 31,						Change
	2005			2004			%
	(in thousands)
Total segment operating income	$	55,613		$	40,530		37	%
Derivatives not allocated to segments	728			—			NA
Selling, general and administrative expense	21,573			16,133			34	%

Income from operations	33,312			24,397			37	%

Loss from unconsolidated affiliates	(2,153		)	(65		)	3,212	%
Interest income	367			87			322	%
Interest expense	(22,469		)	(9,236		)	143	%
Amortization of deferred financing costs (a component of interest expense)	(6,780		)	(5,236		)	29	%
Miscellaneous income	78			15			420	%

Net income	$	2,355		$	9,962		(76	)%

Selling, General and Administrative Expense. Selling, general and administrative expenses increased 34% during the year ended December 31, 2005, relative to the comparable period in 2004 as a result of an increase in non-cash incentive compensation expense of $1.9 million, and audit and Sarbanes-Oxley-related costs of $2.1 million.

Derivative Expense not allocated to Segments. Beginning in the fourth quarter of 2005, the Partnership entered into commodity derivative transactions as part of an entity-wide, comprehensive risk management plan. Prior to the fourth quarter of 2005, derivative activity occurred within segments. The above amount reflects unallocated results of derivative activity.

Loss from Unconsolidated Affiliates. The loss from unconsolidated affiliates during the year ended December 31, 2005, increased as a result of losses incurred from Hurricane Rita.

Interest Income. Interest income increased by $0.3 million during the year ended December 31, 2005, relative to the comparable period in 2004, primarily due to an increase in interest earned on cash equivalents.

Interest Expense. Interest expense increased 143% during the year ended December 31, 2005, relative to the comparable period in 2004, primarily due to increased debt levels resulting from the financing of our 2004 and 2005 acquisitions. In addition to a larger debt amount, interest rates increased significantly between 2004 and 2005. The Partnership also incurred approximately $1.0 million in 2005 from penalty interest expense on the senior debt.

Amortization of Deferred Financing Costs. During the year ended December 31, 2005, the Partnership amortized approximately $6.8 million of deferred financing costs related to debt issuance costs it incurred to finance its acquisitions.

The increase in the amortization of deferred financing costs in 2005 relative to the comparable period in 2004 is attributable to the write-off of deferred financings costs associated with our debt refinancing completed in the fourth quarter of 2005. Deferred financing costs are being amortized over the terms of the related obligations.

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

East Texas

	Year Ended December 31,				Change
	2004		2003		%
	(in thousands)
Revenues	$	21,932	$	—	NA

Operating expenses:
Purchased product costs	3,669		—		NA
Facility expenses	3,229		—		NA
Depreciation	1,489		—		NA
Amortization of intangible assets	3,446		—		NA
Accretion of asset retirement obligation	13		—		NA
Total operating expenses before selling, general and administrative expenses	11,846		—		NA

Operating income before selling, general and administrative expenses	$	10,086	$	—	NA

The East Texas acquisition was completed on July 30, 2004, so there were no results to report for 2003.

Oklahoma

	Year Ended December 31,				Change
	2004		2003		%
	(in thousands)
Revenues	$	133,636	$	7,855	1,601	%

Operating expenses:
Purchased product costs	118,325		7,010		1,588	%
Facility expenses	3,659		298		1,128	%
Depreciation	2,059		158		1,203	%
Accretion of asset retirement obligation	—		—		NA
Total operating expenses before selling, general and administrative expenses	124,043		7,466		1,561	%

Operating income before selling, general and administrative expenses	$	9,593	$	389	2,366	%

The Western Oklahoma acquisition was completed on December 1, 2003, so there was only one month of activity to report for the year ended December 31, 2003.

Other Southwest

	Year Ended December 31,				Change
	2004		2003		%
	(in thousands)
Revenues	$	69,464	$	46,669	49	%

Operating expenses:
Purchased product costs	55,519		37,827		47	%
Facility expenses	3,694		2,914		27	%
Depreciation	3,099		2,126		46	%
Amortization of intangible assets	194		—		NA
Total operating expenses before selling, general and administrative expenses	62,506		42,867		46	%

Operating income before selling, general and administrative expenses	$	6,958	$	3,802	83	%

Revenues. Revenues increased 49% for the year ended December 31, 2004, relative to the comparable period in 2003 due to the acquisitions of the Pinnacle gathering system in March 2003, the Lubbock pipeline in April 2004, and the Hobbs lateral pipeline in April 2004.

Purchased Product Costs. Purchased product costs increased 47% for the year ended December 31, 2004, relative to the comparable period in 2003, primarily due the acquisitions of the Pinnacle gathering system in March 2003, the Lubbock pipeline in April 2004, and the Hobbs lateral pipeline in April 2004.

Facility Expenses. Facility expenses increased 27% for the year ended December 31, 2004, relative to the comparable period in 2003, primarily due to the acquisitions of the Pinnacle gathering system in March 2003, the Lubbock pipeline in April 2004, and the Hobbs lateral pipeline in April 2004.

Depreciation. Depreciation expense increased 46% for the year ended December 31, 2004, relative to the same period in 2003 due to the acquisitions of the Pinnacle gathering system in March 2003, the Lubbock pipeline in April 2004, and the Hobbs lateral pipeline in April 2004.

Gulf Coast

The Javelina acquisition was completed on November 1, 2005, so there were no results to report for the years ended December 31, 2004 and 2003.

Appalachia

	Year Ended December 31,				Change
	2004		2003		%
	(in thousands)
Revenues:
Sales to affiliate	$	59,026	$	49,850	18	%
Sales to unaffiliated parties	1,632		1,278		28	%
Total revenues	60,658		51,128		19	%

Operating expenses:
Purchased product costs	30,031		22,387		34	%
Facility expenses	13,444		12,316		9	%
Depreciation	4,329		2,870		51	%
Impairment	130		1,148		(89	)%
Total operating expenses before selling, general and administrative expenses	47,934		38,721		24	%

Operating income before selling, general and administrative expenses	$	12,724	$	12,407	3	%

Revenues. Revenues increased 19% for the year ended December 31, 2004, relative to the same period in 2003 as a result of higher NGL product sales prices and volumes.

Purchased Product Costs. Purchased product costs increased 34% for the year ended December 31, 2004, relative to the

same period in 2003 due to a higher NGL product sales prices and volumes.

Facility Expenses. Facility expenses increased 9% for the year ended December 31, 2004, relative to the same period in 2003 primarily due to pipeline inspection and repairs required by the November 2004 pipeline failure.

Depreciation. Depreciation expense increased 51% for the year ended December 31, 2004, relative to the same period in 2003 due to accelerated Cobb plant depreciation recorded in 2004.

Michigan

	Year Ended December 31,				Change
	2004		2003		%
	(in thousands)
Revenues	$	15,624	$	11,778	33	%

Operating expenses:
Purchased product costs	3,990		3,608		11	%
Facility expenses	5,885		4,935		19	%
Depreciation	4,580		2,394		91	%
Total operating expenses before selling, general and administrative expenses	14,455		10,937		32	%

Operating income (loss) before selling, general and administrative expenses	$	1,169	$	841	39	%

Revenues. Revenues increased 33% for the year ended December 31, 2004, relative to the same period in 2003 due to the acquisition of the Michigan crude pipeline that was acquired in December 2003 that was partially offset by reduced NGL pipeline throughput volumes, which decreased revenue by $0.5 million.

Purchased Product Costs. Purchased product costs increased 11% for the year ended December 31, 2004, relative to the same period in 2003 due to the acquisition of the Michigan crude pipeline that was acquired in December 2003 that was partially offset by reduced NGL pipeline throughput volumes.

Facility Expenses. Facility expenses increased 19% for the year ended December 31, 2004, relative to the same period in 2003 due to the acquisition of the Michigan crude pipeline that was acquired in December.

Depreciation. Depreciation expense increased 91% the year ended December 31, 2004, relative to the same period in 2003 due to the acquisition of the Michigan crude pipeline that was acquired in December.

Consolidated Financial Information

	Year Ended December 31,						Change
	2004			2003			%
	(in thousands)
Segment operating income	$	40,530		$	17,439		132	%
Selling, general and administrative expense	16,133			8,598			88	%

Income from operations	24,397			8,841			176	%

Interest income	87			14			521	%
Interest expense	(9,236		)	(3,087		)	199	%
Amortization of deferred financing costs (a component of interest expense)	(5,236		)	(984		)	432	%
Miscellaneous expense	(50		)	(25		)	(100	)%

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

Selling, General and Administrative Expense (“SG&A”). SG&A expenses increased during the year ended December 31, 2004, compared to 2003 because MarkWest Hydrocarbon was contractually limited to $4.9 million in the amount it could charge us, from May 24, 2002, the date of our initial public offering, through May 23, 2003. In addition, SG&A expenses have increased due to increased administrative costs of $2.1 million associated with 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. 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 also 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.

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

Amortization of Deferred Financing Costs. Amortization of deferred financing costs increased in 2004 relative to 2003 due to the debt re-financings completed in 2004 and the deferred financing costs associated with 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 that, $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.

Liquidity and Capital Resources

Our primary sources of liquidity, to meet operating expenses and fund capital expenditures (other than for certain acquisitions), are cash flows generated by our operations, and our access to equity and debt markets. The equity and debt markets, public and private, retail and institutional, have been our principal source of capital used to finance a significant amount of our growth, including acquisitions. During the first quarter of 2005, we borrowed $40.0 million from our credit facility to finance the Starfish acquisition. In the fourth quarter of 2005, the $392.8 million Javelina acquisition and then-existing borrowings, were financed with an interim bridge credit facility that was subsequently replaced by a new long-term credit facility, as described below. During the year ended December 31, 2005, we spent $70.8 million on capital expenditures, primarily for the construction of a new processing plant and gathering systems in East Texas to handle our future contractual commitments, and construction of the new replacement Cobb processing facility in Appalachia.

During 2005, we borrowed approximately $432.8 million, primarily to finance our acquisitions. We received approximately $100.0 million in proceeds from a private placement of common units, which was used to pay down our credit facility.

On December 29, 2005, MarkWest Energy Operating Company, L.L.C., a wholly owned subsidiary of MarkWest Energy Partners L.P., entered into the fifth amended and restated credit agreement (“Partnership Credit Facility”), which provides for a maximum lending limit of $615.0 million for a five-year term. The credit facility includes a revolving facility of $250.0 million and a $365.0 million term loan, which can be repaid at any time without penalty. Under certain circumstances, the Partnership Credit Facility can be increased from $250 million up to $450 million. The credit facility is guaranteed by the Partnership and all of the Partnership’s subsidiaries and is collateralized by substantially all of the Partnership’s assets and those of its subsidiaries. The borrowings under the credit facility bear interest at a variable interest rate, plus basis points. The variable interest rate is typically based on the London Inter Bank Offering Rate (“LIBOR”); however, in certain borrowing circumstances the rate would be based on the higher of a) the Federal Funds Rate plus 0.5-1%, and b) a rate set by the Facility’s administrative agent, based on the U.S. prime rate. The basis points correspond to the ratio of the Partnership’s Consolidated Senior Debt (as defined in the Partnership Credit Facility) to Consolidated EBITDA (as defined in the Partnership Credit Facility), ranging from 0.50% to 1.50% for Base Rate loans, and 1.50% to 2.50% for Eurodollar Rate loans. The basis points will increase by 0.50% during any period (not to exceed 270 days) where the Partnership makes an acquisition for a purchase price in excess of $50.0 million (“Acquisition Adjustment Period”). Borrowings under the Partnership Credit Facility were used to finance, in part, the Javelina acquisition discussed above. On December 31, 2005, the available borrowing capacity under the Partnership Credit Facility was $74.8 million.

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

At December 31, 2005, the Partnership and its subsidiary, MarkWest Energy Finance Corporation, also have $225.0 million in senior notes outstanding, at a fixed rate of 6.875%. The notes mature on November 2, 2014. The proceeds from these notes were used to pay down our outstanding debt under our credit facility in October 2004. Subject to compliance with certain covenants, we may issue additional notes from time to time under the indenture pursuant to Rule 144A and Regulation S under the Securities Act of 1933.

The indenture governing the senior notes 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 interests of the Partnership’s subsidiaries; make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets.

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. The Partnership failed to complete the exchange offer in the time provided for in the subscription agreements (April 26, 2005) and, as a consequence, is incurring an interest rate penalty of 0.5%, increasing 0.25% every 90 days thereafter up to 1%, until such time as the exchange offer is completed. The Partnership is currently being charged an interest rate penalty of 1%. The registration statement was filed on January 17, 2006, and the interest penalty ceased on March 7, 2006.

Cash generated from operations, borrowings under our credit facility and funds from our private and public equity offerings are our primary sources of liquidity. The timing of our efforts to raise equity in the future, however, will be influenced by our inability to timely file our Annual Report on Form 10-K for the year ended December 31, 2004, and our quarterly report on Form 10-Q for the quarter ending March 31, 2005. Should we choose to raise capital through a public offering with the SEC, we will not have the ability to incorporate by reference information from our future filings into a new registration statement until October 11, 2006. If we raise additional capital through public debt or equity offerings, we are required to file a Form S-1, which is a long-form type of registration statement. The requirement to file a Form S-1 registration statement may affect our ability to access the capital markets on a timely basis and may increase the costs of doing so. We believe, nonetheless, that funds from raising equity, together with cash generated from operations and borrowings under our credit facility, will be sufficient to meet both our short-term and long-term working capital requirements and anticipated capital expenditures. Funding of additional acquisitions will likely require the issuance of additional common units, the expansion of our credit facility, or both.

Our ability to pay distributions to our unitholders and to fund planned capital expenditures and make acquisitions will depend upon our future operating performance. That, in turn, will be affected by prevailing economic conditions in our industry, as well as financial, business and other factors, some of which are beyond our control.

One of our largest customers is MarkWest Hydrocarbon. Consequently, matters affecting the business and financial condition of MarkWest Hydrocarbon—including its operations, management, customers, vendors, and the like—could affect our liquidity.

The Partnership has budgeted $58.7 million for capital expenditures in 2006, exclusive of any acquisitions, consisting of $55.6 million for expansion capital and $3.1 million for sustaining capital. Expansion capital includes expenditures made to expand or increase the efficiency of the existing operating capacity of our assets, or facilitate an increase in volumes within our operations, whether through construction or acquisition. Sustaining capital includes expenditures to replace partially or fully depreciated assets in order to extend their useful lives.

Cash Flow

	December 31,
	2005			2004
	(in thousands)

Net cash provided by operating activities	$	42,090		$	42,275
Net cash used in investing activities	(469,308		)	(273,176		)
Net cash provided by financing activities	423,060			246,411

Net cash provided by operating activities decreased less than $0.2 million during the year ended December 31, 2005, compared to the year ended December 31, 2004. The decrease was impacted by a decrease in net income, offset by an increase in certain non-cash operating expenses, primarily depreciation and amortization for a full year from our East Texas acquisition, and two months from our November acquisition of Javelina. We expect that, overall, our 2006 volumes will be higher than in 2005, and that cash provided by operating activities in 2006 will exceed 2005 levels. A precipitous decline in natural gas, NGL or crude oil prices or volumes, however, could significantly affect the amount of cash flow that would be generated from operations.

Net cash used in investing activities was higher during the year ended December 31, 2005, than during the year ended December 31, 2004, primarily due to our $41.7 million investment in a 50% non-operating interest in Starfish and our $398.3 million acquisition of Javelina in November 2005. In July 2004, we acquired East Texas for $240.7 million. The Partnership used cash of $70.8 million for capital expenditures in 2005, primarily for the construction of a new processing plant and gathering systems in East Texas to handle our future contractual commitments and construction of the new replacement Cobb processing facility in Appalachia. In 2004, the Partnership used cash of $30.5 million for capital expenditures.

Net cash provided by financing activities increased $176.6 million during the year ended December 31, 2005, compared to the year ended December 31, 2004. The increase was due primarily to net proceeds from additional long-term debt and private placements to fund our acquisitions. Distributions to unitholders increased to $39.0 million in 2005, from $24.6 million in 2004.

Total Contractual Cash Obligations

A summary of our total contractual cash obligations as of December 31, 2005, is as follows, in thousands:

	Payment Due by Period
Type of obligation	Total Obligation		Due in 2006		Due in 2007-2008		Due in 2009-2010		Thereafter

Long-term debt	$	604,000	$	2,738	$	7,300	$	368,962	$	225,000
Operating leases	7,102		3,646		2,759		496		203
Purchase obligations	1,500		1,500		—		—		—
Total contractual cash obligations	$	612,602	$	7,884	$	10,062	$	369,458	$	225,203

Off-Balance Sheet Arrangements

Other than facility- and equipment-leasing arrangements, the Partnership does not engage in off-balance sheet financing activities.

Matters Influencing Future Results

We earn fees for transporting, fractionating and selling the NGLs recovered from the Kenova, Maytown, and Boldman plants to Siloam via our Appalachian pipeline. In November 2004, a leak and ensuing explosion and fire occurred on a leased section of this pipeline. The Company and several of its affiliates were served in early 2005 with two lawsuits presently under the jurisdiction of the U.S. District Court for the Eastern District of Kentucky, Pikeville Division. In early November 2005, we were served with an additional lawsuit filed in Floyd County Circuit Court, Kentucky, adding five new claimants, but essentially alleging the same facts and claims as the earlier two suits. These suits are for third-party claims of property and personal injury damages sustained as a consequence of the explosion and fire. The Partnership has timely notified its general liability insurance carriers of the incident and of the filed Kentucky actions and is coordinating the defense of these third-party lawsuits with the insurers. While investigation into the incident continues, at this time the Partnership believes that it has adequate general liability insurance coverage for third-party property damage and personal injury liability. The Partnership has settled with several of the claimants for property damage claims (damage to residences and personal property), in addition to reaching settlement for some of the personal injury claims related to the incident. These settlements have been paid for or reimbursed under the Partnership’s general liability insurance. As a result, the Partnership has not provided for a loss contingency.

The Partnership has filed an independent action captioned MarkWest Hydrocarbon, Inc., et al. v. Liberty Mutual Ins. Co., et al. (District Court, Arapahoe County, Colorado, Case No. 05CV3953 filed August 12, 2005), as removed to the U.S. District Court for the District of Colorado, Civil Action No. 1:05-CV-1948, on October 7, 2005), against its All-Risks Property and Business Interruption insurance carriers as a result of the insurance companies’ refusal to honor their insurance coverage obligation to pay the Partnership for certain expenses. These include the Partnership’s internal expenses and costs incurred for damage to, and loss of use of the pipeline, equipment, products, the extra transportation costs incurred for transporting the liquids while the pipeline was out of service, the reduced volumes of liquids that could be processed, and the costs of complying with the OPS Corrective Action Order (hydrostatic testing, repair/replacement and other pipeline integrity assurance measures). These expenses and costs have been expensed as incurred and any potential recovery from the All-Risks Property and Business Interruption insurance carriers will be treated as “other income” if and when they are received. The Partnership has not provided for a receivable for these claims because of the uncertainty as to whether and how much the Partnership will ultimately recover under these policies. The Partnership has also asserted that the cost of pipeline testing, replacement and repair are subject to an equitable sharing arrangement with the pipeline owner, pursuant to the terms of the pipeline lease agreement.

The Partnership acquired the Javelina gas processing, transportation and fractionation business located in Corpus Christi, Texas (the “Javelina Business”) on November 1, 2005. The Javelina Business was a party with numerous other defendants to three lawsuits brought by plaintiffs who had residences or businesses located near the Corpus Christi industrial area, an area which included the Javelina gas processing plant, and several petroleum, petrochemical and metal processing and refining operations. These suits, styled Victor Huff v. ASARCO Incorporated, et al. (Cause No. 98-01057-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in March 3, 1998); Hipolito Gonzales et al. v. ASARCO Incorporated, et al., (Cause No. 98-1055-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in 1998); Jesus Villarreal v. Koch Refining Co. et al., (Cause No. 05-01977-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed April 27, 2005), set forth claims for personal injury or property damage, harm to business operations and nuisance type claims, allegedly incurred as a result of operations and emissions from the various industrial operations in the area. The Hipolito Gonzales action is subject to a settlement in principle reached in a mediation held December 9, 2005. The Partnership’s involvement and engagement in the other cases has been limited to this point, but the actions have been and are being vigorously defended and, based on initial evaluation and consultations, it appears at this time that these actions should not have a material impact on the Partnership.

The Partnership has a 50% non-operating ownership interest in Starfish Pipeline Company L.L.C. (“Starfish”), which operates, through its subsidiaries, certain Gulf Coast offshore and onshore facilities. Both Hurricanes Katrina and Rita impacted the Starfish operations. Based on our discussions with the operator and other 50% owner of Starfish, Enbridge Offshore (Gas Transmission) L.L.C. (“Enbridge”), the Partnership has been informed that initial inspections indicate no major damage to Starfish’s offshore platform facilities. However, as a result of Hurricane Rita, repair and rerouting of at least two sections of offshore pipeline will be required, and are expected to be underway through the beginning of the second quarter of 2006. Further sonar and other inspections of the underwater pipe to assess sediment support and cover, and any other damage, is ongoing. Additionally, structural damage occurred at the onshore Starfish dehydration and compressor facilities. The hurricane caused significant damage to the electrical systems, control equipment and office buildings at the onshore facilities, requiring significant repair. Repair, refurbishment and replacement efforts will continue through the first quarter of 2006. Starfish operations have been substantially curtailed since shortly before the hurricanes hit the Gulf Coast in

September 2005, and until such repairs are completed Starfish is not able to fully return to normal operations and this will have a continuing material impact on operating income through the first quarter of 2006. Our evaluation of the Starfish venture is subject to a number of factors. We are still in the process of determining the full extent of the damage incurred by Hurricane Rita, and we must all continue to evaluate our claims for insurance recovery for property damage and business interruption. In addition, we are also still in discussions with various operators of interconnecting production and processing facilities to the extent their activities were also affected by hurricane damage in the region.

Commodity Price Sensitivity

Our earnings and cash flow are dependent on sales volumes and our ability to achieve positive sales margins on the product we sell. The volumes of our sales and our margin on sales can be adversely affected by the prices of commodities, which are subject to significant fluctuation depending upon numerous factors beyond our control, including the supply of and demand for commodity products. The supply of and demand for our products can be affected by, among other things, production levels, industry-wide inventory levels, the availability of imports, the marketing of products by competitors, and the marketing of competitive fuels.

Seasonality

For the portion of our business that is affected by commodity prices, sales volumes also are affected by various other factors such as fluctuating and seasonal demands for products, changes in transportation and travel patterns and variations in weather patterns from year to year.

Effects of Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact our results of operations for the years ended December 31, 2005, 2004 or 2003. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, 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. Estimates are used in accounting for, among other items, valuing identified intangible assets, determining the fair value of derivative instruments, evaluating impairments of long lived assets, establishing estimated useful lives for long-lived assets, valuing asset retirement obligations, and in determining liabilities, if any, for legal contingencies.

The policies and estimates discussed below are considered by management to be critical to an understanding of the Partnership’s financial statements, because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See Note 2 of the accompanying Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information on these policies and estimates, as well as a discussion of additional accounting policies and estimates.

Intangible Assets

The Partnership’s intangible assets are comprised of customer contracts and relationships acquired in business combinations, recorded under the purchase method of accounting at their estimated fair values at the date of acquisition. Using relevant information and assumptions, management determines the fair value of acquired identifiable intangible assets. Fair value is generally calculated as the present value of estimated future cash flows using a risk-adjusted discount rate. The key assumptions include contract renewals, economic incentives to retain customers, historical volumes, current and future capacity of the gathering system, pricing volatility, and the discount rate. Amortization of intangibles with definite lives is calculated using the straight-line method over the estimated useful life of the intangible asset. The contracts’ estimated economic lives are determined by assessing the life of the related assets, likelihood of renewals, competitive factors, regulatory or legal provisions, and maintenance and renewal costs.

Impairment of Long-Lived Assets

The Partnership evaluates its long-lived assets, including intangibles, for impairment when events or changes in circumstances warrant such a review. A long-lived asset group is considered impaired when the estimated undiscounted cash flows from such asset group are less than the asset group’s carrying value. In that event, a loss is recognized to the extent that the carrying value exceeds the fair value of the long-lived asset group. Fair value is determined primarily using estimated discounted cash flows. Management considers the volume of reserves behind the asset and future NGL product and natural gas prices to estimate cash flows. The amount of additional reserves developed by future drilling activity depends, in part, on expected 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.

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.

Investment in Starfish

On March 31, 2005, the Partnership acquired its non-controlling, 50% interest in Starfish Pipeline Company, LLC (“Starfish”), accounted for under the equity method. Differences between the Partnership’s investment and its proportionate share of Starfish’s reported equity are amortized based upon the respective useful lives of the assets to which the differences relate.

We believe the equity method is an appropriate means for us to recognize increases or decreases measured by GAAP in the economic resources underlying the investments. Regular evaluation of these investments is appropriate to evaluate any potential need for impairment. We use the following types of triggers to identify a loss in value of an investment that is other than a temporary decline. Examples of a loss in value may be identified by:

• Our belief in the ability to recover the carrying amount of the investment;

• A current fair value of an investment that is less than its carrying amount; and

• Other operational criteria that cause us to believe the investment may be worth less than otherwise accounted for by using the equity method.

Derivative Instruments

SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, established 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. To the extent derivative instruments designated as cash flow hedges are effective, changes in fair value are recognized in other comprehensive income until the underlying hedged item is recognized in earnings. Effectiveness is evaluated by the derivative instrument’s ability to offset changes in fair value or cash flows of the underlying hedged item. Any change in the fair value resulting from ineffectiveness is recognized immediately in earnings. Changes in the fair value of derivative instruments designated as fair value hedges, as well as the changes in the fair value of the underlying hedged item, are recognized currently in earnings. Any differences between the changes in the fair values of the hedged item and the derivative instrument represent gains or losses from ineffectiveness. To the extent the Partnership elects hedge accounting treatment for specific derivatives, the Partnership formally documents, designates and assesses the effectiveness of transactions receiving hedge accounting treatment. As of December 31, 2005, no transactions had been designated for hedge accounting treatment. In general, the Partnership exempts those contracts that qualify as normal purchase and sale contracts from the mark-to-market requirements of FAS No. 133 and marks all other derivatives to market. Settlements of NGL and natural gas derivative transactions are generally reflected in revenue.

Revenue Recognition

The Partnership generates the majority of its revenues from natural gas gathering and processing, NGL fractionation, transportation and storage, and crude oil gathering and transportation. While all of these services constitute midstream energy operations, the Partnership provides its services pursuant to six different types of arrangements. In many cases, the Partnership provides services under contracts that contain a combination of more than one of the arrangements. The following is a description of the Partnership’s six arrangements.

• Fee-based arrangements - Under fee-based arrangements, the Partnership receives 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 the Partnership earns from these contracts is directly related to the volume of natural gas, NGLs or crude oil that flows through its systems and facilities and is not directly dependent on commodity prices.

• Percent-of-proceeds arrangements - Under percent-of-proceeds arrangements, the Partnership generally gathers and processes natural gas on behalf of producers, sells the resulting residue natural gas and NGLs at market prices and remits to the producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, MarkWest Energy delivers an agreed upon percentage of the residue gas and NGLs to the producer and sells the volumes it keeps to third parties at market prices.

• Percent-of-index arrangements - Under percent-of-index arrangements, the Partnership generally purchases natural gas at either a percentage discount to a specified index price, a specified index price less a fixed amount or a percentage discount to a specified index price less an additional fixed amount. MarkWest Energy then gathers and delivers the natural gas to pipelines where it resells the natural gas at the index price.

• Keep-whole arrangements. Under keep-whole arrangements, we gather natural gas from the producer, process the natural gas to extract NGLs, sell the NGLs to third parties and pay the producer, in the form of processed gas or its cash equivalent, for the full thermal equivalent volume of raw natural gas we received from the producer. Accordingly, our net operating margin is a function of the difference between the value of the extracted NGLs that we sell and the cost of the processed gas that would replace the thermal equivalent value of those NGLs. The profitability of these arrangements is subject not only to the commodity price risk of natural gas and NGLs but also to the price of natural gas relative to the price of NGLs. Our net operating margins increase under these arrangements when the value of NGLs is high relative to the cost of a thermal equivalent amount of natural gas, and our net operating margins decrease when the cost of natural gas is high relative to the value of a thermal equivalent amount of NGLs.

• Settlement margin - Under settlement margin, the Partnership is 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 Partnership’s gathering systems are operated more efficiently than specified per contract allowance, we are entitled to retain the difference for its 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. Under these arrangements, condensate collected in the system is retained by us and sold at market prices.

Under all six arrangements, revenue is recognized at the time the product is delivered and title is transferred. It is upon delivery and title transfer that the Partnership meets all four revenue recognition criteria, and it is at such time that the Partnership recognizes revenue.

The Partnership’s assessment of each of the four revenue recognition criteria as they relate to its revenue producing activities is as follows:

Persuasive evidence of an arrangement exists. The Partnership’s customary practice is to enter into a written contract, executed by both the customer and the Partnership.

Delivery. Delivery is deemed to have occurred at the time the product is delivered and title is transferred or, in the case of fee-based arrangements, when the services are rendered. To the extent we retain our equity liquids as inventory, delivery occurs when the inventory is subsequently sold and title is transferred to the third party purchaser.

The fee is fixed or determinable. The Partnership negotiates the fee for its services at the outset of its fee-based arrangements. In these arrangements, the fees are nonrefundable. The fees are generally due within ten days of delivery or services rendered. For other arrangements, the amount of revenue is determinable when the sale of the applicable product has been completed upon delivery and transfer of title. Proceeds from the sale of products are generally due in 10 days.

Collectibility is probable. Collectibility is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (e.g. cash position and credit rating) and their ability to pay. If collectibility is not considered probable at the outset of an arrangement in accordance with the

Partnership’s credit review process, revenue is recognized when the fee is collected.

Certain revenue from sales of customer gas to a third-party processor is recognized net, under EITF 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, as the Partnership earns a fixed amount and does not take ownership of the gas.

Earnings Per Unit

Except as discussed in the following paragraph, basic and diluted net income per limited partner unit is calculated by dividing net income, after deducting amounts specially allocated to the general partner’s interests, including interests in incentive distribution rights, by the weighted-average number of limited partner common and subordinated units outstanding during the period.

Emerging Issues Task Force Issue No. 03-06 (“EITF 03-06”) “Participating Securities and the Two-Class Method under FASB Statement No. 128” addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity. EITF 03-06 provides that the general partner’s interest in net income is to be calculated based on the amount that would be allocated to the general partner if all the net income for the period were distributed, and not on the basis of actual cash distributions for the period. The application of EITF 03-06 may have an impact on earnings per limited partner unit in future periods if there are material differences between net income and actual cash distributions or if other participating securities are issued.

The following table sets forth the computation of basic and diluted earnings per limited partner unit. The net income available to limited partners and the weighted average limited partner units outstanding have been adjusted for instruments considered common unit equivalents in 2005, 2004 and 2003:

	2005				2004				2003
Numerator for basic and diluted earnings per limited partner unit:
Net income	$		2,355		$		9,962		$		4,759
Adjustments:
General partner’s incentive distribution paid	(4,163			)	(1,355			)	(40			)
Participation plan/depreciation special allocations (see Note 12)	2,055				2,296				804

Subtotal	247				10,903				5,523
General partner’s 2% interest	(5			)	(218			)	(110			)

Net income to limited partners	$	242			$	10,685			$	5,413

Denominator:
Denominator for basic earnings per limited partner unit-weighted average number of limited partner units	10,895				8,151				5,722
Effect of dilutive securities:
Weighted-average of restricted units outstanding	34				26				51
Denominator for diluted earnings per limited partner unit-weighted average number of limited partner units			10,929				8,177				5,773

Basic net income per limited partner unit	$		0.02		$		1.31		$		0.95
Diluted net income per limited partner unit	$		0.02		$		1.31		$		0.94

Incentive Compensation Plans

The Partnership has elected to continue to measure compensation costs for unit-based employee compensation plans as prescribed by Accounting Principles Board (“APB”) No. 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 employees 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. Vesting is accelerated for certain employees, if specified 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. The vesting of any phantom units, however, 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 of its employees and directors 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, the Participation Plan is accounted for as a variable plan. Since the employees and directors are 100% vested (except for two non-executives who have restricted general partnership interests) 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.

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, 2005, 2004, and 2003, respectively.

Recent Accounting Pronouncements

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 May 2005, the FASB issued SFAS No. 154, “Accounting for Changes and Error Corrections – a Replacement of APB Opinion No. 20 and FASB Statement No. 3” (SFAS 154). SFAS 154 requires retrospective application of voluntary changes in accounting principles, unless impracticable. SFAS 154 supersedes the guidance in APB Opinion No. 20 and SFAS No. 3, but does not change any transition provisions of existing pronouncements. Generally, elective accounting changes will no longer result in a cumulative effect of a change in accounting in the income statement, because the effects of any elective changes will be reflected as prior period adjustments to all periods presented. SFAS 154 will be effective beginning in fiscal 2006 and will affect any accounting changes that we elect to make thereafter.

In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140” (“SFAS 155”). This statement amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities” and resolves issues addressed in SFAS 133 Implementation Issue No. D1, “Application of Statement 133 to Beneficial Interest in Securitized Financial Assets”. This Statement: (a) permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation; (b) clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133; (c) establishes a requirement to evaluate beneficial interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation; (d) clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives; and, (e) eliminates restrictions on a qualifying special-purpose entity’s ability to hold passive derivative financial instruments that pertain to beneficial interests that are or contain a derivative financial instrument. The standard also requires presentation within the financial statements that identifies those hybrid financial instruments for which the fair value election has been applied and information on the income statement impact of the changes in fair value of those instruments. The Partnership is required to apply SFAS 155 to all financial instruments acquired, issued or subject to a remeasurement event beginning January 1, 2007, although early adoption is permitted as of the beginning of an entity’s fiscal year. The provisions of SFAS 155 are not expected to have an impact recorded at adoption.

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 Risk

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

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

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

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

As part of an ongoing comprehensive risk management plan, designed to manage risk and stabilize future cash flows, the Partnership has entered into the following derivative instruments that settle monthly through December 31, 2007:

Costless Collars:	Period	Floor		Cap		Fair Value at December 31, 2005
Crude Oil — 500 Bbl/d	2006	$	57.00	$	67.00	$	(187	)
Crude Oil — 250 Bbl/d	2006	$	57.00	$	67.00	(93		)
Crude Oil — 205 Bbl/d	2006	$	57.00	$	65.10	(126		)

Propane — 20,000 Gal/d	2006	$	0.90	$	0.99	(258		)
Propane — 10,000 Gal/d	2006	$	0.97	$	1.15	162
Propane — 12,750 Gal/d	Jan – June 2006	$	0.90	$	1.01	(56		)

Ethane — 22,950 Gal/d	2006	$	0.65	$	0.80	104

Natural Gas — 1,575 Mmbtu/d	Jan - Mar 2006	$	9.00	$	11.40	62
Natural Gas — 1,575 Mmbtu/d	April - Oct 2006	$	8.50	$	10.05	(86		)
Natural Gas — 1,575 Mmbtu/d	Nov - Mar 2007	$	9.00	$	12.50	(58		)
Natural Gas — 645 Mmbtu/d	Jan - Mar 2006	$	8.86	$	15.21	14
Natural Gas — 645 Mmbtu/d	April - June 2006	$	6.71	$	12.46	19

Swaps		Fixed Price		Fair Value at December 31, 2005
Crude Oil — 250 Bbl/d	2006	$	62.00	$	(105	)
Crude Oil — 185 Bbl/d	2006	$	61.00	(143		)
Crude Oil — 250 Bbl/d	2007	$	65.30	23

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

While we expect these derivative instruments to provide economic stability against the impact of changing commodity prices on our physical positions, for accounting purposes, we will not designate these derivatives as cash flow hedges and will not apply hedge accounting.

As a result of our decision not to designate these derivatives as cash flow hedges for accounting purposes, we are required to mark each contract to market with the resulting unrealized gain or loss recorded in revenue in the income statement. For the year ended December 31, 2005, unrealized losses of approximately $728,000 were recorded. The fair value of our derivative contracts at December 31, 2005 of $728,000 was recorded as a derivative liability. Changes in forward price curves can result in significant changes in the fair value of our derivative contracts as reported, however, we expect the actual settlements to be largely offset by changes in the settlement of our physical positions.

Interest Rate

Our primary interest rate risk exposure results from our $615.0 million long-term debt agreement, entered into on December 29, 2005. The debt related to this agreement bears interest at variable rates that are tied to either the U.S. prime rate or LIBOR at the time of borrowing. 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.

Long-term Debt	Due	Outstanding at December 31, 2005
Variable Rate ($615.0 million)	December 29, 2010	$379.0 million
Fixed Rate ($225.0 million)	November, 2014	$225.0 million

Based on our overall interest rate exposure at December 31, 2005, a hypothetical instantaneous increase or decrease of one percentage point in interest rates applied to borrowings under our credit facility would change earnings by approximately $3.8 million over a 12-month period.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

Report of Deloitte & Touche LLP, Independent Registered Public Accounting Firm

Report of KPMG LLP, Independent Registered Public Accounting Firm

Report of PricewaterhouseCoopers, LLP Independent Registered Public Accounting Firm

Consolidated Balance Sheets at December 31, 2005 and 2004

Consolidated Statements of Operations for each of the three years in the period ended December 31, 2005

Consolidated Statements of Comprehensive Income for each of the three years in the period ended December 31, 2005

Consolidated Statements of Changes in Capital for each of the three years in the period ended December 31, 2005

Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2005

Notes to Consolidated Financial Statements

All omitted shedules have been omitted because they are not required or because the required information is contained in the financial statements or notes thereto.

Pursuant to Rule 3.09 of Regulation S-X, separate financial statements of subsidiaries not consolidated and 50 percent or less owned persons, the omitted financial statements of Starfish, a non-accelerated filer, that are required to be filed by us are expected to be filed by us by amendment to this report not later than 90 days after the end of our fiscal year.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

MarkWest Energy GP, L.L.C.

Englewood, Colorado

We have audited the accompanying consolidated balance sheet of MarkWest Energy Partners, L.P. and subsidiaries (the “Partnership”) as of December 31, 2005, and the related consolidated statements of operations, comprehensive income, changes in capital, and cash flows for the year then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the 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, such consolidated financial statements present fairly, in all material respects, the financial position of MarkWest Energy Partners, L.P. and subsidiaries as of December 31, 2005, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 16, 2006 expressed an unqualified opinion on management’s assessment of the effectiveness of the Partnership’s internal control over financial reporting and an adverse opinion on the effectiveness of the Partnership’s internal control over financial reporting.

/s/	DELOITTE & TOUCHE LLP

Denver, Colorado

March 16, 2006

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.

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.

/s/	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 statements of operations, of comprehensive income, of changes in capital and cash flows for the year ended December 31, 2003 present fairly, in all material respects, the results of operations and cash flows of MarkWest Energy Partners, L.P., a Delaware partnership, and its subsidiaries (the Partnership) for the year 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 audit. We conducted our audit of these statements 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

March 15, 2004, except for Note 18 (presented herein) and Note 19 to the consolidated financial statements included in the Annual Report on Form 10-K for the year ended December 31, 2004 (not presented herein), as to which the date is May 24, 2005

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

	December 31,
	2005			2004
ASSETS
Current assets:
Cash and cash equivalents	$	20,105		$	24,263
Receivables, net of allowances of $151 and $211, respectively	110,038			41,890
Receivables from affiliate	7,940			5,846
Inventories	3,554			449
Other assets	6,861			511
Total current assets	148,498			72,959

Property, plant and equipment	567,094			335,430
Less: Accumulated depreciation	(74,133		)	(54,795		)
Total property, plant and equipment, net	492,961			280,635

Other assets:
Investment in Starfish	39,167			—
Investment in and advances to equity investee	182			177
Intangibles and other assets, net of accumulated amortization of $13,321 and $3,666 respectively	346,496			162,001
Deferred financing costs, net of accumulated amortization of $4,424 and $5,496, respectively	18,463			13,650
Other	326			—
Total other assets	404,634			175,828
Total assets	$	1,046,093		$	529,422

LIABILITIES AND CAPITAL
Current liabilities:
Accounts payable	$	102,175		$	35,695
Payables to affiliate	3,421			7,003
Accrued liabilities	27,492			19,329
Fair value of derivative instruments	728			385
Current portion of long-term debt	2,738			—
Total current liabilities	136,554			62,412

Long-term debt	601,262			225,000
Other liabilities	1,102			868
Total liabilities	738,918			288,280
Commitments and contingencies (Note 15)

Capital:
General partner	6,788			5,160
Limited partners:
Common unitholders (11,070 and 7,642 units issued and outstanding at December 31, 2005 and 2004, respectively)	300,882			227,483
Subordinated unitholders (1,800 and 3,000 units issued and outstanding at December 31, 2005 and 2004, respectively)	(495		)	8,813
Accumulated other comprehensive loss	—			(314		)
Total capital	307,175			241,142
Total liabilities and capital	$	1,046,093		$	529,422

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

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

	Year Ended December 31,
	2005			2004			2003

Revenues:
Unaffiliated parties	$	436,013		$	243,108		$	68,360
Affiliates	64,922			59,026			49,850
Derivatives	(1,851		)	(820		)	(780		)
Total revenues	499,084			301,314			117,430

Operating expenses:
Purchased product costs	366,878			211,534			70,832
Facility expenses	47,972			29,911			20,463
Selling, general and administrative expenses	21,573			16,133			8,598
Depreciation	19,534			15,556			7,548
Amortization of intangible assets	9,656			3,640			—
Accretion of asset retirement obligation	159			13			—
Impairments	—			130			1,148
Total operating expenses	465,772			276,917			108,589

Income from operations	33,312			24,397			8,841

Other income (expense):
Interest income	367			87			14
Interest expense	(22,469		)	(9,236		)	(3,087		)
Amortization of deferred financing costs (a component of interest expense)	(6,780		)	(5,236		)	(984		)
Loss from unconsolidated affiliates	(2,153		)	(65		)	—
Miscellaneous income (expense)	78			15			(25		)
Net income	$	2,355		$	9,962		$	4,759

Interest in net income (loss):
General partner	$	2,113		$	(723	)	$	(654	)
Limited partners	$	242		$	10,685		$	5,413

Net income per limited partner unit:
Basic	$	0.02		$	1.31		$	0.95
Diluted	$	0.02		$	1.31		$	0.94

Weighted average units outstanding:
Basic	10,895			8,151			5,722
Diluted	10,929			8,177			5,773

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

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

	Year Ended December 31,
	2005		2004		2003

Net income	$	2,355	$	9,962	$	4,759

Other comprehensive income (loss) – unrealized gains (losses) on commodity derivative instruments accounted for as hedges	314		184		213

Comprehensive income	$	2,669	$	10,146	$	4,972

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

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

	PARTNERS’ CAPITAL												Accumulated
	Limited Partners												Other
	Common				Subordinated					General			Comprehensive
	Units	Amount			Units		Amount			Partner			Income (Loss)			Total
Balance at December 31, 2002	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	—	—			—		—			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	—	2,495			—		2,918			(654		)	—			4,759
Other comprehensive income	—	—			—		—			—			213			213
Balance at December 31, 2003	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
Issuance of units in private placements, net of offering costs	2,219	97,518			—		—			1,990			—			99,508
Common units issued for vested restricted units, including contribution by MarkWest Energy GP, LLC	9	432			—		—			9			—			441
Contributions by MarkWest Energy GP, LLC										404						404
Common unit registration costs		(45		)	—		—			—			—			(45		)
Subordinated units converted to common units	1,200	496			(1,200	)	(496		)	—			—			—
Participation Plan compensation expense allocated from MarkWest Hydrocarbon	—	—			—		—			2,055			—			2,055
Distributions to partners	—	(24,866		)	—		(9,190		)	(4,943		)	—			(38,999		)
Net income	—	(136		)	—		378			2,113			—			2,355
Other comprehensive income	—	—			—		—			—			314			314
Balance at December 31, 2005	11,070	$	300,882		1,800		$	(495	)	$	6,788		$	—		$	307,175

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

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

	Year Ended December 31,
	2005			2004			2003
Cash flows from operating activities:
Net income	$	2,355		$	9,962		$	4,759
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation	19,534			15,556			7,548
Amortization of intangible assets	9,656			3,640			—
Amortization of deferred financing costs	6,780			5,236			984
Accretion of asset retirement obligation	159			13			—
Impairments	—			130			1,148
Restricted unit compensation expense	1,076			1,065			1,357
Participation Plan compensation expense	2,055			2,277			912
Equity in losses of investee	1,561			73			81
Distribution from Starfish	2,441			—			—
Unrealized loss on derivative instruments	657			71			—
Gain on sale of property, plant and equipment	(24		)	(29		)	—
Other	(28		)	27			21
Changes in operating assets and liabilities, net of acquisitions:
Receivables	11,216			(29,948		)	(1,166		)
Receivables from affiliates	(2,094		)	(3,429		)	430
Inventories	(1,318		)	(203		)	(956		)
Other assets	(6,676		)	(288		)	113
Accounts payable and accrued liabilities	(1,678		)	32,643			5,197
Payables to affiliates	(3,582		)	5,479			801
Net cash provided by operating activities	42,090			42,275			21,229

Cash flows from investing activities:
Acquisitions, net of cash acquired:
Javelina	(356,917		)	—			—
East Texas System	—			(240,726		)	—
Hobbs Lateral	—			(2,275		)	—
Pinnacle	—			—			(38,526		)
Lubbock Pipeline	—			—			(12,235		)
Western Oklahoma	—			—			(37,951		)
Michigan Crude Pipeline	—			—			(21,283		)
Investment in Starfish	(41,688		)	—			—
Capital expenditures	(70,750		)	(30,467		)	(2,944		)
Payments on financing lease receivable	—			133			—
Proceeds from sale of property, plant and equipment	47			159			46
Net cash flows used in investing activities	(469,308		)	(273,176		)	(112,893		)

Cash flows from financing activities:
Proceeds from long-term debt	893,000			220,100			391,700
Repayment of long-term debt	(514,000		)	(346,300		)	(286,900		)
Proceeds from private placement of senior notes	—			225,000			—
Payments for debt issuance costs	(11,808		)	(15,399		)	(3,995		)
Proceeds from secondary public offerings, net	—			142,076			—
Proceeds from private placements, net	94,508			44,962			9,964
Payments for deferred offering costs	(45		)	—			(389		)
Capital contribution from MarkWest Energy GP, LLC	404			592			695
Distributions to unitholders	(38,999		)	(24,620		)	(13,434		)
Net cash flows provided by financing activities	423,060			246,411			97,641

Net increase (decrease) in cash	(4,158		)	15,510			5,977
Cash and cash equivalents at beginning of year	24,263			8,753			2,776
Cash and cash equivalents at end of year	$	20,105		$	24,263		$	8,753

Supplemental disclosures of cash flow information:
Cash paid during the year for interest, net of amounts capitalized	$	22,112		$	6,532		$	2,068

Supplemental schedule of non-cash investing and financing activities:
Construction projects in progress	$	(1,545	)	$	4,037		$	—

Property, plant and equipment asset retirement obligation	$	561		$	377		$	450

Deferred offering costs payable	$	215		$	—		$	606

Accrued amounts due to Javelina sellers and Starfish	$	6,888		$	—		$	—

Accrued private placement proceeds	$	5,000		$	—		$	—

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

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

MarkWest Energy Partners, L.P. 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 eight acquisitions completed during 2003, 2004 and 2005, 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.

2. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements include the accounts of MarkWest Energy Partners, L.P., and all of its majority-owned subsidiaries (collectively, the “Partnership”), and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Equity investments in which the Partnership exercises significant influence, but does not control and is not the primary beneficiary, are accounted for using the equity method.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, 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. Estimates affect, among other items, valuing identified intangible assets, determining the fair value of derivative instruments, evaluating impairments of long lived assets, establishing estimated useful lives for long-lived assets, valuing asset retirement obligations, and in determining liabilities, if any, for legal contingencies.

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 are valued at the lower of weighted average cost or market. Inventories consisting primarily of crude oil and unprocessed natural gas are valued based on the cost of the raw material. Processed natural gas inventories include material, labor and overhead. Shipping and handling costs are included in operating expenses.

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. Leasehold improvements are depreciated over the shorter of the useful life or lease term. Depreciation is provided, principally on the straight-line method, over the following estimated useful lives:

Asset Class		Range of Estimated Useful Lives
Buildings		20 – 25 years
Gas gathering facilities		20 – 25 years
Gas processing plants		20 – 25 years
Fractionation and storage facilities		20 – 25 years
Natural gas pipelines		20 – 25 years
Crude oil pipelines		20 – 25 years
NGL transportation facilities		20 – 25 years
Equipment and other		3 – 10 years

The Partnership recognizes the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred, with an offsetting increase in the carrying amount of the related long-lived asset. Over time, the liability is accreted to its future value, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. The Partnership adopted FIN 47, Accounting for Conditional Asset Retirement Obligations, on January 1, 2005. FIN 47 clarified the accounting for conditional asset retirement obligations under SFAS 143, Accounting for Asset Retirement Obligations. A conditional asset retirement obligation is an unconditional legal obligation to perform an 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. FIN 47 requires an entity to recognize a liability for a conditional asset retirement obligation if the amount can be reasonably estimated. Adopting FIN 47 had an immaterial impact on the Partnership.

Investment in Starfish

On March 31, 2005, the Partnership acquired its non-controlling, 50% interest in Starfish Pipeline Company, LLC (“Starfish”) for $41.7 million, which is accounted for under the equity method. Differences between the Partnership’s investment and its proportionate share of Starfish’s reported equity are amortized based upon the respective useful lives of the assets to which the differences relate. For the year ended December 31, 2005, the Partnership received a dividend of $2.4 million, and accrued $1.5 million for a capital call. The Partnership’s share of Starfish’s loss in 2005 was $1.6 million.

Our accounting policy requires us to evaluate operating losses, if any, and other factors that may have occurred, that may be indicative of a decrease in value of the investment which is other than temporary, and which should be recognized even though the decrease in value is in excess of what would otherwise be recognized by application of the equity method. The evaluation allows us to determine if an equity method investment should be impaired and that an impairment, if any, is fairly reflected in our financial statements

The Partnership believes the equity method is an appropriate means for it to recognize increases or decreases measured by GAAP in the economic resources underlying the investments. Regular evaluation of these investments is appropriate to evaluate any potential need for impairment. It uses the following types of triggers to identify a loss in value of an investment that is other than a temporary decline. Examples of a loss in value may be identified by:

• An inability to recover the carrying amount of the investment;

• A current fair value of an investment that is less than its carrying amount; and

• Other operational criteria that cause us to believe the investment may be worth less than otherwise accounted for by using the equity method.

Intangible Assets

The Partnership’s intangible assets are comprised of customer contracts and relationships acquired in business combinations, recorded under the purchase method of accounting at their estimated fair values at the date of acquisition. Using relevant information and assumptions, management determines the fair value of acquired identifiable intangible assets. Fair value is generally calculated as the present value of estimated future cash flows using a risk-adjusted discount rate. The key assumptions include contract renewals, economic incentives to retain customers, historical volumes, current and future capacity of the gathering system, pricing volatility, and the discount rate. Amortization of intangibles with definite lives is calculated using the straight-line method over the estimated useful life of the intangible asset. The estimated economic life is determined by assessing the life of the assets to which the contracts and relationships relate, likelihood of renewals, competitive factors, regulatory or legal provisions, and maintenance and renewal costs.

Impairment of Long-Lived Assets

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, included in Other assets, are amortized over the estimated lives of the related obligations or, in certain circumstances, accelerated if the obligation is refinanced.

Derivative Instruments

SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, established 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. To the extent derivative instruments designated as cash flow hedges are effective, changes in fair value are recognized in other comprehensive income until the underlying hedged item is recognized in earnings. Effectiveness is evaluated by the derivative instrument’s ability to offset changes in fair value or cash flows of the underlying hedged item. Any change in the fair value resulting from ineffectiveness is recognized immediately in earnings. Changes in the fair value of derivative instruments designated as fair value hedges, as well as the changes in the fair value of the underlying hedged item, are recognized currently in earnings. Any differences between the changes in the fair values of the hedged item and the derivative instrument represent gains or losses from ineffectiveness. To the extent that the Partnership elects hedge accounting treatment for specific derivatives, the Partnership formally documents, designates and assesses the effectiveness. As of December 31, 2005, no transactions had been designated for hedge accounting treatment. In general, the Partnership exempts those contracts that qualify as normal purchase and sale contacts from the mark-to-market requirements of SFAS 133. All other derivative instruments are marked-to-market through revenue.

Fair Value of Financial Instruments

Management believes the carrying amount of financial instruments, including cash, accounts receivable, accounts payable, accrued expenses, and other financial instruments approximates fair value because of the short-term maturity of these instruments. Management believes the carrying value of the Partnership’s Credit Facility (Note 10) approximates fair value due to its variable interest rates. The estimated fair value of the Senior Notes (Note 10) was approximately $207.0 million and $225.0 million at December 31, 2005 and 2004, respectively, based on quoted market prices. Derivative instruments not designated as hedges (Note 11) are recorded at fair value, based on available market information.

Revenue Recognition

• Fee-based arrangements - Under fee-based arrangements, the Partnership receives 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 the Partnership earns from these contracts is directly related to the volume of natural gas, NGLs or crude oil that flows through its systems and facilities and is not directly dependent on commodity prices.

delivers the natural gas to pipelines where it resells the natural gas at the index price.

The Partnership’s assessment of each of the four revenue recognition criteria as they relate to its revenue producing activities is as follows:

Persuasive evidence of an arrangement exists. The Partnership’s customary practice is to enter into a written contract, executed by both the customer and the Partnership.

Delivery. Delivery is deemed to have occurred at the time the product is delivered and title is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain our equity liquids as inventory, delivery occurs when the inventory is subsequently sold and title is transferred to the third party purchaser.

The fee is fixed or determinable. The Partnership negotiates the fee for its services at the outset of its fee-based arrangements. In these arrangements, the fees are nonrefundable. The fees are generally due within ten days of delivery or services rendered. For other arrangements, the amount of revenue is determinable when the sale of the applicable product has been completed upon delivery and transfer of tile. Proceeds from the sale of products are generally due in ten days.

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 $2.6 million and $0.1 million and an imbalance receivable of $2.7 million and $1.4 million at December 31, 2005 and 2004, 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. As described above, changes in the fair value of commodity derivative instruments are recognized currently in revenue.

Incentive Compensation Plans

MarkWest Hydrocarbon also has entered into arrangements with certain of its employees and directors. 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, the Participation Plan is accounted for as a variable plan. Since the employees and directors are 100% vested (except for two non-executives who have restricted general partnership interests) 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.

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 years ended December 31, 2005, 2004, and 2003, 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.

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

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

The following table sets forth the computation of basic and diluted earnings per limited partner unit. The net income available to limited partners and the weighted average to those used to compute diluted net income per limited partner unit for the years ended December 31, 2005, 2004 and 2003:

	2005				2004				2003
Numerator for basic and diluted earnings per limited partner unit:
Net income	$		2,355		$		9,962		$		4,759
Adjustments:
General partner’s incentive distribution paid	(4,163			)	(1,355			)	(40			)
Participation plan/depreciation special allocations (see Note 12)	2,055				2,296				804

Subtotal	247				10,903				5,523
General partner’s 2% interest	(5			)	(218			)	(110			)

Net income to limited partners	$	242			$	10,685			$	5,413

Denominator:
Denominator for basic earnings per limited partner unit-weighted average number of limited partner units	10,895				8,151				5,722
Effect of dilutive securities:
Weighted-average of restricted units outstanding	34				26				51
Denominator for diluted earnings per limited partner unit-weighted average number of limited partner units			10,929				8,177				5,773

Basic net income per limited partner unit	$		0.02		$		1.31		$		0.95
Diluted net income per limited partner unit	$		0.02		$		1.31		$		0.94

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. The Partnership has 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. It will take into consideration the additional guidance provided by SAB 107 in connection with the implementation of SFAS No. 123(R).

3. Acquisitions

Javelina Acquisition

On November 1, 2005, for consideration of $357.0 million, plus $41.3 million for net working capital, the Partnership acquired equity interests in Javelina Company, Javelina Pipeline Company and Javelina Land Company, L.L.C., which were 40%, 40% and 20%, respectively, owned by subsidiaries of El Paso Corporation, Kerr-McGee Corporation, and Valero Energy Corporation. The Corpus Christi, Texas, gas-processing facility treats and processes off-gas from six local refineries, two of which are owned by Valero Energy Corporation, two by Koch Industries, Inc. and two by Citgo Petroleum Corporation. The facility was constructed in 1989 to recover up to 28,000 barrels per day of NGLs. The facility currently processes approximately 125 to 130 MMcf/d of inlet gas, but it is expected to process up to its capacity of 142 MMcf/d as refinery output continues to grow. The Partnership and the seller are still negotiating the final value of the acquired working capital, so the purchase price may change upon settlement.

Starfish Joint Venture

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

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 acquired assets consist of processing plants, gathering systems, a processing facility currently under construction and an NGL pipeline.

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.

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 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 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 a third-party Lakehead Pipeline, which then transports the crude oil to refineries in Sarnia, Ontario, Canada.

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, financed through borrowings under the credit facility. 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 and processing 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.

Lubbock Pipeline Acquisition

Effective September 2, 2003, the Partnership, through its wholly owned subsidiary, MarkWest Pinnacle L.P., completed the 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 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 of $39.9 million was financed through borrowing under the Partnership’s line of credit.

The following table summarizes the costs and allocations of the above acquisitions (in thousands):

	Pinnacle			Lubbock Pipeline		Western Oklahoma		Michigan Crude Pipeline		Hobbs Lateral		East Texas			Javelina
Acquisition Costs:
Cash consideration	$	39,471		$	12,200	$	37,850	$	21,155	$	2,300	$	240,269		$	396,336
Direct acquisition costs	450			—		101		128		—		457			2,009
Totals:	$	39,921		$	12,200	$	37,951	$	21,283	$	2,300	$	240,726		$	398,345

Allocation of acquisition costs:
Current Assets	$	10,643		—		—		—		—		$	65		$	111,679
Customer contracts and relationships	—			—		—		—		—		165,379			194,150
Property, plant and equipment	38,223			12,200		37,951		21,283		2,300		76,012			162,859
Liabilities assumed	(8,945		)	—		—		—		—		(730		)	(70,343		)
Totals:	$	39,921		$	12,200	$	37,951	$	21,283	$	2,300	$	240,726		$	398,345

Pro Forma Results of Operations (Unaudited)

The following table reflects the unaudited pro forma consolidated results of operations for the years ended December 31, 2005, 2004 and 2003, as though the Starfish and Gulf Coast acquisitions had occurred on January 1, 2004, and the East Texas System, Michigan Crude Pipeline, Western Oklahoma, Lubbock and Pinnacle acquisitions had occurred on January 1, 2003. The unaudited pro forma results have been prepared for comparative purposes only and may not be indicative of future results.

	Year Ended December 31,
	2005			2004		2003
	(in thousands, except per unit amounts)

Revenue	$	754,948		$	607,893	$	209,699
Net income (loss)	$	(5,492	)	$	20,464	$	(4,233	)
Net income (loss) - limited partners	$	(7,007	)	$	20,591	$	(3,380	)

Net income (loss) per limited partner unit:
Basic	(0.64		)	$	1.94	$	(0.32	)
Diluted	(0.64		)	$	1.93	$	(0.32	)

Weighted average units outstanding:
Basic	10,895			10,629		10,589
Diluted	10,929			10,655		10,640

4. Significant Customers and Concentration of Credit Risk

For the years ended December 31, 2005, 2004 and 2003, the Appalachia segment’s sales to MarkWest Hydrocarbon accounted for 13%, 20%, and 42% of Partnership revenues, respectively. As of December 31, 2005 and 2004, the Partnership had $7.9 million and $5.8 million, respectively, of accounts receivable from MarkWest Hydrocarbon. Consequently, matters affecting the business and financial condition of MarkWest Hydrocarbon, including its operations, management, customers, and vendors, have the potential to affect the Partnership. The Partnership’s business is concentrated within the Appalachian Basin, southwest United States and Michigan geographic areas. Changes and events within these regions have the potential to affect the Partnership.

For the years ended December 31, 2005, 2004 and 2003, the Other Southwest segment had sales to one other customer accounting for 14%, 20%, and 20% of Partnership revenues, respectively. The Partnership had $5.5 million and

$3.6 million, respectively, receivable from this customer as of December 31, 2005 and 2004.

5. Receivables and Other Current Assets

Receivables consist of the following (in thousands):

	December 31,
	2005		2004
Trade, net	$	100,894	$	34,864
Other	9,144		7,026
Total receivables	$	110,038	$	41,890

Other current assets consist of the following (in thousands):

	December 31,
	2005		2004
Customer margin deposits	$	2,600	$	—
Prepaid fuel	3,614		151
Prepaid other	647		360
Total other assets	$	6,861	$	511

6. Properties, Plant and Equipment

Property, plant and equipment consist of:

		December 31,
		2005			2004
		(in thousands)

Gas gathering facilities		$	212,042		$	160,763
Gas processing plants		213,943			56,239
Fractionation and storage facilities		22,882			22,112
Natural gas pipelines		42,246			38,167
Crude oil pipelines		19,070			18,499
NGL transportation facilities		4,433			4,381
Land, building and other equipment		10,987			6,510
Construction in-progress		41,491			28,759
		567,094			335,430
Less:	Accumulated depreciation	(74,133		)	(54,795		)
	Total property, plant and equipment, net	$	492,961		$	280,635

The Partnership capitalizes interest on major projects during construction. For the years ended December 31, 2005 and 2004, the Partnership capitalized interest of $2.1 million and $0.8 million, respectively. The Partnership did not capitalize interest for the year ended December 31, 2003, as there were no major construction projects.

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 old 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, 2005 and 2004, costs of $0.4 million and $0.6 million, respectively, have been funded by MarkWest Energy GP, L.L.C., which amounts have been reflected as an increase in partners’ capital.

7. Intangible Assets

The Partnership’s intangible assets at December 31, 2005 and 2004, are comprised of customer contracts and relationships, as follows (in thousands):

	December 31, 2005							December 31, 2004
Description	Gross			Accumulated Amortization		Net		Gross		Accumulated Amortization		Net		Useful Life
East Texas	$		165,379	$	11,740	$	153,639	$	165,379	$	3,446	$	161,933	20 years
Javelina	194,150			1,293		192,857		—		—		—		25 years
Other	288			288		—		288		220		68		1 year
Total:	$	359,817		$	13,321	$	346,496	$	165,667	$	3,666	$	162,001

Amortization expense related to the intangible assets was $9.7 million, $3.6 million and $0.0 million for the years ended December 31, 2005, 2004 and 2003.

Estimated future amortization expense related to the intangible assets at December 31, 2005, is as follows (in thousands):

Year ending December 31:
2006	$	16,035
2007	16,035
2008	16,035
2009	16,035
2010	16,035
Thereafter	266,321
Total	$	346,496

8. Accrued Liabilities

Accrued liabilities consist of the following (in thousands):

	December 31,
	2005		2004
Product and operations	$	5,967	$	7,373
Customer obligations	3,380		3,773
Professional services	1,736		517
Taxes (other than income tax)	2,183		1,078
Interest	3,233		2,876
Javelina working capital adjustment	5,402		—
Starfish contribution	1,486		—
Construction in progress	2,652		2,602
Deferred income	223		290
Other	1,230		820

Total accrued liabilities	$	27,492	$	19,329

9. Asset Retirement Obligation

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. The Partnership also has land leases that require the Partnership to return the land to its original condition upon the termination of the lease. In connection with the adoption of SFAS 143, the Partnership reviewed current laws and regulations governing obligations for asset retirements and leases, as well as the Partnership’s leases and other agreements.

The following is a reconciliation of the changes in the asset retirement obligation from January 1, 2003, to December 31, 2005 (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
Accrued liabilities	553
Accretion expense	159
Liabilities settled	(450		)
Asset retirement obligation as of December 31, 2005	$	1,102

At January 1 and December 31, 2005 and 2004, there were no assets legally restricted for purposes of settling asset retirement obligations.

10. Debt

Debt as of December 31, 2005 and 2004, is summarized below:

	2005			2004
	(in thousands)
Partnership Credit Facility
Term loan, 8.75% interest at December 31, 2005, due December 2010	$	365,000		$	—
Revolver facility, 8.75% interest at December 31, 2005, due December 2010	14,000			—
Senior Notes
Senior Notes, 6.875% interest, due November 2014	225,000			225,000
	604,000			225,000
Less: obligations due in one year	(2,738		)	—
Total long-term debt	$	601,262		$	225,000

Partnership Credit Facility

On December 29, 2005, MarkWest Energy Operating Company, L.L.C., a wholly owned subsidiary of MarkWest Energy Partners L.P., entered into the fifth amended and restated credit agreement (“Partnership Credit Facility”), which provides for a maximum lending limit of $615.0 million for a five-year term. The credit facility includes a revolving facility of $250.0 million and a $365.0 million term loan. The credit facility is guaranteed by the Partnership and all of the Partnership’s subsidiaries and is collateralized by substantially all of the Partnership’s assets and those of its subsidiaries. The borrowings under the credit facility bear interest at a variable interest rate, plus basis points. The variable interest rate is typically based on the London Inter Bank Offering Rate (“LIBOR”); however, in certain borrowing circumstances the rate would be based on the higher of a) the Federal Funds Rate plus 0.5 to 1.0%, and b) a rate set by the Facility’s administrative agent, based on the U.S. prime rate. The basis points vary based on the ratio of the Partnership’s Consolidated Debt (as defined in the Partnership Credit Facility) to Consolidated EBITDA (as defined in the Partnership Credit Facility), ranging from 0.50% to 1.50% for Base Rate loans, and 1.50% to 2.50% for Eurodollar Rate loans. The basis points will increase by

0.50% during any period (not to exceed 270 days) where the Partnership makes an acquisition for a purchase price in excess of $50.0 million (“Acquisition Adjustment Period”). The 8.75% rate at December 31, 2005, was converted to 6.65%, a LIBOR-based rate, on January 5, 2006.

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

• a ratio of not less than 2.00 to 1.00 of Consolidated EBITDA to consolidated interest expense for any fiscal quarter-end increasing to 3.00 to 1.00 upon the first to occur of September 30, 2006 or the first fiscal quarter-end following the Partnership raising at least $175.0 million in aggregate proceeds from equity offerings;

• a ratio of not more than 6.50 to 1.00 of total consolidated debt to Consolidated EBITDA for any fiscal quarter-end decreasing to 5.25 to 1.00 upon the first to occur of September 30, 2006 or the first fiscal quarter-end following the Partnership raising at least $175.0 million in aggregate proceeds from equity offerings;

• a ratio of not more than 4.75 to 1.00 of consolidated senior debt to Consolidated EBITDA for any fiscal quarter-end decreasing to 3.75 to 1.00 upon the first to occur of September 30, 2006 or the first fiscal quarter-end following the Partnership raising at least $175.0 million in aggregate proceeds from equity offerings and

• Both the total debt and senior debt ratios contain adjustment clauses during any Acquisition Adjustment Period.

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

The Javelina Acquisition (see Note 3) was funded through the fourth amended and restated credit agreement, which provided for a maximum lending limit of $500.0 million for a term of one year, comprised of a revolving facility of $100.0 million and a $400.0 million term loan. The fourth amended and restated credit agreement had terms similar to the new credit facility. In the fourth quarter of 2005, the Partnership completed two private placement offerings to repay a portion of the funds borrowed (see Note 14).

In October 2004 the Operating Company, coincident with the issuance of the Senior Notes, discussed below, entered into the third amended and restated credit agreement (“Old Credit Facility”), which provided for a maximum lending limit of $200.0 million for a term of five years. The Old Credit Facility included a revolving facility of $200.0 million. The borrowings under the Old Credit Facility carried interest at a variable 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 adjusted quarterly based on the ratio of funded debt to EBITDA (as defined in the credit agreement). For the years ended December 31, 2005, 2004 and 2003, the weighted average interest rate on the Old Credit Facility was 7.02%, 4.48% and 4.69%, respectively.

Senior Notes

In October 2004 the Partnership and its subsidiary, MarkWest Energy Finance Corporation, issued $225.0 million in

senior notes at a fixed rate of 6.875%, payable semi-annually in arrears on May 1 and November 1, commencing on May 1, 2005. The notes mature on November 2, 2014. The Partnership may redeem some or all of the notes at any time on or after November 1, 2009, at certain redemption prices together with accrued and unpaid interest to the date of redemption. The Partnership may redeem all of the notes at any time prior to November 1, 2009, at a make-whole redemption price. In addition, prior to November 1, 2007, the Partnership may redeem up to 35% of the aggregate principal amount of the notes with the proceeds of certain equity offerings at a stated redemption price. The Partnership must offer to repurchase the notes at a specified price if it a) sells certain assets and does not reinvest the proceeds or repay senior indebtedness, or b) the Partnership experiences specific kinds of changes in control. Each of the Partnership’s existing subsidiaries, other than MarkWest Energy Finance Corporation, has guaranteed the notes jointly and severally and fully and unconditionally. The notes are senior unsecured obligations equal in right of payment with all of the Partnership’s existing and future senior debt. 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 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. The Partnership failed to complete the exchange offer in the time provided for in the subscription agreements (April 26, 2005) and, as a consequence, is incurring an interest rate penalty of 0.5% annually, increasing 0.25% every 90 days thereafter up to 1%, until such time as the exchange offer is completed. As of December 31, 2005, the Partnership was being charged an interest rate penalty of 1%. As discussed further in Note 17, the registration statement was filed on January 17, 2006, and the interest penalty will cease on March 7, 2006.

The aggregate minimum principal payments on long-term debt are as follows, as of December 31, exclusive of any prepayments related to Excess Cash Flow (in thousands):

2006	$	2,738
2007	3,650
2008	3,650
2009	3,650
2010	365,312
2011 and thereafter	225,000
	$	604,000

11. Derivative Financial Instruments

Commodity Instruments

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

Exchange (“NYMEX”). The Partnership enters into OTC swaps with financial institutions and other energy company counterparties. 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 may be subject to margin deposit requirements under some of its agreements.

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

As part of an ongoing comprehensive risk management plan designed to manage risk and stabilize future cash flows, the Partnership has entered into the following derivative instruments that settle monthly through December 31, 2007.

Costless Collars:	Period	Floor		Cap
Crude Oil — 500 Bbl/d	2006	$	57.00	$	67.00
Crude Oil — 250 Bbl/d	2006	$	57.00	$	67.00
Crude Oil — 205 Bbl/d	2006	$	57.00	$	65.10

Propane — 20,000 Gal/d	2006	$	0.90	$	0.99
Propane — 10,000 Gal/d	2006	$	0.97	$	1.15
Propane — 12,750 Gal/d	Jan – June 2006	$	0.90	$	1.01

Ethane — 22,950 Gal/d	2006	$	0.65	$	0.80

Natural Gas — 1,575 Mmbtu/d	Jan - Mar 2006	$	9.00	$	11.40
Natural Gas — 1,575 Mmbtu/d	April - Oct 2006	$	8.50	$	10.05
Natural Gas — 1,575 Mmbtu/d	Nov - Mar 2007	$	9.00	$	12.50
Natural Gas — 645 Mmbtu/d	Jan - Mar 2006	$	8.86	$	15.21
Natural Gas — 645 Mmbtu/d	April - June 2006	$	6.71	$	12.46

Swaps	Fixed Price
Crude Oil — 250 Bbl/d	2006	$	62.00
Crude Oil — 185 Bbl/d	2006	$	61.00
Crude Oil — 250 Bbl/d	2007	$	65.30

In 2003, the Partnership hedged its natural gas price risk in Other Southwest by entering into fixed-for-floating price swaps that settled monthly through December 2005.

The impact of commodity derivative instruments on the Partnership’s results of operations and financial position are summarized below (in thousands):

	Year ended December 31,
	2005			2004			2003
Realized gains (losses) – revenue	$	(1,194	)	$	(749	)	$	(713	)
Unrealized gains (losses) – revenue	(657		)	(71		)	(67		)
Other comprehensive income – changes in fair value	68			(265		)	(500		)
Other comprehensive income – settlement	246			749			713

	December 31,
	2005		2004
Unrealized losses – current liability	$	728	$	385
Accumulated other comprehensive income (loss)	—		(314		)

Interest rate swap

The Partnership discontinued an interest rate hedge in the year ended December 31, 2004, resulting in $0.4 million, included in accumulated other comprehensive loss, being reclassified into earnings.

12. 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. 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, comprised of 200,000 restricted units and 300,000 unit options. The Compensation Committee of the general partner’s board of directors administers the plan.

The general partner’s board of directors, at 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, 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. No change in any outstanding grant, however, 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 equal to the value of a common unit. These restricted units are entitled, during the vesting period, to receive distribution equivalents, which represent cash equal to the amount of distributions made on common units. 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. The Compensation Committee also determines the vesting period. 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, that the Compensation Committee provides otherwise. Common units used for settlement may be acquired by the general partner in the open market, already owned by the general partner, acquired by the general partner directly from the Partnership or any other person, or any combination of the foregoing. The general partner will be entitled to reimbursement from the Partnership 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:

	2005			2004			2003
	(in thousands, except unit data)

Balance, beginning of period	29,500			34,496			50,230
Granted	20,139			27,900			11,756
Vested	(9,100		)	(27,453		)	(23,758		)
Forfeited	(1,675		)	(5,443		)	(3,732		)
Balance, end of period	38,864			29,500			34,496

Fair value, end of year	$	1,873		$	1,434		$	1,383

Compensation expense for the year	$	1,076		$	1,065		$	1,398

Of the total number of restricted units that vested in 2005, the Partnership did not redeem any restricted units for cash, and issued 8,850 common units and acquired 250 common units in the open market. The Partnership recorded $1.1 million in compensation expense in 2005, of which $0.4 million related to the accelerated vesting of restricted units.

In 2004, 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 in 2004, of which $0.5 million related to the accelerated vesting of restricted units, resulting from

specified distribution targets being achieved.

In October 2003, the board of directors of the general partner approved the accelerated vesting of 23,758 restricted unit grants due to the achievement of cash distribution goals, effective December 1, 2003. Accordingly, the Partnership recorded a charge in the amount of $1.0 million.

Unit Options. The Long-Term Incentive Plan currently permits the granting of options for 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, at 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, 2005, 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 of its employees and directors. 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 is sold with certain put-and-call provisions that allow the individuals to require MarkWest Hydrocarbon to buy back, or require the individuals to sell back their interest in the general partner to MarkWest Hydrocarbon. Specifically, the employees and directors can exercise their put if (1) MarkWest Hydrocarbon or the Partnership’s general partner undergoes a change of control; (2) additional membership interests are issued 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 its call option if the employee or director ceases to be a director or employee of MarkWest Hydrocarbon or any of its affiliates, or if there is a change of control. MarkWest Hydrocarbon 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. The Partnership has established an implied repurchase obligation, however, through its pattern of buying back the subordinated units each time an employee or director has left MarkWest Hydrocarbon. The subordinated units converted into common units on August 15, 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 2005, 2004 and 2003 were 0, 1,500 and 12,500, respectively. MarkWest Hydrocarbon reacquired 0, 2,867 and 867 subordinated units in 2005, 2004 and 2003, respectively.

The Partnership recorded compensation expense under the Participation Plan of $2.1 million, $2.3 million and $0.9 million for the years ended December 31, 2005, 2004 and 2003, 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. 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, $0.1 million and $0.2 million for the years ended December 31, 2005, 2004 and 2003, respectively. The plan is discretionary, with annual contributions determined by MarkWest Hydrocarbon’s Board of Directors.

14. Partners’ Capital

As of December 31, 2005, partners’ capital consists of 11,069,576 common limited partner units, representing an 84% partnership interest; 1,800,000 subordinated limited partner units, representing a 14% partnership interest; and a 2% general partner interest. MarkWest Hydrocarbon and its subsidiaries, in the aggregate, own a 21% interest in the Partnership consisting of 836,162 common limited partner units, 1,633,334 subordinated limited partner units and a 2% general partner interest.

The Partnership Agreement defines the Partnership’s ability to issue new capital, maintain capital accounts, and distribute cash, as discussed, below.

The Partnership has the ability to issue an unlimited number of units to fund immediately accretive acquisitions. An immediately accretive acquisition is one that, in the general partner’s good faith determination, would have resulted in an increase to the amount of operating surplus generated by the Partnership on a per-unit basis with respect to each of the four most recently completed quarters on a pro forma basis. During 2005, 2004 and 2003, the Partnership consummated a total of eight acquisitions, aggregating approximately $794.4 million, certain of which were subsequently funded partially by equity offerings.

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. Per the Partnership Agreement, compensation expense under the Participation Plan allocated to the Partnership by MarkWest Hydrocarbon is allocated entirely to the general partner (See Note 12).

Distributions of Available Cash

The Partnership distributes all of its Available Cash (as defined) to unitholders of record and the general partner within 45 days after the end of each quarter. 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 for the quarter 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 (as defined), before any distributions of available cash from operating surplus may be made on the subordinated units, the common unitholders have the right to receive distributions of available cash in an amount equal to the minimum quarterly distribution of $0.50 per quarter per common unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters.

The Subordination Period ends on the first day of any quarter beginning after June 30, 2009, when certain financial tests 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 or financial goals are met. The earliest possible date by which some of the subordinated units could be converted into common units was June 30, 2005. As a result of achieving those goals in May 2005, 600,000 subordinated units were converted into common units on August 15, 2005, and an additional 600,000 subordinated units were converted into common units on November 15, 2005. When the subordination period ends, any remaining subordinated units will convert into common units on a one-for-one basis, and the common unit holders 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.

• 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 quarterly distribution amount exceeds the target levels specified below:

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

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

In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate payment of any cumulative minimum quarterly distribution. The Partnership is currently distributing at a rate in excess of $0.75 per unit.

The quarterly cash distributions applicable to 2005, 2004 and 2003, were as follows:

Quarter Ended	Record Date	Payment Date	Amount Per Unit

December 31, 2005	February 8, 2006	February 14, 2006	$	0.82
September 30, 2005	November 8, 2005	November 14, 2005	$	0.82
June 30, 2005	August 9, 2005	August 15, 2005	$	0.80
March 31, 2005	May 10, 2005	May 16, 2005	$	0.80

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

Private Placement – December 28, 2005

The Partnership sold 574,714 common units to certain accredited investors at $43.50 per common unit, for gross proceeds of $25.0 million. $20 million of the proceeds were received in December 2005. The remaining $5 million was accrued at December 31, 2005, and received in January 2006. Offering costs of $0.1 million reduced the aggregate gross proceeds of $25.0 million to $24.9 million of net proceeds. The net proceeds of $24.9 million, and the $0.5 million contributed by the general partner to maintain its 2% interest, resulted in total net proceeds associated with the private placement of $25.4 million.

Private Placement – November 11, 2005

The Partnership sold 1,644,065 common units to certain accredited investors at $44.21 per common unit, for gross proceeds of $72.7 million. Offering costs of $0.1 million reduced the aggregate gross proceeds of $72.7 million to $72.6 million of net proceeds. The net proceeds of $72.6 million, and the $1.5 million contributed by the general partner to maintain its 2% interest, resulted in total net proceeds associated with the private placement of $74.1 million.

Public Offering – September 21, 2004

The Partnership priced its offering of 2,157,395 common units at $43.41 per unit. The Partnership sold 2,000,000 units, for gross proceeds of $86.8 million. The remaining 157,395 were sold by certain unitholders, who retained the proceeds. 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. Underwriters’ fees of $4.8 million, and professional fees and other offering costs of $0.4 million, reduced the gross proceeds of $100.9 million to $95.7 million of net proceeds. 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 – July 30, 2004

The Partnership sold 1,304,438 common units to certain accredited investors at $34.50 per common unit, for gross proceeds of $45.0 million. Offering costs of $0.9 million reduced the aggregate gross proceeds of $45.0 million to $44.1 million of net proceeds. 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.

Public Offering – January 12, 2004

The Partnership priced its offering of 1,148,000 common units at $39.90 per unit. The Partnership sold 1,100,444 units, for gross proceeds of $43.9 million. The remaining 47,556 were sold by certain unitholders, who retained the proceeds. 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. Underwriters’ fees of $2.5 million, and professional fees and other offering costs of $1.3 million, reduced the gross proceeds of $46.8 million to $43.0 million of net proceeds. 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 of $43.9 million.

Private Placement – June 27 and July 10, 2003

The Partnership sold 375,000 common units to certain accredited investors in two installments at a price of $26.23 per unit. On June 27, 2003, the first installment of 300,031 units raised proceeds of approximately $7.9 million. On July 10, 2003, the second installment of 74,969 units raised proceeds of approximately $1.9 million. Transaction costs for both installments were less than $0.1 million. The Partnership’s general partner made a $0.2 million contribution in order to maintain its 2% interest in July 2003, after the second installment was completed.

15. Commitments and Contingencies

Legal

MarkWest Energy Partners, in the ordinary course of business, is subject to a variety of risks and disputes normally incident to its business, a defendant in various lawsuits and a party to various other legal proceedings. We maintain insurance policies with insurers in amounts and with coverage and deductibles as we believe are reasonable and prudent. However, we cannot assure either that the insurance companies will promptly honor their policy obligations or that the coverage or levels of insurance will be adequate to protect us from all material expenses related to potential future claims for property loss or business interruption to the Partnership or for third party claims of personal and property damage, or that the coverages or levels of insurance it presently has will be available in the future at economical prices.

In early 2005, the Partnership and several of its affiliates were served with two lawsuits, Ricky J. Conn, et al. v. MarkWest Hydrocarbon, Inc. et al.(filed February 7, 2005), and Charles C. Reid, et al. v. MarkWest Hydrocarbon, Inc. et al., (filed February 8, 2005), presently removed to and under the jurisdiction of the U.S. District Court for the Eastern District of Kentucky, Pikeville Division. The Partnership was served with an additional lawsuit, Community Trust and Investment Co., et al. v. MarkWest Hydrocarbon, Inc. et al., filed November 7, 2005 in Floyd County Circuit Court, Kentucky, that added five new claimants but essentially alleged the same facts and claims as the earlier two suits. These actions are for third-party claims of property and personal injury damages sustained as a consequence of an NGL pipeline leak and an ensuing explosion and fire that occurred on November 8, 2004. The pipeline was owned by an unrelated business entity and leased and operated by the Partnership’s subsidiary, MarkWest Energy Appalachia, LLC. It transports NGLs from the Maytown gas processing plant to the Partnership’s Siloam fractionator. The fire from the leaked vapors resulted in property damage to five homes and injuries to some of the residents. The pipeline owner, the U.S. Department of Transportation, Office of Pipeline Safety (“OPS”), and the Partnership continue to investigate the incident.

The Partnership has filed an independent action captioned MarkWest Hydrocarbon, Inc., et al. v. Liberty Mutual Ins. Co., et al. (District Court, Arapahoe County, Colorado, Case No. 05CV3953 filed August 12, 2005), as removed to the U.S. District Court for the District of Colorado, Civil Action No. 1:05-CV-1948, on October 7, 2005), against its All-Risks Property and Business Interruption insurance carriers as a result of the insurance companies’ refusal to honor their insurance coverage obligation to pay the Partnership for certain expenses. These include the Partnership’s internal expenses and costs incurred for damage to, and loss of use of the pipeline, equipment, products, the extra transportation costs incurred for transporting the liquids while the pipeline was out of service, the reduced volumes of liquids that could be processed, and the costs of complying with the OPS Corrective Action Order (hydrostatic testing, repair/replacement and other pipeline integrity assurance measures). These expenses and costs have been expensed as incurred and any potential recovery from the All-Risks Property and Business Interruption insurance carriers will be treated as “other income” if and when they are received. The Partnership has not provided for a receivable for these claims because of the uncertainty as to whether and how much the Partnership will ultimately recover under these policies. The Partnership has also asserted that the cost of pipeline testing, replacement and repair are subject to an equitable sharing arrangement with the pipeline owner, pursuant to the terms of the pipeline lease agreement.

limited to those measured at the wellhead, that Plaintiff’s claims are without merit, and that MarkWest also may have overpaid Plaintiff based on, among other things, the wet versus dry Btu measurements. Discovery has just begun, and at this time, the Partnership is not able to predict the ultimate outcome of this matter. As a result, the Partnership has not provided for a loss contingency.

The Partnership acquired the Javelina gas processing, transportation and fractionation business located in Corpus Christi, Texas (the “Javelina Business”) on November 1, 2005. The Javelina Business was a party with numerous other defendants to three lawsuits brought by plaintiffs who had residences or businesses located near the Corpus Christi industrial area, an area which included the Javelina gas processing plant, and several petroleum, petrochemical and metal processing and refining operations. These suits, styled Victor Huff v. ASARCO Incorporated, et al. (Cause No. 98-01057-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in March 3, 1998); Hipolito Gonzales et al. v. ASARCO Incorporated, et al., (Cause No. 98-1055-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in 1998); Jason and Dianne Gutierrez, individually and as representative of the estate of Sarina Galan Gutierrez (Cause No. 05-2470-A, 28^TH Judicial District, severed May 18, 2005, from Gonzales v. Asarco Incorporated, above); and Jesus Villarreal v. Koch Refining Co. et al., (Cause No. 05-01977-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed April 27, 2005), set forth claims for personal injury or property damage, harm to business operations and nuisance type claims, allegedly incurred as a result of operations and emissions from the various industrial operations in the area. The Hipolito Gonzales action is subject to a settlement in principle reached in a mediation held December 9, 2005. The Partnership’s involvement and engagement in the other cases has been limited to this point, but the actions have been and are being vigorously defended and, based on initial evaluation and consultations, it appears at this time that these actions should not have a material impact on the Partnership.

In response to a shipper inquiry to the Federal Energy Regulatory Commission (“FERC”) regarding the Partnership’s Michigan Crude Pipeline, and following unsuccessful FERC-requested rate structure discussions with the shippers, FERC recently requested that we file a tariff. The Partnership filed on November 18, 2005 a tariff with FERC establishing a cost of service rate structure to be effective starting January 1, 2006. Two shippers and a producer filed a joint protest to the FERC filing with the Commission, and the Partnership filed a response to this joint protest vigorously defending its filing and opposing the protest. The Commission issued an order on December 29, 2005, rejecting the protestor’s request for interim rates and accepting the Partnership’s filing, and the new rates and rate structure became effective January 1, 2006. The Commission established hearing procedures for the tariff filing, but held them in abeyance pending the outcome of FERC sponsored settlement discussions, which the parties have been referred to under the FERC procedures. The Partnership and the shippers subsequently negotiated a settlement that resulted in the Partnership filing a new tariff which, for the most part, returns the rates to those in effect prior to the effective date of the November 18, 2005 tariff filing, and established such rates for a prospective three year period.

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

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 $5.9 million, $3.3 million and $1.1 million for the years ended December 31, 2005, 2004 and 2003, respectively. The minimum future lease payments under these operating leases as of December 31, 2005, are as follows (in thousands):

Year ending December 31,
2006	$	3,646
2007	1,919
2008	843
2009	416
2010	79
2011 and thereafter	203
Total	$	7,106

16. Related Party Transactions

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 several contracts with MarkWest Hydrocarbon. Specifically, the Partnership entered into:

• A gas-processing agreement in which MarkWest Hydrocarbon delivers to us for processing all natural gas it

receives from third-party producers. MarkWest Hydrocarbon pays us a monthly fee based on volumes delivered.

• A transportation agreement in which MarkWest Hydrocarbon delivers most of its NGLs to us for transportation through the pipeline to the Partnership’s Siloam fractionator. MarkWest Hydrocarbon pays us a monthly fee based on the number of gallons delivered to us.

• A fractionation agreement in which MarkWest Hydrocarbon delivers all of its NGLs to us for unloading, fractionation, loading and storage at the Partnership’s Siloam facility. MarkWest Hydrocarbon pays us a monthly fee based on the number of gallons delivered to us for fractionation, an annual storage fee, and a monthly fee based on the number of gallons of NGLs unloaded.

• A natural gas liquids purchase agreement in which MarkWest Hydrocarbon receives and purchases, and the Partnership delivers and sells, all of the NGL products the Partnership produces pursuant to the Partnership’s gas- processing agreement with a third party. Under the terms of this agreement, MarkWest Hydrocarbon pays us a purchase price equal to the proceeds it receives from the resale to third parties of the 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 remits the balance of the proceeds to this third party.

Under the Services Agreement with MarkWest Hydrocarbon, MarkWest Hydrocarbon continues to provide centralized corporate functions such as accounting, treasury, engineering, information technology, insurance and other services. The Partnership reimburses MarkWest Hydrocarbon monthly for the selling, general and administrative expenses. For the years ended December 31, 2005, 2004 and 2003, MarkWest Hydrocarbon charged approximately $6.9 million, $8.7 million and $5.3 million, respectively, for these expenses.

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, 2005, 2004 and 2003, these costs totaled $8.0 million, $9.1 million and $6.2 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 fees and percent-of-proceeds consideration for the first 10,000 Mcf/d 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, 2005, 2004 and 2003, MarkWest Hydrocarbon’s net profit interest was $0.0 million, $0.5 million and $0.9 million, respectively, which amounts are included in facility expenses.

17. Subsequent Event

On January 17, 2006, the Partnership filed a Form S-4 exchange offer registration statement related to the Senior Notes (see Note 10). The registration became effective February 3, 2006. The interest rate penalty (1% at December 31, 2005) on the Senior Notes will cease on March 7, 2006.

18. Segment Information

The Partnership is engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids and refinery off-gas; and the gathering and transportation of crude oil. The Partnership is a processor of natural gas in the northeastern and southwestern United States, processing gas from the Appalachian Basin, one of the country’s oldest natural gas-producing regions, and from East Texas, Gulf Coast and Michigan. Our chief operating decision maker is our chief executive officer (“CEO”). Our CEO reviews the Partnership’s discrete financial information on a geographic and operational basis, as the products and services are closely related within each geographic region and business operations. Accordingly, the CEO makes operating decisions, assesses financial performance and allocates resources on a segment basis. The Partnership’s segments are as follows:

Segment	Related Legal Entity	Products and services

Southwest
East Texas	MarkWest Energy East Texas Gas Company, L.P. MarkWest Pipeline Company, L.P.	Gathering, processing, pipeline, fractionation and storage

Oklahoma	MarkWest Western Oklahoma Gas Company, L.L.C.	Gathering and processing

Other Southwest	MarkWest Power Tex L.P. MarkWest Pinnacle L.P. MarkWest PNG Utility L.P. MarkWest Texas PNG Utility L.P. MarkWest Blackhawk L.P. MarkWest New Mexico L.P.	Gathering and pipeline

Gulf Coast
Gulf Coast	MarkWest Javelina Company MarkWest Javelina Pipeline Company MarkWest Javelina Pipeline Holding Company, L.P. MarkWest Javelina Holding Company, L.P.	Gathering, processing and pipeline

Northeast
Appalachia	MarkWest Energy Appalachia, L.L.C.	Processing, pipelines, fractionation and storage

Michigan	Basin Pipeline, L.L.C. West Shore Processing Company, L.L.C. MarkWest Michigan Pipeline Company, L.L.C.	Gathering, processing and crude oil transportation

The Partnership prepares business segment information in accordance with GAAP (see Note 1), except that certain items below the “Operating Income” line are not allocated to business segments, as management does not consider them in its evaluation of business unit performance. In addition, selling, general and administrative expenses are not allocated to individual business segments. Management evaluates business segment performance based on operating income before selling, general and administrative expenses. Revenues from MarkWest Hydrocarbon are reflected as revenue from Affiliates.

The table below presents information about operating income for the reported segments for the three years ended December 31, 2005, 2004 and 2003 (in thousands).

	East Texas		Oklahoma		Other Southwest		Appalachia		Michigan				Gulf Coast		Total
Year Ended December 31, 2005:
Revenues:
Unaffiliated parties	$	86,196	$	213,947	$	106,661	$	1,758	$	12,496			$	13,832	$	434,890
Affiliated parties	—		—		—		64,922		—				—		64,922
Total Revenues	86,196		213,947		106,661		66,680		12,496				13,832		499,812
Expenses:
Purchased product costs	39,024		193,787		92,602		38,435		3,030				—		366,878
Facility expenses	10,463		4,927		4,990		19,360		6,080				2,152		47,972
Depreciation	4,836		2,385		3,383		3,187		4,665				1,078		19,534
Amortization	8,293		—		68		—		—				1,295		9,656
Accretion	33		63		22		41		—				—		159
Operating income (loss) before selling, general and administrative expenses	$	23,547	$	12,785	$	5,596	$	5,657	$	(1,279		)	$	9,307	$	55,613
Capital expenditures	$	46,088	$	11,937	$	7,765	$	4,611	$	251			$	98	$	70,750
Total segment assets	$	324,231	$	75,576	$	98,345	$	55,436	$	50,560			$	441,945	$	1,046,093

Year Ended December 31, 2004:
Revenues:
Unaffiliated parties	$	21,932	$	133,636	$	69,464	$	1,632	$		15,624		$	—	$	242,288
Affiliated parties	—		—		—		59,026		—				—		59,026
Total Revenues	21,932		133,636		69,464		60,658		15,624				—		301,314
Expenses:
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
Impairment	—		—		—		130		—				—		130
Accretion	13		—		—		—		—				—		13
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:
Revenues:
Unaffiliated parties	$	—	$	7,855	$	46,669	$	1,278	$	11,778			$	—	$	67,580
Affiliated parties	—		—		—		49,850		—				—		49,850
Total Revenues	—		7,855		46,669		51,128		11,778				—		117,430
Expenses:
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				—		212,978

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

	Year Ended December 31,
	2005			2004			2003

Total segment revenue	$	499,812		$	301,314		$	117,430
Derivatives not allocated to segments	(728		)	—			—
Total revenue	499,084			301,314			117,430

Total segment operating income before selling, general and administrative expenses	55,613			40,530			17,439
Derivatives not allocated to segments	(728		)	—			—
Selling, general and administrative expenses not allocated to segments	(21,573		)	(16,133		)	(8,598		)
Income from operations	33,312			24,397			8,841

Interest income	367			87			14
Interest expense	(22,469		)	(9,236		)	(3,087		)
Amortization of deferred financing costs	(6,780		)	(5,236		)	(984		)
Loss from unconsolidated affiliates	(2,153		)	(65		)	-
Miscellaneous income (expense)	78			15			(25		)

Net income	$	2,355		$	9,962		$	4,759

19. Quarterly Results of Operations (Unaudited)

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

	Three Months Ended
	March 31		June 30		September 30		December 31
	(in thousands, except per unit amounts)
2005
Revenue	$	89,637	$	102,960	$	130,568	$	175,919
Income from operations	$	8,451	$	4,747	$	6,872	$	13,242
Net income (loss)	$	4,265	$	671	$	602	$	(3,183	)(a)
Limited partner’s share of net income (loss)	$	4,346	$	385	$	79	$	(4,568	)
Net income (loss) per limited partner unit:
Basic	$	0.41	$	0.04	$	0.01	$	(0.44	)
Diluted	$	0.41	$	0.04	$	0.01	$	(0.44	)

	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
Limited partner’s share of net income	$	2,162	$	3,027	$	802	$	4,694
Net income per limited partner unit:
Basic	$	0.32	$	0.43	$	0.10	$	0.46
Diluted	$	0.32	$	0.43	$	0.10	$	0.46

(a) The following items impacted 2005 fourth quarter results:

• Starfish: The path of Hurricane Rita was along the Starfish pipeline corridor. Onsite and aerial inspections indicated no material damage to platform facilities, and pipe integrity was not compromised. Sonar inspections showed significant damage to underwater pipe. Some structural damage appears to have occurred at the onshore Starfish dehydration and compressor facilities. The interruption in operations, however, resulted in significant fourth quarter losses for Starfish.

• East Texas: Under the terms of certain gathering contracts in our East Texas systems, we are required to buy gas based on a specific index price. Our typical process has been to sell our best estimate of the production at the same index price near the end of the prior month. Due to unexpected volatility and a corresponding lack of liquidity in the gas trading market at the end of October 2005, the Partnership was unable to sell all of its requirements at the same index price. As a result, the Partnership was not able to sell approximately 16,600 Mmbtu/day of gas from its Appleby and east Texas assets for November 2005. During the month of November, the Partnership sold the gas at a different index price, which was lower than the index purchase price for the month. The Partnership ended up with a negative impact to operating income from operations of approximately $2.5 million from the Appleby and

East Texas operations. The Partnership has implemented additional controls and procedures to mitigate a similar exposure going forward. The Partnership has sold 90% of its forecasted volumes through March 2006 at index price. The Partnership has also established firm guidelines to sell the remainder of forecast volumes earlier in the preceding month to reduce the risk of encountering unexpected market conditions that preclude these types of index sales.

• Under the terms of the keep-whole agreements in the Partnership’s western Oklahoma System, the Partnership purchases gas to replace the shrink and fuel requirements under those arrangements. The Partnership then sells the natural gas liquids processed at the Foss Lake plant. The continued strong pricing environment for natural gas liquids coupled with the decline in mid-continental natural gas prices in November, that contributed to the negative impact to operations in East Texas and Appleby, resulted in higher than expected margins in the Partnership’s western Oklahoma System of approximately $1.0 million.

• Commodity prices experienced extreme volatility in the fourth quarter, with natural gas achieving some of the highest settlements on record. In addition, NGL prices were increasing steadily during the fourth quarter.

20. Valuation and Qualifying Accounts

Activity in the allowance for doubtful accounts is as follows (in thousands):

	Year Ended December 31,
	2005			2004			2003
Balance at beginning of period	$	211		$	80		$	—
Charged to costs and expenses	42			211			80
Deductions (Collections)	(102		)	(80		)	—
Balance at end of period	$	151		$	211		$	80

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

On September 20, 2005, the Partnership dismissed KPMG as its registered independent accounting firm. The Registrant’s Audit Committee made the decision to change independent accountants and that decision was approved, ratified and adopted by the Partnership’s Board of Directors.

The report of KPMG on the consolidated financial statements as of and for the year ended December 31, 2004, contained no adverse opinion or disclaimer of opinion and was not qualified or modified as to uncertainty, audit scope or accounting principle. The audit report of KPMG on management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting as of December 31, 2004, did not contain an adverse opinion or disclaimer of opinion, and was not qualified or modified as to uncertainty, audit scope or accounting principles, except that KPMG’s report indicates that the Partnership did not maintain effective internal control over financial reporting as of December 31, 2004, because of the effect of material weakness on the achievement of the objectives of the control criteria and contains an explanatory paragraph that states that the following material weaknesses have been identified and included in management’s assessment:

• Ineffective control environment

• Insufficient technical accounting expertise, inadequate policies and procedures related to accounting matters, and inadequate management review in the financial reporting process

• Inadequate personnel, processes and controls at the Partnership’s Southwest Business Unit

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

In connection with its audit for the year ended December 31, 2004, and the subsequent interim period through September 20, 2005, there were no disagreements with KPMG 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 KPMG would be expected to cause them to make reference thereto in their reports on financial statements for such year.

During the two most recent fiscal years and through September 20, 2005, except as noted in this paragraph, there have been no “Reportable Events” (as defined in Regulation S-K, Item 304(a)(1)(v)). In conjunction with KPMG’s audit of the consolidated financial statements for the year ended December 31, 2004, KPMG communicated to the Partnership’s Audit Committee the existence of material weaknesses related to (i) ineffective control environment, (ii) insufficient technical accounting expertise, inadequate policies and procedures related to accounting matters, and inadequate management review in the financial reporting process, (iii) inadequate personnel, processes and controls at our Southwest Business Unit, and (iv) inadequately designed controls and procedures over property, plant and equipment. Information regarding these deficiencies is incorporated herein by reference to Item 9A (Controls and Procedures) of the Registrant’s Form 10-K filed with the Securities and Exchange Commission on June 24, 2005.

On September 20, 2005, the Partnership engaged Deloitte & Touche LLP as the Registrant’s independent registered public accounting firm for the year ending December 31, 2005, and to perform procedures related to the financial statements included in the Partnership’s quarterly reports on Form 10-Q, beginning with the quarter ended September 30, 2005. The Audit Committee made the decision to engage Deloitte & Touche and that decision was then approved, adopted and ratified by the Partnership’s Board of Directors. The Partnership has not consulted with Deloitte & Touche during its two most recent fiscal years or during any subsequent interim period prior to its appointment as auditor regarding either (i) 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 Registrant’s consolidated financial statements, and neither a written report was provided to the Partnership nor oral advice was provided that Deloitte & Touche concluded was an important factor considered by the Partnership in reaching a decision as to the accounting, auditing or financial reporting issue; or (ii) any matter that was either the subject of disagreement (as defined in Item 304(a)(1)(iv) of Regulation S-K and the related instructions) or a reportable event (within the meaning of Item 304(a)(1)(v) of Regulation S-K).

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 report of PricewaterhouseCoopers LLP on the consolidated financial statements for the year ended

December 31, 2003, contains no adverse opinion or disclaimer of opinion and was not qualified or modified as to uncertainty, audit scope, or accounting principle.

In connection with its audit for the fiscal year ended December 31, 2003, 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 report on the financial statements for the fiscal year ended December 31, 2003.

During the fiscal year 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).

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) are controls and other procedures that are designed to provide reasonable assurance that the information that we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

In connection with the preparation of this Annual Report, our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2005. In making this evaluation, our management considered material weaknesses discussed below. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of December 31, 2005.

In light of the material weaknesses described below, through the date of the filing of this Form 10-K, we have adopted remedial measures to address the deficiencies in our internal controls that existed on December 31, 2005. In addition, we have applied compensating procedures and processes as necessary to ensure the reliability of our financial reporting. Such additional procedures include detailed management review of account reconciliations for all accounts in all business units and multiple level management review of accounting treatment for significant non-routine transactions. Accordingly, management believes that the consolidated financial statements included in this Annual Report present fairly, in all material respects, our financial condition, results of operations and cash flows as of, and for, the periods presented in conformity with GAAP.

MANAGEMENT’S REPORT ON INTERNAL CONTROLS OVER FINANCIAL REPORTING

Management of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. The Partnership’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 in the United States of America and includes those policies and procedures that:

• pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Partnership;

• 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 Partnership are being made only in accordance with authorizations of management and directors of the Partnership; and

• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Partnership’s assets that could have a material effect on the financial statements.

Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.

Management assessed the effectiveness of our internal controls over financial reporting as of December 31, 2005. In making this assessment, management used the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).

A material weakness is a significant deficiency (within the meaning of PCAOB Auditing Standard No. 2), or combination of significant deficiencies, that result in there being a more than remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

As reported in Item 9 of the Partnership’s 2004 Form 10-K, material weaknesses existed as of December 31, 2004, related to 1) ineffective control environment, 2) insufficient technical accounting expertise, inadequate policies and procedures related to accounting matters, and inadequate management review in the financial reporting process, 3) Inadequate personnel, processes, and controls at our Southwest Business Unit, and 4) Inadequately designed controls and procedures over property, plant and equipment.

While the Partnership has undertaken numerous steps in an effort to remediate its material weaknesses, as discussed under remediation plans below, in connection with management’s current year assessment, management has identified the following material weaknesses that existed at December 31, 2005:

Internal Control Environment – The Partnership’s control environment did not sufficiently promote effective internal control over financial reporting through the management structure to prevent a material misstatement, as was evidenced by deficiencies or significant deficiencies in the following areas:

• Segregation of duties within certain key processes was inadequate to support management’s assertions with respect to accuracy and completeness of financial records.

• Entity level controls including the anti-fraud program and controls necessary to address the COSO elements of risk assessment, information and communication.

• Application controls over financially significant applications with respect to change management and information systems operations.

• Fixed assets controls including instances of inappropriate authorization of invoices and improper reconciliation procedures.

• Financial reporting controls related to the closing process, including control over non-routine transactions, unusual journal entries and the use of estimates and judgment.

• Controls over expenditures including instances of inappropriate authorization of invoices and the inability to independently validate accuracy and validity of amounts recorded.

• Spreadsheet controls related to change management within key financial spreadsheets.

Risk Management and Accounting for Derivative Financial Instruments – The Partnership did not have adequate internal controls and processes in place to support management’s assertions with respect to the completeness, accuracy and validity of commodity transactions. The design of internal controls over commodity transactions did not support independent validation of data or control and review of transacting activity. In particular, personnel responsible for executing and entering transactions into commodity accounting systems also have duties that are not compatible with transaction execution and entry.

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

Conclusion:

Because of the material weaknesses described above, management has concluded that, as of December 31, 2005, the Partnership did not maintain effective internal control over financial reporting.

The Partnership’s independent registered public accounting firm has issued an attestation report on management’s assessment of the Partnership’s internal control over financial reporting, which appears on page 97.

Date: March 16, 2006	By:	/S/FRANK M. SEMPLE
		Frank M. Semple
		Chief Executive Officer


Date: March 16, 2006	By:	/S/JAMES G. IVEY
		James G. Ivey
		Chief Financial Officer

Changes in Internal Control Over Financial Reporting

No changes were made to internal control that affected management’s assertions about our internal control over financial reporting. Specific changes that have occurred and further planned changes are discussed below under the heading “Remediation of Material Weaknesses in Internal Controls.”

Internal Control Over Financial Reporting for the Years Ended December 31, 2004 and 2003

In addition to the material weaknesses described above, we and KPMG LLP, our independent registered public accounting firm at that time, identified material weaknesses in our internal control over financial reporting as of December 31, 2004. Additionally, PwC, our independent registered public accounting firm at the time, identified certain deficiencies in our internal accounting controls as of December 31, 2003. Considered collectively, these deficiencies may have constituted a material weakness in our internal controls pursuant to standards established by the American Institute of Certified Public Accountants.

Year Ended December 31, 2003

PwC identified certain deficiencies in our internal accounting controls as of December 31, 2003. The identified deficiencies included the following:

• a possible insufficiency in the personnel resources available to adequately maintain our financial reporting obligations as a public company;

• inadequate implementation of uniform controls over certain acquired entities and operations;

• inadequate control over classification of certain fixed asset balances and processes for accrual of certain accounts payable; and

• potential need for separation of certain duties between payroll and other accounting personnel.

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

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

Year Ended December 31, 2004

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

• Ineffective control environment;

• Insufficient technical accounting expertise, inadequate policies and procedures related to accounting matters, and inadequate management review in the financial reporting process;

• Inadequate personnel, processes and controls at our Southwest Business Unit; and

• Inadequately designed controls and procedures over property plant and equipment.

Ineffective control environment. Our control environment did not sufficiently promote effective internal control over financial reporting throughout our management structure, and this material weakness was a contributing factor in the development of other material weaknesses described below. Principal contributing factors included the lack of adequate personnel with sufficient expertise to perform accounting functions necessary to ensure preparation of financial statements in accordance with generally accepted accounting principles, and a lack of adequate policies and procedures to enable the timely preparation of reliable financial statements, as described more fully below. We believe that this material weakness developed as a result of our rapid expansion in 2003 and 2004. The steps we have taken to remediate this material weakness are described in detail below.

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

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

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

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

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

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

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

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

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

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

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

These material weaknesses in internal control over financial reporting resulted in misstatements of cash; receivables; other current assets; property, plant and equipment; accumulated 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, we restated our financial statements for the first three quarters of 2004. These misstatements, which were considered material in the aggregate, were corrected prior to issuance of our audited financial statements for the year 2004.

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

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

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

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

These issues were identified late in 2004 and early in 2005. At that time, our resources were focused on completing the outstanding filings and the associated restatements, and we did not have additional

resources to focus on standardizing and implementing new policies and procedures. The steps we have taken to remediate this material weakness are described in detail below.

Remediation of Material Weaknesses in Internal Control

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

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

• In November 2005, we hired a new chief accounting officer with significant public company audit, accounting and financial reporting experience and technical expertise. The chief accounting officer now reports directly to our chief executive officer.

• In the third and fourth quarters of 2005, we hired additional external reporting, tax and accounting staff to supplement our existing technical accounting resources and mitigate segregation of duties deficiencies.

• In July 2005, we hired a Vice President of Risk and Compliance with a strong public company risk management, compliance and audit background. This individual is responsible for coordinating our internal audit and internal control compliance efforts.

• In the third and fourth quarters of 2005, we established an internal audit function and staffed it through an outsourcing and technical consultation arrangement with a professional accounting and consulting firm.

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

• We formalized the monthly account reconciliation process for all balance sheet accounts and have implemented a formal review of reconciliations by our business unit accounting management.

• We established a compliance office focused on control deficiency identification and remediation, i.e., purchasing controls, revenue recognition controls and application and spreadsheet change controls that performs ongoing internal control evaluation and assessment and works actively with the process owners in developing appropriate remediation of control deficiencies.

• We conducted an entity-level risk assessment, established an internal audit plan and began to execute that internal audit plan. Results are reported directly to our general partner’s audit committee.

• We enhanced entity level controls through the implementation of significant new controls.

• We strengthened our disclosure review committee charter to solicit and review input from management personnel throughout the Partnership regarding possible instances of fraud or significant events requiring disclosure.

• We implemented a technical accounting issues forum to address non-routine transactions and the use of critical estimates and judgment.

The steps taken to remediate the material weaknesses described above were not completed until the latter part of 2005 because our resources had been directed towards the restatements of our financial statements. As a result, the identified internal control weaknesses persisted throughout 2005. While we believe we have substantially improved our organizational capabilities, the full impact of the changes had not been realized by December 31, 2005.

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

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

Remediation of Material Weakness Related to Risk Management and Accounting for Derivative Financial Instruments.

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

• Vice President of Risk and Compliance, to oversee and ensure improvements in our commodity transaction verification and monitoring capabilities; and

• Director of Risk Management and staff to establish appropriate verification and monitoring activities associated with our commodity transactions.

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

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

• We are enhancing employee awareness of our Code of Conduct, ethics and anti-fraud policies, including a revised training program to be delivered to all employees in 2006. This includes heightened awareness of the ethics hotline availability and access options.

• We are conducting a detailed review and re-documentation of all of our control processes and will undertake significant control design changes to ensure that all control objectives are met.

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that MarkWest Energy Partners, L.P. and subsidiaries (the “Partnership”) did not maintain effective internal control over financial reporting as of December 31, 2005, because of the effect of the material weaknesses identified in management’s assessment based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management’s Report on Internal Control over Financial Reporting, management excluded from their assessment the internal control over financial reporting at Javelina Company, Javelina Pipeline Company, Javelina Land Company L.L.C. (the “Gulf Coast Business Unit”), which was acquired on November 1, 2005, because the Gulf Coast Business Unit was acquired very late in the year, management did not include internal control processes for the Gulf Coast Business Unit in its assessment of internal controls as of December 31, 2005. The Gulf Coast Business Unit constitutes 3% percent and 42% percent of net and total assets, respectively, and 3% percent of total revenues of the consolidated financial statement amounts as of and for the year ended December 31, 2005. Accordingly, our audit did not include the internal control over financial reporting at the Gulf Coast Business Unit. The Partnership’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 opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel 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.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a significant deficiency, or combination of significant 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:

Internal Control Environment – The Partnership’s control environment did not sufficiently promote effective internal control over financial reporting through their management structure to prevent a material misstatement, as was evidenced by deficiencies or significant deficiencies in the following areas:

• Segregation of duties within certain key processes was inadequate to support management’s assertions with respect to accuracy and completeness of financial records.

• Entity level controls including the anti-fraud program and controls necessary to address the COSO elements of risk assessment, information and communication.

• Application controls over financially significant applications with respect to change management and information systems operations.

• Fixed assets controls including inappropriate authorization of invoices and improper reconciliation procedures.

• Financial reporting controls related to the closing process including control over non-routine transactions, unusual journal entries and the use of estimates and judgment.

• Controls over expenditures including inappropriate authorization of invoices and the inability to independently validate accuracy and validity of amounts recorded.

• And, spreadsheet controls related to change management within key financial spreadsheets.

Risk Management and Accounting for Derivative Financial Instruments – The Partnership did not have adequate internal controls and processes in place to support management’s assertions with respect to the completeness, accuracy and validity of commodity transactions. The design of internal controls over commodity transactions did not support independent validation of data or control and review of transacting activity. In particular, personnel responsible for executing and entering transactions into commodity accounting systems also have duties, which are not compatible with transaction execution and entry.

The material weaknesses result from both a deficiency in the design of internal controls, as well as, a deficiency in the operating effectiveness of key controls relied on by management. The design deficiencies primarily represent situations where control activities did not exist to meet control objectives necessary to support the financial statement assertions. Operating effectiveness deficiencies were, in many cases, a result of the Partnership’s control activities that were not performed adequately to address the control objective. The significant turnover of accounting personnel in the fourth quarter of 2005 was a contributing factor in the failure of key control activities to operate effectively. As a result of the pervasive nature of the material weaknesses, the risk exists that the Partnership’s financial reporting processes and controls may not identify a material misstatement in the consolidated financial statements.

These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the consolidated financial statements as of and for the year ended December 31, 2005, of the Partnership and this report does not affect our report on such financial statements.

In our opinion, management’s assessment that the Partnership did not maintain effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, because of the effect of the material weaknesses described above on the achievement of the objectives of the control criteria, the Partnership has not maintained effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2005, of the Partnership and our report dated March 16, 2006 expressed an unqualified opinion on those financial statements.

/s/	DELOITTE & TOUCHE LLP

Denver, Colorado
March 16, 2006

ITEM 9B. OTHER INFORMATION

None.

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 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. Whenever possible, however, 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 those 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. Committee members 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, as well as 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 of our general partner 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 of our general partner 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 directs its officers to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs.

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

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

Name	Age	Position with our General Partner	Director Since

John M. Fox	65	Chairman of the Board of Directors	2002
Keith E. Bailey	63	Director	2005
Charles K. Dempster	63	Director	2002
Donald C. Heppermann	63	Director	2002
William A. Kellstrom	64	Director	2002
William P. Nicoletti	60	Director	2002
Frank M. Semple	54	President, Chief Executive Officer and Director	2003
C. Corwin Bromley	48	Vice President, General Counsel and Secretary	NA
James G. Ivey	54	Senior Vice President, Chief Financial Officer	NA
Nancy K. Masten	36	Senior Vice President, Chief Accounting Officer	NA
John C. Mollenkopf	44	Senior Vice President, Southwest Business Unit	NA
Randy S. Nickerson	44	Senior Vice President, Corporate Development	NA
Richard A. Ostberg	40	Vice President, Risk and Compliance	NA
Andrew L. Schroeder	47	Vice President, Finance and Treasurer	NA
David L. Young	46	Senior Vice President, Northeast Business Unit	NA

John M. Fox has served as MarkWest Hydrocarbon’s Chairman of the Board of Directors since its inception in April 1988, and in the same capacity for the general partner of MarkWest Energy since May 2002. Mr. Fox also served as President and Chief Executive Officer of MarkWest Hydrocarbon and the general partner of MarkWest Energy 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.

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. He currently serves on the boards of directors of Apco Argentina Inc., Associated Electric & Gas Insurance Services Limited (Aegis) and Peoples Energy Corporation. Mr. Bailey holds a bachelor’s degree in mechanical engineering from the Missouri School of Mines and Metallurgy.

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, 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 served as Executive Vice President, Chief Financial Officer and Secretary of MarkWest Hydrocarbon, Inc. and the general partner of MarkWest Energy since October 2003 until his retirement in March 2004. Mr. Heppermann joined MarkWest Hydrocarbon and the general partner of the Partnership in November 2002 as Senior Vice President and Chief Financial Officer, and served as Senior Executive Vice President beginning in January 2003. Mr. Heppermann has served as a member of the Company’s Board of Directors since November 2002 and the general partner of the Partnership’s board of directors since its inception in May 2002. He also serves as Chairman of the Finance Committee. Prior to joining MarkWest Hydrocarbon and the general partner of MarkWest Energy, Mr. Heppermann was a private investor and career executive in the energy industry with responsibilities in operations, finance, business development and strategic planning. From 1990 to 1997, Mr. Heppermann 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 Vice President of Finance for Pinnacle West Capital Corporation, the holding company for Arizona Public Service Company. From

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1965 to 1987, Enron Corporation and its predecessors employed Mr. Heppermann in a variety of positions, including Executive Vice President, Gas Pipeline Group.

William A. Kellstrom has served as a member of the Board of Directors of MarkWest Hydrocarbon since May 2000 and the general partner of MarkWest Energy since its inception in May 2002. 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 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 Surge Global Energy, Inc. Mr. Nicoletti is a graduate of Seton Hall University and received an MBA from Columbia University Graduate School of Business.

Frank M. Semple was appointed as President of both MarkWest Hydrocarbon and the general partner of MarkWest Energy on November 1, 2003. Mr. Semple also became Chief Executive Officer of both MarkWest Hydrocarbon and the general partner of MarkWest Energy on January 1, 2004. Prior to his appointment, Mr. Semple served in various capacities, most recently as Chief Operating Officer of 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, 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 also served on the board of directors for PowerTel Communications and the Competitive Telecommunications Association (Comptel). 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. Mr. Semple holds a Mechanical Engineering degree from the United States Naval Academy and is a professional engineer registered in the state of Kansas.

C. Corwin Bromley has served as Vice President, General Counsel and Secretary of both MarkWest Hydrocarbon and the general partner of MarkWest Energy 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 & 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 the general partner of MarkWest Energy since June 2004. Prior to joining the Company, Mr. Ivey served as Treasurer of The Williams Companies from 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 retired in early 2004 from the Army Reserve with the rank of colonel. Mr. Ivey is a graduate of Texas A&M University and has an MBA from the University of Houston. He is also a graduate of the Army Command and General Staff College.

Nancy K. Masten was appointed Chief Accounting Officer of both MarkWest Hydrocarbon and the general partner of MarkWest Energy in November 2005. Previous to her appointment, Ms. Masten was the Chief Financial Officer for Experimental and Applied Sciences (“EAS”) in Golden, Colorado. EAS is a wholly owned subsidiary of the Ross Product Division of Abbott Laboratories. Prior to her employment at EAS, Ms. Masten was a Vice President with TransMontaigne Inc. in Denver, Colorado. Preceding this appointment, Ms. Masten was a Partner with Ernst & Young LLP, having spent time in the firm’s Denver, London, New York and Washington, D.C. offices.

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John C. Mollenkopf was appointed Senior Vice President, Southwest Business Unit, of MarkWest Hydrocarbon and the general partner of MarkWest Energy in January 2004. Previously he served as Vice President, Business Development of the Company since January 2003. Prior to that, he served as Vice President, Michigan Business Unit, of MarkWest Energy’s 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.

Randy S. Nickerson has served as Senior Vice President, Corporate Development of MarkWest Hydrocarbon and MarkWest Energy’s general partner since October 2003. Prior to that, Mr. Nickerson served as Executive Vice President, Corporate Development of the Partnership’s general partner since January 2003 and as Senior Vice President of the Partnership’s 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.

Richard A. Ostberg was appointed the Vice President of Risk and Compliance of MarkWest Hydrocarbon and the general partner of MarkWest Energy in July 2005. Prior to that, Mr. Ostberg served as Vice President and Controller of Black Hills Energy. Prior to Black Hills, Mr. Ostberg spent four years with Pacific Minerals, Inc, the operator of the Bridger Coal mine and spent eight years with Deloitte & Touche in their audit practice, including two years consulting from his national office assignment in Washington, D.C.

Andrew L. Schroeder has served as Vice President and Treasurer of MarkWest Hydrocarbon and the Partnership’s 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. He is a Certified Public Accountant licensed in the state of Colorado.

David L. Young was appointed Senior Vice President, Northeast Business Unit of MarkWest Hydrocarbon and the Partnership’s 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. 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.

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. Bailey is financially sophisticated and qualifies as an “audit committee financial expert” within the meaning of the regulations of the SEC.

Audit Committee Pre-Approval Policy

The Audit Committee pre-approves all audit and permissible non-audit services provided by the independent auditors on a case-by-case basis. These services may include audit services, audit-related services, tax services and other services. Our Chief Accounting Officer is responsible for presenting the Audit Committee with an overview of all proposed audit, audit-related, tax or other non-audit services to be performed by the independent auditors. The presentation must be in sufficient detail to define clearly the services to be performed. The Audit Committee does not delegate its responsibilities to pre-approve services performed by the independent auditor to management or to an individual member of the Audit Committee. The Audit Committee may, however, from time to time delegate its authority to the Audit Committee Chairman, who reports on the independent auditor services approved by the Chairman at the next Audit Committee meeting.

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Code of Conduct and Ethics

We have adopted a Code of Conduct and Ethics that 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. This 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 Partnership. SEC regulations also require directors, executive officers and greater than 10% unitholders to furnish us with copies of all Section 16(a) reports they file.

To our knowledge, based solely on review of the copies of such reports furnished to us and written representations that no other reports were required, we believe our directors, executive officers and greater than 10% unitholders complied with all Section 16(a) filing requirements during the year ended December 31, 2005, 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. Bailey	1	0	1
Mr. Ivey	1	0	1
Mr. Ostberg	1	1	0
Mr. Young	2	0	2
Mr. Dempster	1	0	1
Mr. Heppermann	1	0	1
Mr. Nicoletti	2	0	2
Mr. Kellstrom	1	0	1
Ms. Marle	1	1	0
Mr. Dickerson	1	1	0

ITEM 11. EXECUTIVE COMPENSATION

The Partnership has no employees. The officers of our general partner manage the Partnership. 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 2005, 2004 and 2003 by each person who served as Chief Executive Officer of our general partner in 2005 and the four other highest-paid officers, whose salary and bonus exceeded $100,000 for services rendered during 2005.

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 selling, 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	2005	$	288,462	$	143,000	$	84,280	$	22,634	$	20,550
President and Chief Executive	2004	280,385		47,250		108,750		20,500		52,838
Officer	2003	36,346		6,413		279,000		4,800		623

James G. Ivey (6)	2005	$	218,846	$	60,000	$	27,567	$	21,661	$	18,965
Chief Financial Officer	2004	126,154		5,979		251,500		8,640		37,408
	2003	—		—		—		—		—

Randy S. Nickerson	2005	$	188,846	$	97,000	$	41,088	$	9,536	$	19,677
Senior Vice President, Corporate	2004	181,155		30,625		108,750		5,363		13,686
Development	2003	164,743		23,515		26,875		10,675		13,193

John C. Mollenkopf	2005	$	184,231	$	95,000	$	41,088	$	6,336	$	19,400
Sr. Vice President, Southwest	2004	180,865		30,625		65,250		6,703		13,426
Business Unit	2003	144,354		20,684		59,475		11,985		12,331

David L. Young (7)	2005	$	181,462	$	72,000	$	34,717	$	7,699	$	8,077
Senior Vice President, Northeast	2004	161,538		25,521		77,000		4,380		—
Business Unit	2003	—		—		—		—		—

(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 MarkWest Energy restricted unit awards plus the MarkWest Hydrocarbon restricted share awards (calculated by multiplying the closing market price of the corresponding securities on the date of grant by the number of units or shares awarded). As of December 31, 2005, the named executives held an aggregate of 14,083 restricted units and 5,279 restricted shares with an aggregate market value of $770,205.

(4) Represents distributions received for restricted units and restricted shares.

(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, in 2004, 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 $220,000.

(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 $185,000.

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. It 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

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employee shall be entitled to receive base salary and continued medical benefits for a period ranging from six months to twenty-four months, depending upon the employee’s status at the time of the termination. In the case of (iv) above, the employee shall be entitled to receive base salary for a period ranging from one month to six months and continued medical benefits for a period ranging from one month to six months. In either case, the aggregate amount of benefits paid to an employee shall in no event exceed twice the employee’s annual compensation during the year immediately preceding the termination.

Employment Agreement

Frank M. Semple

Mr. Semple entered into an executive employment agreement with MarkWest Hydrocarbon on November 1, 2003, pursuant to which Mr. Semple serves as MarkWest Hydrocarbon’s President and Chief Executive Officer and pursuant to which the Board of Directors of MarkWest Hydrocarbon appointed Mr. Semple to serve as the President and Chief Executive Officer of our general partner. The employment agreement 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 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 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 received no 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 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 27, 2006, the Board of Directors of the general partner approved director compensation for 2006. Each non-officer/employee director will receive an annual retainer of $20,000 and 500 restricted units per year. Chairs of the Audit Committee, Conflicts Committee and Compensation Committee will receive an additional annual retainer of $4,000, $2,000 and $2,000, respectively. In addition, each non-officer/employee director will receive compensation of $2,000 for either in-person or telephonic attendance at meetings of the board of directors. Members of committees will receive $1,000 for each meeting.

Previously, each independent director received an annual retainer of $12,000 and 500 restricted units per year. In addition, each non-officer/employee 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.

Each 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

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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 the long-term value of the Partnership. This incentive is intended to reward, motivate and retain the services of executive employees.

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 of which may be awarded in the form of restricted units. At December 31, 2005, the Partnership had granted 38,864 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 combination of cash compensation and restricted units that would be required from a

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competitive point of view to retain the services of a valued executive officer.

CEO Compensation

In January 2006, the Compensation Committee established the Chief Executive Officer’s 2006 annual base salary at $350,000. 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 his 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

PERFORMANCE GRAPH

Source: FactSet.

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

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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, 2005, 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.

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	38,864	—		400,825

Total	38,864	$	—	400,825

(1) The amount in column (a) of this table reflects only restricted units granted but not vested as of December 31, 2005. No unit options have been granted. No value is shown in column (b) of the table, since the restricted units do not have an exercise price.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT - UPDATE

The following table sets forth the beneficial ownership of units as of December 31, 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)	836,162	—		1,633,334	90.7	%	19.2	%
John M. Fox (3)	44,731		*	1,637,384	91.0	%	23.7	%
Kayne Anderson Capital Advisors, L.P (4)
1800 Avenue of the Stars, Second Floor Los Angeles, CA 90067	1,670,380	15.1	%	—	—		13.0	%
Richard A. Kayne (4)
1800 Avenue of the Stars, Second Floor Los Angeles, CA 90067	1,670,380	15.1	%	—	—		13.0	%
Tortoise Capital Advisors L.L.C. (5)
10801 Mastin Boulevard, Suite 222 Overland Park, KS 66210	966,704	8.3	%	—	—		7.2	%
Tortoise Energy Infrastructure Corporation (5)
10801 Mastin Boulevard, Suite 222 Overland Park, KS 66210	805,810	7.3	%	—	—		6.3	%
Tortoise MWEP, L.P.	—	—		166,666	9.3	%	1.3	%
Frank M. Semple	13,734		*			*
James G. Ivey	3,151		*	—	—			*
Randy S. Nickerson	12,495		*			*
John C. Mollenkopf	7,936		*			*
David L. Young	136		*	—	—			*
Keith E. Bailey	2,000		*	—	—			*
Donald C. Heppermann	11,667		*			*		*
William A. Kellstrom	4,042		*	—	—			*
William P. Nicoletti	3,542		*	—	—			*
Charles K. Dempster	1,542		*	—	—			*
All directors and executive officers as a group (11 persons)	68,525		*	1,637,384	91.0	%	24.2	%

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* 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 1,633,334 subordinated units owned by MarkWest Hydrocarbon and its subsidiaries, and approximately 4,050 subordinated units owned by Tortoise MWEP, L.P. in which Mr. Fox owns an equity interest. As of December 31, 2005, Mr. Fox beneficially owned approximately 43% of the voting securities of MarkWest Hydrocarbon. Mr. Fox currently serves as MarkWest Hydrocarbon’s Chairman of the Board. Mr. Fox resigned as President of MarkWest Hydrocarbon effective November 1, 2003, and as Chief Executive Officer effective January 1, 2004. As a result, Mr. Fox may be deemed to be the beneficial owner of the subordinated units owned by MarkWest Hydrocarbon.

(4) Information is based solely on a Schedule 13G filed with the Securities and Exchange Commission by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne, on February 9, 2006, with respect to units held as of December 31, 2005. The Schedule 13G indicates that Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne have shared voting power and dispositive power with respect to 1,670,380 units. The reported units are owned by investment accounts managed, with discretion to purchase or sell securities, by Kayne Anderson Capital Advisors, L.P., as a registered investment advisor. Kayne Anderson Capital Advisors, L.P. is the general partner of the limited partnerships and investment adviser to the other accounts. Richard A. Kayne is the controlling shareholder of the corporate owner of Kayne Anderson Investment Management, Inc., the general partner of Kayne Anderson Capital Advisors, L.P. Mr. Kayne is also a limited partner of each of the limited partnerships and a shareholder of the registered investment company. Kayne Anderson Capital Advisors, L.P. disclaims beneficial ownership of the units reported, except those units attributable to it by virtue of its general partner interests in the limited partnerships. Mr. Kayne disclaims beneficial ownership of the units reported, except those units held by him or attributable to him by virtue of his limited partnership interests in the limited partnerships, his indirect interest in the interest of Kayne Anderson Capital Advisors, L.P. in the limited partnership, and his ownership of common units of the registered investment company.

(5) 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. Despite its delegation of investment and voting power to TCA, however, TYG may be deemed to be the beneficial owner under Rule 13d-3 of the Securities and Exchange Act of 1940, of the securities it owns of record because it has the right to acquire investment and voting power through termination of the Investment Advisory Agreement. Thus, TCA and TYG have reported that they share voting power and dispositive power over the securities owned of record by TYG. TCA also acts as an investment advisor to certain managed accounts. Under contractual agreements with individual account holders, TCA, with respect to the securities held in the managed accounts, shares investment and voting power with certain account holders, and has no voting power but shares investment power with certain other account holders. TCA may be deemed the beneficial owner 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.

The following table sets forth the beneficial ownership of our general partner as of December 31, 2005, held by

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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.	89.3	%
John M. Fox (1)	90.9
Frank M. Semple	2.0
James G. Ivey	0.5
Randy S. Nickerson	1.6
John C. Mollenkopf	1.6
David L. Young	—
Keith E. Bailey	—
Donald C. Heppermann	1.0
William A. Kellstrom	—
William P. Nicoletti	—
Charles K. Dempster	—
All directors and executive officers as a group (11 persons)	97.6

(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, 2005, Mr. Fox beneficially owned approximately 43% of the voting securities of MarkWest Hydrocarbon. Mr. Fox currently serves as MarkWest Hydrocarbon’s Chairman of the Board. Mr. Fox resigned as President of MarkWest Hydrocarbon effective November 1, 2003, and as Chief Executive Officer effective January 1, 2004. As a result, Mr. Fox may be deemed to be the beneficial owner of the ownership interests owned by MarkWest Hydrocarbon.

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 March 1, 2006, affiliates of MarkWest Hydrocarbon, in the aggregate, owned a 21% interest in the Partnership, consisting of 836,162 common units, 1,633,334 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.

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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;

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

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

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

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

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.

Gas-Processing Agreement

At 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 has 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:

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• 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 adjusted on each anniversary of the effective date to reflect changes in the Producers Price Index for Oil and Gas Field Services.

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

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

We will also pay MarkWest Hydrocarbon a penalty of $5,000 per day (unless MarkWest Hydrocarbon can establish actual damages in excess of $5,000 per day) if we fail to process the natural gas at any of our processing plants to meet the agreed specifications, or interrupt the NGL production process, unless the reason for the failure or interruption is:

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

• conditions of force majeure; or

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

If we interrupt processing at any of our processing plants for any reason for 30 consecutive days without making a good-faith effort to resume processing as soon as reasonably possible, or, 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

At 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

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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 NGLs acquired from our Kenova processing facility, and any 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.

In return, 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 fee is 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 incidental losses incurred at our facilities, or the losses or gains due to variations in measurement equipment.

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

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

Fractionation, Storage and Loading Agreement

At 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 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 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 gallons unloaded. A portion of each of the above fees is 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 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

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

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

Natural Gas Liquids Purchase Agreement

At 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.

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 also 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 and the Partnership as a named insured MarkWest Hydrocarbon’s policy.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND EXPENSES

For the year ended December 31, 2005 and 2004, Deloitte & Touche LLP’s and KPMG LLP’s accounting fees and services (in thousands) were as follows:

	2005		2004
Audit fees	$	2,555	$	1,723
Audit-related fees (1)	526		92
Tax fees	—		—
All other fees (2)	—		—

Total accounting fees and services	$	3,081	$	1,815

(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) 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 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:

Schedule A — Significant Subsidiary Financial Statements — Starfish Pipeline Company, LLC

All omitted schedules have been omitted because they are not required or because the required information is contained in the financial statements or notes thereto.

Schedule A — Significant Subsidiary Financial Statements — Starfish Pipeline Company, LLC

Starfish Pipeline Company, LLC

Consolidated Financial Statements

December 31, 2005 and 2004

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Starfish Pipeline Company, LLC
Index
December 31, 2005 and 2004

Report of Independent Auditors

Consolidated Financial Statements

Balance Sheets

Statements of Income

Statements of Members’ Capital

Statements of Cash Flows

Notes to Financial Statements

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Members of
Starfish Pipeline Company, LLC

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of members’ capital and of cash flows present fairly, in all material respects, the financial position of Starfish Pipeline Company, LLC and its subsidiaries (the “Company”) at December 31, 2005 and 2004, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. 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, 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 3 to the financial statements, the Company has significant transactions and relationships with affiliated entities.

PricewaterhouseCoopers LLP

Houston, Texas

March 27, 2006

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Starfish Pipeline Company, LLC
Consolidated Balance Sheets
December 31, 2005 and 2004

(in thousands of dollars)	2005		2004

Assets
Current assets
Cash and cash equivalents	$	1,574	$	904
Transportation receivables, net of allowance	6,469		4,371
Owing from related parties	1,486		2
Gas imbalance Net under-recoveries (Note 2)	4,228		825
Other assets	579		889
Total current assets	14,336		6,991

Pipelines, plant and equipment, net (Note 4)	89,736		92,921
Total assets	$	104,072	$	99,912

Liabilities and Members’ Capital
Current liabilities
Accounts payable, trade	$	2,887	$	1,430
Owing to related parties	421		643
Gas imbalances (Note 2)	6,324		2,425
Accrued expenses	2,193		105
Current obligation under capital lease	1,073		1,073
Total current liabilities	12,898		5,676

Obligation under capital lease, less current portion	5,966		6,504
Asset retirement obligation (Note 6)	5,593		5,277
Regulatory liability (Note 6)	9,180		8,817
Total liabilities	33,637		26,274

Members’ capital	70,435		73,638
Total liabilities and members’ capital	$	104,072	$	99,912

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

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Starfish Pipeline Company, LLC
Consolidated Statements of Income
Years Ended December 31, 2005 and 2004

(in thousands of dollars)	2005			2004

Operating revenues
Transportation	$	16,739		$	22,321
Dehydration and other	2,604			3,244
Total revenues	19,343			25,565

Operating expenses
Operating and maintenance	11,200			9,636
Administrative and general	1,821			1,679
Depreciation and amortization	6,371			6,483
Accretion and regulatory expense	679			716
Gain on disposition of assets	—			(860		)
Total operating expenses, net	20,071			17,654

Net operating (loss) income	(728		)	7,911

Other income (expense)
Interest expense	(536		)	(573		)
Interest income	42			43
Other income	354			274
Total other income (expense), net	(140		)	(256		)
Net (loss) income	$	(868	)	$	7,655

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

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Starfish Pipeline Company, LLC
Consolidated Statements of Members’ Capital
Years Ended December 31, 2005 and 2004

	Enterprise/			Shell/
	MarkWest			Enbridge
(in thousands of dollars)	(Note 1)			(Note 1)			Total

Capital account balances at December 31, 2003	$	40,565		$	40,565		$	81,130
Contributions	1,536			1,535			3,071
Distributions	(9,109		)	(9,109		)	(18,218		)
Net income	3,827			3,828			7,655

Capital account balances at December 31, 2004	36,819			36,819			73,638
Contributions	1,486			1,486			2,972
Distributions	(2,653		)	(2,654		)	(5,307		)
Net income	(434		)	(434		)	(868		)

Capital account balances at December 31, 2005	$	35,218		$	35,217		$	70,435

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

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Starfish Pipeline Company, LLC
Consolidated Statements of Cash Flows
Years Ended December 31, 2005 and 2004

(in thousands of dollars)	2005			2004

Cash flows from operating activities
Net (loss) income	$	(868	)	$	7,655
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation and amortization	6,371			6,483
Accretion and regulatory expense	679			716
Provision for bad debts	1,422			—
Gain on disposition of assets	—			(860		)
Changes in working capital
Transportation receivables	(3,520		)	(2,318		)
Owing from related parties	2			77
Gas imbalance Net under-recoveries	(3,403		)	2,049
Other assets	(8		)	201
Accounts payable and accrued liabilities	3,611			(1,288		)
Gas imbalances	3,899			2,910
Owing to related parties	(222		)	300
Net cash provided by operating activities	7,963			15,925

Cash flows from investing activities
Capital expenditures	(2,934		)	(5,271		)
Proceeds from disposition of assets	—			15
Net cash used in investing activities	(2,934		)	(5,256		)

Cash flows from financing activities
Contribution from members	1,486			3,071
Distribution to members	(5,307		)	(18,218		)
Reduction of capital lease obligation	(538		)	(500		)
Net cash used in financing activities	(4,359		)	(15,647		)
Increase (decrease) in cash and cash equivalents	670			(4,978		)

Cash and cash equivalents
Beginning of period	904			5,882
End of period	$	1,574		$	904

Supplemental cash flow disclosures
Cash paid in interest	$	—		$	—
Noncash financing and investing activities
As of December 31, 2005 and 2004, respectively, accounts payable, trade included $0 and $66,235 of fixed asset additions.

During 2005 and 2004, respectively, $0 and $300,000 of fixed asset additions were recognized due to recording of an asset retirement obligation.

The members agreed on December 19, 2005, to provide capital contributions in the amount of $2,972,000. As of December 31, 2005, a receivable in the amount of $1,486,000, was due from MarkWest. Starfish received the contribution in January 2006.

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

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Starfish Pipeline Company, LLC
Notes to Consolidated Financial Statements
December 31, 2005 and 2004

1. Organization and Business

Starfish Pipeline Company, LLC (“Starfish” or the “Company”) was formed on December 8, 2000, under the provisions of the Delaware Limited Liability Company Act. Starfish is owned 50% each by Enterprise Products Operating, LP (“Enterprise”) and Shell Gas Transmission, LLC (“Shell”), an affiliate of Shell Oil Company (“SOC”). In January 2001, Starfish acquired 100% of Stingray Pipeline Company, LLC (“Stingray”), West Cameron Dehydration, LLC (“West Cameron”) and Triton Gathering, LLC (“Triton”, previously East Breaks Gathering Company, LLC) from Deepwater Holdings, LLC, an affiliate of the El Paso Corporation. The purchase price was $50,200,000, which was allocated based on the fair value of the net assets acquired. Since the estimated fair value of the net assets was in excess of the purchase price, no goodwill was recorded. On December 31, 2004, SOC sold its interest in Shell to Enbridge Holdings (Offshore) L.L.C. (“Enbridge”), an affiliate of Enbridge (U.S.) Inc. Therefore, as of December 31, 2004, SOC is no longer an affiliate. Subsequent to the sale, Shell was renamed Enbridge Offshore (Gas Transmission) L.L.C. On March 31, 2005, with an effective date of January 1, 2005, Enterprise sold its interest in Starfish to MarkWest Energy Partners L.P. (“MarkWest”). Therefore, as of January 1, 2005, Enterprise is no longer an affiliate.

Stingray operates a regulated natural gas pipeline system (the “Stingray System”) engaged in the transmission of natural gas in the Louisiana and Texas offshore areas. The Stingray System consists of (i) 361 miles of 6 to 36-inch diameter pipeline that transports natural gas from the High Island Offshore System, or HIOS, West Cameron, East Cameron, Garden Banks and Vermilion lease areas in the Gulf of Mexico to onshore transmission systems in Louisiana, (ii) 43 miles of 16 to 20-inch diameter pipeline connecting platforms and leases in the Garden Banks Block 191 and 72 areas to the Stingray System, and (iii) 13 miles of 16-inch diameter pipeline connecting the GulfTerra Energy Partners L.P., formerly known as El Paso Energy Partners L.P., platform at East Cameron Block 373 to the Stingray System at East Cameron Block 338.

West Cameron operates an unregulated natural gas dehydration facility that provides interruptible dehydration service to offshore platform operators connected to the Stingray System. The facility is located at Stingray station 701 in Holly Beach, Louisiana.

Triton is a gathering system that includes 18 laterals, which are connected to the Stingray System, and located in the Garden Banks, East Cameron, Vermilion, and West Cameron areas of the Gulf of Mexico. This includes the Gunnison lateral completed in December 2003.

Starfish has no employees and receives all administrative and operating support through contractual arrangements with affiliated companies. These services and agreements are outlined in Note 3, Related Party Transactions.

Agreements between the member companies address the allocation of income and capital contributions and distributions amongst the respective members’ capital accounts.

The terms of the agreements include, but are not limited to the following:

• No member is required to make a capital contribution unless such member votes to approve the capital contribution;

• If a member does not contribute by the time required, other non-defaulting members may elect to participate in its share of such advance in proportion to its membership interest;

• Starfish is required to distribute all available cash, as defined by the members, within thirty days of the end of the calendar month;

• Starfish is not required to distribute any amounts that would cause it to materially default under any debt agreement or instrument.

2. Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its subsidiaries. All intercompany transactions and balances have been eliminated in consolidation.

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Use of Estimates and Significant Risks

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the related reported amounts of revenue and expenses during the reporting period. Such estimates and assumptions include those made in areas of FERC regulations, fair value of financial instruments, future cash flows associated with assets, useful lives for depreciation and potential environmental liabilities. Actual results could differ from those estimates. Management believes that the estimates are reasonable.

Development and production of natural gas in the service area of the pipeline and dehydration facilities are subject to, among other factors, prices for natural gas and federal and state energy policy, none of which are within Starfish’s control.

Regulation

The Stingray System, is an interstate pipeline subject to regulation by the Federal Energy Regulatory Commission (“FERC”). Stingray has accounting policies that conform to generally accepted accounting principles, as applied to regulated enterprises and are in accordance with the accounting requirements and ratemaking practices of the FERC.

Stingray follows the regulatory accounting principles prescribed under Statement of Financial Accounting Standards (“SFAS”) No. 71, Accounting for the Effects of Certain Types of Regulation. If Stingray discontinued the application of SFAS No. 71, due to an increased level of competition and discounting in its market area, adjustments and possible write-offs of regulatory assets and liabilities would be necessary.

Cash and Cash Equivalents

All highly liquid investments with maturity of three months or less when purchased are considered to be cash equivalents.

Allowance for Doubtful Accounts

Allowances have been established for losses on accounts, which may become uncollectible. Collectibility is reviewed regularly and the allowance is adjusted as necessary, primarily under the specific identification method. The allowance was $1,421,567 and $229,728 at December 31, 2005 and 2004, respectively.

The Company recognized provisions for bad debts of $1,421,567 in 2005 relating to an imbalance dispute with shippers.

Pipelines, Plant and Equipment

Pipelines, plant and equipment consist primarily of natural gas pipeline assets and appurtenant facilities that are recorded at cost when originally devoted to service. The regulated portion of the pipeline assets includes an Allowance for Funds Used During Construction (“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by FERC. The pipeline and related facilities are depreciated on the straight-line method over 100 years. The dehydration facility is depreciated based on a useful life of 40 years. The laterals are depreciated based on a useful life of 10 years. Routine maintenance and repair costs are expensed as incurred while additions, improvements and replacements are capitalized.

Leased property and equipment are capitalized, as appropriate, and the present value of the related lease payments is recorded as a liability. Amortization of capitalized lease assets is computed on a straight-line method over the term of the lease and recorded as a component of depreciation expense. Improvements to leased properties are amortized over their useful lives or the lease period, whichever is shorter.

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Retirements, sales and disposals of assets are recorded by eliminating the related costs and accumulated depreciation of the disposed assets. Any resulting gain or loss is reflected in income.

Impairment of Long Lived Assets

Starfish evaluates its assets for impairment when events or circumstances indicate that the carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which Starfish intends to use a long-lived asset and adverse changes in the legal or business environment, such as adverse actions by regulators. When an event occurs, Starfish evaluates the recoverability of our carrying value based on its long-lived assets’ ability to generate future cash flows on an undiscounted basis. If impairment is indicated Starfish will adjust the carrying value of assets downward.

Asset Retirement Obligations

Effective January 1, 2003, Starfish adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143, issued in June 2001, requires the recording of liabilities equal to the fair value of asset retirement obligations and corresponding additional asset costs. The obligations included are those for which there is a legal obligation as a result of existing or enacted law, statute or contract. Over time, the liability would be accreted to its present value, and the capitalized cost would be depreciated over the useful life of the related asset. Upon settlement of the liability, an entity would either settle the obligation for its recorded amount or recognize a gain or loss. Starfish’s assets are under the jurisdiction of the Department of Transportation and the Minerals Management Service (“MMS”). The MMS requires the ultimate abandonment of offshore facilities when they are no longer in use or when suspension for future utilization cannot be justified. Stingray and Triton recorded asset retirement obligations for several of their laterals during FAS 143 implementation in 2003. Starfish did not recognize any asset retirement obligations for its remaining assets because these were determined to be part of the main trunk-line system or laterals with long term usage potential, and due to current reserve estimates and expanding production in the deepwater of the Gulf of Mexico, the date of abandonment could not be reasonably estimated. FIN 47 provides specific guidance regarding when an asset retirement obligation is reasonably estimable including when sufficient information is available to apply an expected present value technique. The Company’s implementation of FIN 47 did not have a material impact effect on these financial statements.

Costs related to the retirement of the Stingray System are provided for in the rates charged to shippers, as allowed by the FERC. The amounts charged to shippers for the costs related to the retirement of the Stingray System differ from the period costs recognized in accordance with SFAS No. 143, and therefore, result in a difference in the timing of recognition of period costs for financial reporting and rate-making purposes. The Company recognizes a regulatory asset or liability for differences in the timing of recognition of the period costs associated with asset retirement obligations for financial reporting and rate-making purposes.

Income Taxes

Starfish is treated as a tax partnership under the provisions of the Internal Revenue Code. Accordingly, the accompanying financial statements do not reflect a provision for income taxes since Starfish’s results of operations and related credits and deductions will be passed through to and taken into account by its members in computing their respective tax liabilities.

Revenue Recognition

Revenue from pipeline transportation of hydrocarbons is recognized upon receipt of the hydrocarbons into the pipeline system. Revenue from dehydration services is recognized at the time service is performed.

Gas Imbalances and Gas Imbalance Over (Under) Recoveries

In the course of providing transportation services to customers, Stingray may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. These transactions result in imbalances (gains and losses), which are settled in-kind through a fuel gas and unaccounted-for gas tracking mechanism, negotiated cash-outs between parties, or are subject to a cash-out procedure included in Stingray’s tariff. Gas imbalances and gas imbalance over (under) recoveries represent natural gas volumes owed to or due from Stingray’s customers. Gas imbalances are valued at an average monthly index price, with was $12.5475 per Dth for the month of December 2005 and $6.5675 per Dth for the month of December 2004.

Stingray’s tariff, Section 11.5, states that subsequent to the end of the twelve-month billing period ending November 30 of each year, Stingray shall compare the revenues and costs under the cash-out procedures and shall refund, within 60 days, the gas imbalance net over-recoveries to firm and interruptible transportation customers on a pro-rata basis in accordance with the transportation revenues Stingray received during that billing period. If the revenues received are less than the costs incurred, then Stingray shall carry forward the gas imbalance net under-recoveries and may offset such net under recoveries against any future net over recoveries that may occur.

Environmental Costs

Starfish records environmental liabilities at their undiscounted amounts when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations, and include estimates of associated legal costs. As of December 31, 2005, Starfish had no liabilities recognized for environmental costs.

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Fair Value of Financial Instruments

The reported amounts of financial instruments such as cash and cash equivalents, receivables, and current liabilities approximate fair value because of their short maturities.

Reclassifications

Certain reclassifications have been made in the prior year consolidated financial statements to conform to the 2005 financial statement presentation. These reclassifications have no impact on net income.

3. Related Party Transactions

Transportation Services

Approximately $145,734 of transportation revenues were derived from related parties in 2004. There were no transportation revenues derived from related parties in 2005. All transactions were at rates pursuant to the existing tariff. There were no affiliate receivables or payables relating to transportation and gas imbalances at December 31, 2005 and 2004.

Operating and Administrative Expense

Starfish has no employees. Operating, maintenance and general and administrative services are provided to Starfish under service agreements with an Enbridge and Shell affiliate in 2005 and 2004, respectively. Substantially all operating and administrative expenses were incurred through services provided under these agreements. At December 31, 2005 and 2004, respectively, Starfish had affiliate payables of $421,447 and $643,249 and affiliates receivables of $0 and $1,617, relating to these agreements.

Partner Contributions

At December 31, 2005, Starfish had an affiliate receivable of $1,486,000 due from MarkWest for a capital contribution. Starfish received the contribution in January 2006.

4. Pipelines, Plant and Equipment

Pipelines, plant and equipment at December 31, 2005 and 2004, is comprised of the following:

(in thousands of dollars)	2005		2004

Regulated pipelines and equipment	$	49,273	$	49,287
Regulated pipeline under capital lease	9,778		9,778
Unregulated pipelines and equipment	43,211		43,325
Dehydration facilities	4,542		4,542
Construction in progress	3,656		433
Asset retirement cost (regulated pipelines)	2,181		2,181
	112,641		109,546
Accumulated depreciation	22,905		16,625
	$	89,736	$	92,921

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5. Capital Lease

Stingray leases a 36-inch pipeline from Natural Gas Pipeline Company of America (“NGPL”), an affiliate of Kinder Morgan, Inc., that connects Stingray’s pipeline system to onshore Louisiana. In June 1999, the lease agreement with NGPL was extended for an additional 14 years beginning December 1, 1999, through November 30, 2013, with an option to purchase the asset at the expiration of the lease. Accordingly, Stingray accounts for this lease as a capital lease. The present value of the lease payments under the capital lease is recorded as other current and noncurrent liabilities in the accompanying balance sheet.

Future minimum lease payments under capital leases are as follows:

(in thousands of dollars)

Year Ended December 31,
2006	$	1,073
2007	1,073
2008	1,073
2009	1,073
2010	1,073
Thereafter	3,129
Total minimum lease payments	8,494

Less: Amount representing interest	(1,455		)

Present value of net minimum lease payments, including current maturities of $1,073	$	7,039

6. Asset Retirement Obligation

Activity related to the Company’s asset retirement obligation (“ARO”) during the year ended December 31, 2005 and 2004, is as follows:

(in thousands of dollars)	2005		2004

Balance of ARO as of January 1	$	5,277	$	6,193
Liabilities incurred during period	—		300
Liabilities settled during period	—		(1,507		)
Accretion expense	316		291

Balance of ARO as of December 31	$	5,593	$	5,277

For the years ended December 31, 2005 and 2004, the Company recognized depreciation expense related to its asset retirement cost (“ARC”) of $223,000 and $295,000, respectively.

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The rate case filed by Stingray with the FERC (Docket No. RP99–166) decreased the amount the Company could charge in their rates (“Negative Salvage”) for asset retirement obligations. Beginning in 2003, the Negative Salvage the Company was allowed to recover 0.25% of the total value of the Stingray System (approximately $697,000 per year). The Company recognized regulatory expense of approximately $363,000 and $425,000 during the year ended December 31, 2005 and 2004, respectively. Activity related to the Company’s regulatory liability during the year ended December 31, 2005 and 2004, is as follows:

(in thousands of dollars)	2005			2004

Balance of regulatory liability as of January 1	$	8,817		$	8,392
Negative Salvage recovered	697			697
Current period ARO accretion (Stingray’s System)	(252		)	(206		)
Current period ARC depreciation (Stingray’s System)	(82		)	(66		)

Balance as of December 31	$	9,180		$	8,817

7. Regulatory Matters

Regulatory Environment

The FERC has jurisdiction over Stingray with respect to transportation of gas, rates and charges, construction of new facilities, extension or abandonment of service facilities, accounts and records, depreciation and amortization policies and certain other matters.

An annual charge totaling $337,079 and $311,549 was paid to the FERC for fiscal years 2005 and 2004, respectively. This charge, to be recovered from customers through rates, was recorded as a regulatory asset and will be amortized over twelve months. During 2005 and 2004, respectively, $318,082 and $375,801 was recorded as amortization expense.

8. Commitments and Contingencies

In the ordinary course of business, Starfish and its subsidiaries are subject to various laws and regulations including regulations of the FERC. In the opinion of management, compliance with existing laws and regulations will not materially affect the financial position or results of operations of Starfish.

Various legal actions, which have arisen in the ordinary course of business, are pending with respect to the assets of the Starfish. Management believes that the ultimate disposition of these actions, either individually or in aggregate, will not have a material adverse effect on the financial position, the results of operations or cash flows of Starfish.

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9. Impact of Hurricane Rita

In September 2005, Hurricane Rita caused substantial damage to both onshore and offshore facilities, resulting in loss of revenues and significant capital and maintenance expenditures. Onshore repairs were primarily complete as of December 31, 2005, and offshore repairs are ongoing during 2006. Total estimated expenditures related to Rita, including capital and maintenance costs are estimated to be approximately $21,000,000 at the date of this report. The Company is continuing to assess potential hurricane damages. Total expenditures of approximately $3,700,000 have been incurred as of December 31, 2005.

The Company is self insured. To the extent that the Company does not have the financial resources to return the integrity of the assets to pre-hurricane levels, it is the member’s intent to provide the necessary financial support.

10. Recent Accounting Pronouncements

In May 2005, the FASB issued SFAS No. 154, Accounting Charges and Error Corrections, a Replacement of APB Opinion No. 20 and FASB Statement No. 3. This statement requires retrospective application of changes in accounting principle to prior periods’ financial statements, rather than the use of the cumulative effect of a change in accounting principle, unless impractical. If impratical to determine the impact on prior periods, then the latest accounting principle should be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practical, with a corresponding adjustment to equity, unless impractical for all periods presented, in which case prospective treatment should be applied. This statement applies to all voluntary changes in accounting principle, as well as those required by the issuance of new accounting pronouncements if no specific transition guidance is provided. SFAS No. 154 does not change the previously issued guidance for reporting a change in accounting estimate or correction of an error. This statement becomes effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Starfish does not expect this pronouncement to have a material impact on their financial position and results of operations.

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(3) Exhibits:

Exhibit Number		Description

2.1 (2)		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 (2)		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 (3)		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 (4)		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 (8)		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.

2.5 (15)		Purchase and Sale Agreement effective as of January 1, 2005 between MarkWest Energy Partners L.P. and Enterprise Products Operating L.P.

2.6 (16)		Asset and Sale Agreement, dated as of September 16, 2005 Among MarkWest Energy Partners and El Paso Corporation.

2.7 (16)		Asset and Sale Agreement, dated as of September 16, 2005 Among MarkWest Energy Partners and Kerr-McGee Corporation.

2.8 (16)		Asset and Sale Agreement, dated as of September 16, 2005 Among MarkWest Energy Partners and Valero Energy Corp.

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

3.2 (5)		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 (5)		Amended and Restated Limited Liability Company Agreement of MarkWest Energy Operating Company, L.L.C., dated as of May 24, 2002.

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

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

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

3.7 (20)		Amendment No. 2 to Amended and Restated Limited Partnership Agreement MarkWest Energy Partners, L.P.

4.1 (6)		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 (6)		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 (8)		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(8)		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(9)		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(10)		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(10)		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(10)		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(10)		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)

4.10 (17)		Registration Rights Agreement, dated as of November 9, 2005

4.11 (17)		Unit Purchase Agreement, dated as of November 9, 2005

4.12 (18)		Registration Rights Agreement, dated as of December 23, 2005

4.13 (18)		Unit Purchase Agreement, dated as of December 23, 2005

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10.1 (3)		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 (3)		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.

10.3 (5)		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 (5)		MarkWest Energy Partners, L.P. Long-Term Incentive Plan.

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

10.6 (5)		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 (5)+		Fractionation, Storage and Loading Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.

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

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

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

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

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

10.13 (7)		Services Agreement dated January 1, 2004 between MarkWest Energy GP, L.L.C. and MarkWest Hydrocarbon, Inc.

10.14(8)		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(8)		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.

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10.16(11)				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 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(13)^D				MarkWest Hydrocarbon, Inc. 1997 Severance Plan

10.18(14)^D				Executive Employment Agreement effective November 1, 2003 between MarkWest Hydrocarbon, Inc. and Frank Semple.

10.19 (19)				Fourth Amended and Restated Credit Agreement, dated as of November 1, 2005

10.20 (20)				Fifth amended and restated credit agreement dated as of December 29, 2005, 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, Forties Capital Corp., as Documentation Agent, U.S. Bank National Association, as Documentation Agent, Society General, 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 $615,000,000 Senior Credit Facility.

16.1(21)				Changes in registrants certifying accountants. MarkWest Energy Partners, L.P. dismissed PricewaterhouseCoopers LLP as its independent accountants.

16.2(22)				Changes in registrants certifying accountants. MarkWest Energy Partners, L.P. dismissed KPMG LLP as the Partnership’s independent registered public accounting firm and engaged Deloitte & Touche LLP as its new independent registered public accounting firm.

21.1(23)				List of subsidiaries

23.1*				Consent of KPMG LP

23.2*				Consent of PricewaterhouseCoopers LLP

23.3*				Consent of Deloitte & Touche LLP

23.4*				Consent of PricewaterhouseCoopers LLP

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

31.2*				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 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.

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(1)		Incorporated by reference to the Registration Statement (No. 33-81780) on Form S-1 filed January 31, 2002.
(2)		Incorporated by reference to the Current Report on Form 8-K filed April 14, 2003.
(3)		Incorporated by reference to the Current Report on Form 8-K filed December 16, 2003.
(4)		Incorporated by reference to the Current Report on Form 8-K filed December 31, 2003.
(5)		Incorporated by reference to the Current Report on Form 8-K filed June 7, 2002.
(6)		Incorporated by reference to the Current Report on Form 8-K filed June 19, 2003.
(7)		Incorporated by reference to the Annual Report on Form 10-K filed March 15, 2004.
(8)		Incorporated by reference to the Current Report on form 8-K/A filed September 13, 2004.
(9)		Incorporated by reference to the Current Report on Form 8-K filed September 20, 2004.
(10)		Incorporated by reference to the Current Report on Form 8-K filed October 25, 2004.
(11)		Incorporated by reference to the Current Report on Form 8-K filed October 29, 2004.
(12)		Incorporated by reference to the Current Report on Form 8-K filed January 6, 2005.
(13)		Incorporated by reference to the Quarterly Report of MarkWest Hydrocarbon, Inc. on Form 10-Q filed November 13, 1997.
(14)		Incorporation by reference to the Annual Report of MarkWest Hydrocarbon, Inc. on Form 10-K filed March 30, 2004.
(15)		Incorporated by reference to the Current Report on Form 8-K filed April 6, 2005.
(16)		Incorporated by reference to the Current Report on Form 8-K filed September 21, 2005.
(17)		Incorporated by reference to the Current Report on Form 8-K filed November 16, 2005.
(18)		Incorporated by reference to the Current Report on Form 8-K/A filed December 29, 2005.
(19)		Incorporated by reference to the Current Report on Form 8-K filed November 7, 2005.
(20)		Incorporated by reference to the Current Report on Form 8-K filed January 5, 2006.
(21)		Incorporated by reference to the Current Report on Form 8-K filed March 1, 2004.
(22)		Incorporated by reference to the Current Report on Form 8-K filed September 23, 2005.
(23)		Incorporated by reference to the Annual Report on Form 10-K filed March 16, 2006.

+		Application has been made to the Securities and Exchange Commission for confidential treatment of certain provisions of these exhibits. Omitted material for which confidential treatment has been requested 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 20, 2006	By:	/S/FRANK M. SEMPLE
		Frank M. Semple
		President and Chief Executive Officer
		(Principal Executive Officer)

Date: June 20, 2006	By:	/S/NANCY K. MASTEN
		Nancy K. Masten
		Senior Vice President and Chief Accounting Officer
		(Principal Accounting Officer)

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Markwest Energy Partners L P Inactive 10-K/A2005 FY Annual report (amended)

PART I

ITEM 1. BUSINESS

General

ITEM 1A. RISK FACTORS

ITEM 1B. UNRESOLVED STAFF COMMENTS

ITEM 2. PROPERTIES

NGL Pipelines:

Michigan Crude Pipeline :

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

Distributions of Available Cash During the Subordination Period

Incentive Distribution Rights

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

Overview

Consolidated Financial Information

Off-Balance Sheet Arrangements

Commodity Price Sensitivity

Seasonality

Critical Accounting Policies and Estimates

Impairment of Long-Lived Assets

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

Use of Estimates

Property, Plant and Equipment

Impairment of Long-Lived Assets

Fair Value of Financial Instruments

Hobbs Lateral Acquisition

Michigan Crude Pipeline

Western Oklahoma Acquisition

Lubbock Pipeline Acquisition

Pinnacle Acquisition

Cobb Processing Plant

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

Distributions of Available Cash During the Subordination Period

Incentive Distribution Rights

Public Offering – January 12, 2004

18. Segment Information

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

Director Compensation

Compensation Committee Report

PERFORMANCE GRAPH

Natural Gas Liquids Purchase Agreement