10-K 1 a06-3166_110k.htm ANNUAL REPORT PURSUANT TO SECTION 13 AND 15(D)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ý		Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
		for the fiscal year ended December 31, 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 001-14841

MARKWEST HYDROCARBON, INC.

(Exact name of registrant as specified in its charter)

Delaware		84-1352233
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

155 Inverness Drive West, Suite 200, Englewood, CO 80112-5000
(Address of principal executive offices)

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

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

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

Indicate by check mark whether the registrant 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 to file reports pursuant to Section 13 or 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 voting common stock held by non-affiliates of the registrant on June 30, 2005 was approximately $147,374,000.

The registrant had 10,802,488 shares of common stock, $0.01 per share par value, outstanding as of January 31, 2006.

DOCUMENTS INCORPORATED BY REFERENCE: None

MarkWest Hydrocarbon, Inc.

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 Equity and Related Stockholder 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 Hydrocarbon” or the “Company” are intended to mean MarkWest Hydrocarbon, Inc., and its consolidated subsidiaries. “MarkWest Energy” or “MarkWest Energy Partners” or the “Partnership” are intended to mean MarkWest Energy Partners, L.P.

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 tertiary 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 within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. We use words such as “may,” “believe,” “estimate,” “expect,” “intend,” “project,” “anticipate,” and similar expressions to identify forward-looking statements.

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

• Our expectations regarding MarkWest Energy Partners, L.P.

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

• Our ability to amend certain producer contracts.

• Our expectations regarding natural gas, NGLs product and prices.

• Our efforts to increase fee-based contract volumes.

• Our ability to manage our commodity price risk.

• Our ability to maximize the value of our NGL output.

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

• Our ability to comply with environmental and governmental regulations.

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

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

• The availability of NGLs for our transportation, fractionation and storage services.

• Prices of NGL products and natural gas, including the effectiveness of any hedging activities.

• Our ability to negotiate favorable marketing agreements.

• The risks that third party natural gas exploration and production activities will not occur or be successful.

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

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

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

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

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

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

• 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.

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

• The threat of terrorist attacks or war.

• Winter weather conditions.

This list is not necessarily complete. Other unknown or unpredictable factors could also have material adverse effects on future results. The Company 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 Hydrocarbon was founded in 1988 as a partnership and later incorporated in Delaware. We completed our initial public offering of common shares in 1996.

MarkWest Hydrocarbon is an energy company primarily focused on marketing natural gas liquids (NGLs) and increasing shareholder value by growing MarkWest Energy Partners, L.P. (“MarkWest Energy” or “MarkWest Energy Partners” or “The Partnership”), our consolidated subsidiary and a publicly-traded master limited partnership. MarkWest Energy Partners 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 Company discontinued its exploration and production activities in 2003.

MarkWest Hydrocarbon’s assets consist primarily of partnership interests in MarkWest Energy Partners and certain processing agreements in Appalachia. As of December 31, 2005, the Company owned a 21% interest in the Partnership, consisting of the following:

• 1,633,334 subordinated units and 836,162 common units, representing a 19% limited partner interest in the Partnership; and

• an 89% ownership interest in MarkWest Energy GP, L.L.C., the general partner of the Partnership, which in turn owns a 2% general partner interest and all of the incentive distribution rights in the Partnership.

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.

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 or fuel 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 delivered to our processing plant is 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. At the Javelina facility, MarkWest also produces a height quality hydrogen stream that is delivered back to certain refinery customers.

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 three other 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.

• Ethylene and propylene are principally used as petrochemical feedstocks.

• Hydrogen is principally used in the refining process to assist in the production of low sulfur products.

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

The Partnership faces competition for natural gas and crude oil transportation; 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 the Partnership’s fractionation services include availability of capacity, proximity to supply and industry marketing centers, cost efficiency and reliability of service, and, in the case of Javelina, the value of the recovered products compared to their equivalent value when consumed at the refineries as fuel. Competition for customers is based primarily on price, delivery capabilities, flexibility, and maintenance of quality customer relationships.

The Partnership’s 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.

We believe the Partnership’s competitive strengths include:

• Location and efficiency of facilities. In many locations, the Partnership’s facilities were installed more recently and are more efficient than those of its competitors. This provides the Partnership with a significant competitive advantage over its competitors. In other locations, there are no other viable facilities to provide similar services as the Partnership provides.

• Long-term contracts. We believe MarkWest Energy Partners’ long-term contracts, which we define as contracts with remaining terms of four years or more, lend greater stability to its cash-flow profile.

• 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 the Partnership’s 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.

To better understand our business and 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 our relationship with MarkWest Energy Partners;

• The nature of the contracts from which we derive our revenues and from which MarkWest Energy Partners derives its revenues; and

• The lack of comparability within our results of operations across periods because of MarkWest Energy Partners’ significant acquisition activity.

Our Relationship with MarkWest Energy Partners

We spun off the majority of our then-existing natural gas gathering and processing and NGL transportation, fractionation and storage assets into MarkWest Energy Partners in May 2002, just before the Partnership completed its initial public offering. At the time of its formation and initial public offering, we entered into four contracts with MarkWest Energy

Partners whereby MarkWest Energy Partners provides midstream services in Appalachia to us for a fee. Additionally, MarkWest Energy Partners receives 100% of all fee and percent-of-proceeds consideration for the first 10 MMcf/d that it gathers and processes in Michigan. MarkWest Hydrocarbon retains a 70% net profits interest in the gathering and processing income earned on quarterly pipeline throughput in excess of 10 MMcf/d. In accordance with generally accepted accounting principles, MarkWest Energy Partners’ financial results are included in our consolidated financial statements. All intercompany accounts and transactions are eliminated during consolidation.

As a result of the contracts mentioned above, the Company is one of the Partnership’s largest customers. For the year ended December 31, 2005, we accounted for 13% of the Partnership’s revenues and 20% of its net operating margin. This represents a decrease from the year ended December 31, 2004, when we accounted for 20% of the Partnership’s revenues and 32% of its net operating margin. We expect we will continue to account for less of the Partnership’s business in the future as it continues to acquire assets and increase its customer base or diversify its business.

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

MarkWest Hydrocarbon Contracts

Excluding the revenues derived from MarkWest Energy Partners, we generate the majority of our revenues and net operating margin (net operating margin is discussed further, below) from the Appalachia processing agreements. We outsource these services to the Partnership and pay the Partnership a fee for providing processing and fractionation services. As compensation for providing processing services to our Appalachian producers, we earn a fee and receive title to the NGLs produced. In return, we are required to replace, in dry natural gas, the Btu value of the NGLs extracted. This Btu replacement obligation is referred to in the industry as a “keep-whole” arrangement. In keep-whole arrangements, our principal cost is purchasing and delivering dry gas of an equivalent Btu content to replace Btus extracted from the gas stream in the form of NGLs, or consumed as fuel during processing. The spread between the NGL product sales price and the purchase price of natural gas with an equivalent Btu content is called the “frac spread.” Generally, the frac spread is positive and offsets all or a portion of the fees that we pay the Partnership. In the event natural gas becomes more expensive on a Btu equivalent basis than NGL products and the associated fees that we pay the Partnership, the net operating margin associated with the Appalachian processing agreements results in operating losses.

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

In September 2004, we entered into several new and amended agreements, expiring December 31, 2009, with one of the largest Appalachia producers, which allow us to significantly reduce our exposure to commodity price risk, for approximately 25% of our keep-whole gas volumes. Under these agreements, the Company’s exposure to the keep-whole natural gas is limited in the event natural gas becomes more expensive than the NGL product sales price, thereby mitigating the risk of incurring operating losses.

At the closing of MarkWest Energy Partners’ initial public offering on May 24, 2002, we outsourced our midstream services to the Partnership. Pursuant to the terms of the operating agreements, we retained all the benefits and associated risks of our keep-whole contracts with producers. Our NGL marketing and natural gas supply operations were retained by us and not contributed to MarkWest Energy Partners.

Our keep-whole contracts expose us to commodity price risk, both on the sales side (of NGLs) and on the purchase side (of natural gas), which, in turn, may increase the volatility of our standalone results and cash flows. We attempt to mitigate our commodity price risk through our commodity price risk management program (see Item 7A, “Quantitative and Qualitative Disclosures about Market Risk” for further details about our commodity price risk management program).

MarkWest Energy Partners’ Contracts

The Partnership generates the majority of its 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; crude oil gathering and transportation; and refinery off-gas processing. It has a variety of contract types. In many cases, the Partnership provides services under contracts that contain a combination of more than one of the arrangements described below.

• Fee-based arrangements. The Partnership receives fees for gathering, processing and transmission of natural gas; transportation, fractionation and storage of NGLs; and gathering and transportation of crude oil. The revenue it earns from these arrangements 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. In certain cases, these arrangements provide for minimum annual payments. If a sustained decline in commodity prices resulted in a decline in volumes, our revenues from these arrangements would be reduced.

• Percent-of-proceeds arrangements. The Partnership generally gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGLs at market prices, and remits 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, the Partnership 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. Under these types of arrangements, its revenues and net operating margins generally increase as natural gas prices and NGL prices increase, and its 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. The Partnership generally purchases 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. It then gathers and delivers the natural gas to pipelines, where it resells the natural gas at the index price, or at a different percentage discount to the index price. The net operating margins the Partnership realizes 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. The Partnership gathers natural gas from the producer, processes the natural gas, and sells the resulting NGLs to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, the Partnership must either purchase natural gas at market prices for return to producers, or make cash payment to the producers equal to the energy content of this natural gas. Accordingly, under these arrangements, its revenues and net operating margins increase as the price of NGLs increases relative to the price of natural gas, and decreases as the price of natural gas increases relative to the price of NGLs.

• Settlement margin. Typically, the terms of the Partnership’s gathering arrangements specify that it is allowed to retain a fixed percentage of the volume gathered to cover the compression fuel charges and deemed line losses. To the extent the gathering system is operated more efficiently than specified per contract allowance, the Partnership is entitled to retain the difference for its own account.

In its current areas of operations, MarkWest Energy Partners utilizes a combination of contract types. In many cases, the Partnership provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of MarkWest Energy Partners’ contracts vary based on gas quality, the competitive environment at the time the contracts are signed and customer requirements. The Partnership’s contract mix and, accordingly, its exposure to natural gas and NGL prices, may change due to changes in producer preferences, the Partnership’s expansion in regions where some types of contracts are more common, and other market factors. Any change in the contract portfolio will influence its financial results.

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		December 31, 2004		December 31, 2003
Revenues	$	714,177	$	460,113	209,268

Purchased product costs	583,084		363,261		187,544

Net operating margin	131,093		96,852		21,724

Facility expenses	45,577		28,580		20,957
Selling, general and administrative expenses	33,350		28,132		15,865
Depreciation	20,829		16,895		8,795
Amortization of intangible assets	9,656		3,640		—
Accretion of asset retirement obligation	160		15		—
Impairments	—		130		2,187
Income from operations	$	21,521	$	19,460	(26,080	)

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 (1)		Percent-of-Proceeds (2)		Percent-of-Index (3)		Keep-Whole (4)		Total
Revenues	23	%	3	%	24	%	50	%	100	%
Net operating margin	35	%	15	%	29	%	21	%	100	%

(1) Includes gas marketing and NGL wholesale revenues.

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

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

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

Items Affecting Comparability of Financial Results

In reading the discussion of our historical results of operations, you should be aware of the impact of MarkWest Energy Partners’ recent significant acquisitions, which influence the comparability of our results of operations for the periods discussed.

MarkWest Energy Partners’ Recent Acquisitions

Since its initial public offering, the Partnership has completed eight acquisitions for an aggregate purchase price of approximately $794.4 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.

Segment Reporting

Segments. We have two segments: MarkWest Hydrocarbon Standalone and MarkWest Energy Partners. 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.

MarkWest Hydrocarbon Standalone

Our marketing group markets our NGL production in Appalachia. In 2005, we sold approximately 157 million gallons of NGLs extracted at the Partnership’s Siloam facility. We ship NGL products from Siloam by truck, rail and barge. Our marketing customers include propane retailers, refineries, petrochemical plants and NGL product resellers. Most marketing sales contracts have terms of one year or less, are made on best-efforts basis and are priced in reference to Mt. Belvieu index prices or plant posting prices. In addition to our NGL product sales, our marketing operations are also responsible for the purchase of natural gas delivered for the account of producers, pursuant to our keep-whole processing contracts. Also, we operate a wholesale propane marketing business.

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

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

Consistent with the Partnership’s operating agreements with this same customer, the Partnership enters into contracts with the natural gas producers for their production to be processed in the Partnership’s Kenova, Boldman and Cobb facilities, before delivery of the producer’s natural gas to the customer’s transmission facilities. We have contractual commitments with approximately 260 such producers in Appalachia. Approximately 54% of these contracts, representing approximately 27% of the committed volumes, expire in 2009. The other 46% of the contracts, representing approximately 73% of the committed volumes, expires in 2015. Under the provisions of our contracts with the Appalachian producers, the producers have

committed all of the natural gas they deliver into the customer’s transmission facilities upstream of MarkWest Energy’s Kenova, Boldman and Cobb facilities for processing.

As compensation for providing processing services to our Appalachian producers (we have since outsourced these services to MarkWest Energy as discussed below), we earn both a fee and retain the NGLs produced under keep-whole agreements. In return, we are required to replace, in dry natural gas, the energy content of the NGLs extracted.

In September 2004, we entered into several new and amended agreements, expiring December 31, 2009, with one of the largest Appalachia producers, which allow us to significantly reduce our exposure to commodity price risk, for approximately 25% of our keep-whole gas volumes. Under these agreements, we purchase natural gas from the producer based on the value of the NGLs that we sell, thereby mitigating the risk of incurring operating losses.

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

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

Beginning in February 2004, we initiated a wholesale propane marketing business through an agency relationship with a third party marketer located in Kansas City, Missouri. We buy propane on a wholesale basis and resell it to third parties, primarily propane retailers. This operation is fundamentally a high-volume, low margin business. For the years ended December 31, 2005 and 2004, 9% and 7%, respectively, of our revenue stemmed from our wholesale propane marketing business. The wholesale propane marketing business’ net operating margin in 2005 and 2004, as a percent of consolidated net operating margin, was 1% and 1%, respectively.

MarkWest Energy Partners

MarkWest Energy Partners’ operations may be summarized as follows:

Southwest Business Unit

• East Texas. MarkWest Energy Partners owns 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. MarkWest Energy Partners owns 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. MarkWest Energy Partners owns 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. The Partnership gathers a significant portion of the gas produced from fields adjacent to its gathering systems. In addition, the Partnership owns four lateral pipelines in Texas and New Mexico.

Northeast Business Unit

• Appalachia. MarkWest Energy Partners is 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.

• Michigan. MarkWest Energy Partners owns an interstate crude oil gathering pipeline in Michigan and refers to this system as the Michigan Crude Pipeline. The Partnership also owns a natural gas gathering system and a natural gas processing plant in Michigan.

Gulf Coast Business Unit

• Javelina. On November 1, 2005, MarkWest Energy Partners 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.

• Starfish. On March 31, 2005, the Partnership acquired 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. Starfish owns the FERC-regulated Stingray natural gas pipeline, and the unregulated Triton natural gas gathering system and West Cameron dehydration facility. For external reporting purposes, we do not include Starfish information in this segment. However, management includes Starfish in its decision making and management of the Gulf Coast Business Unit.

Regulatory Matters

The activities of MarkWest Hydrocarbon and MarkWest Energy 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.

MarkWest Energy Partners’ Appalachian pipeline carries NGLs across state lines. The primary shipper on the pipeline is MarkWest Hydrocarbon, which has entered into agreements with the Partnership, providing for a fixed transportation charge for the term of the agreements. They expire on December 31, 2015. The Partnership is the only other shipper on the pipeline. As the Company neither operates the Appalachian pipeline as a common carrier nor holds 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, the Company has agreed to not challenge the status of the Appalachian pipeline or the transportation charge during the term of its agreements. With respect to the Company’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. We 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 Company vigorously defended its tariff, and on December 29, 2005, the Commission rejected the protestors’ request for interim rates and accepted the 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 Company cannot predict whether the FERC tariff protest or any settlement will adversely affect its Michigan Crude Pipeline results of operations.

Environmental Matters

MarkWest Hydrocarbon

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

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

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

MarkWest Energy Partners

General. The Partnership’s 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 the Partnership’s present and future operations, and generally require it 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 the Partnership to fines, penalties and/or interruptions in its operations that could influence its results of operations. If an accidental leak, spill or release of hazardous substances occurs at any facilities the Partnership owns, operates or otherwise uses, or where it sends materials for treatment or disposal, the Partnership could be held jointly and severally liable for all resulting liabilities, including investigation, remedial and clean-up costs. Likewise, the Partnership could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination. The Partnership could also be required to perform remedial operations to prevent future contamination for properties owned, leased or acquired by it 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 the Partnership’s results of operations and cash flows.

The Partnership believes that its operations and facilities are in substantial compliance with applicable environmental laws and regulations, and that the cost of compliance with such laws and regulations will not have a material adverse effect on the Partnership’s results of operations or financial condition. The Partnership cannot ensure, however, that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable. 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 the Partnership 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 the Partnership’s customers, could have material adverse effect on its business, financial condition, results of operations and cash flow.

Ongoing Remediation and Indemnification from a Third Party. The previous owner/operator of the Partnership’s 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 the Company’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, the Company assigned to the Partnership 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 the Partnership’s financial condition or results of operations.

Pipeline Safety Regulations

The Company’s 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. The Partnership is currently preparing its application for 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

As of December 31, 2005, we had 235 employees, who operate the Partnership’s facilities and provide general and administrative services. The Paper, Allied Industrial, Chemical and Energy Workers International Union Local 5-372 represents 15 employees at the Partnership’s 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 stock trades on the American Stock Exchange under the symbol “MWP.” 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 Hydrocarbon.

Risks Inherent in Our Business

We are highly dependent upon the earnings and distributions of MarkWest Energy Partners.

A significant decline in MarkWest Energy Partners’ earnings and/or cash distributions would have a corresponding negative impact on us. For more information on these earnings and cash distributions, please see MarkWest Energy Partners’ 2005 Annual Report on Form 10-K.

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

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

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

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

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

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

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

• the failure to realize expected synergies and cost savings;

• coordinating geographically disparate organizations, systems and facilities;

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

• consolidating corporate and administrative functions.

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

The Partnership’s 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 the Partnership’s opportunities for future acquisitions, and could adversely affect its operations and cash flows available for distribution to its unitholders.

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 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 hedging 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. 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.

Our management has discretion in conducting our risk management activities and may not accurately predict future price fluctuations and therefore expose us to financial risks and reduce our opportunity to benefit from price increases.

We evaluate our exposure to commodity price risk from an overall portfolio basis. Our management has discretion in determining whether and how to manage the commodity price risk associated with our physical and derivative positions.

To the extent that we do not manage the commodity price risk relating to a position that is subject to commodity price risk, and commodity prices move adversely, we could suffer losses. Such losses could be substantial, and could adversely affect our financial condition and results of operations.

Changes in commodity prices subject us to margin calls, which may adversely affect our liquidity.

Unfavorable commodity price changes may subject us to margin calls that require us to provide cash collateral to our counterparties in amounts that may be material. Such funding requirements could exceed our ability to access our credit line or other sources of capital. If we are unable to meet these margin calls with borrowings or cash on hand, we would be forced to sell product to meet the margin calls, or to terminate the corresponding futures contracts. If we are forced to sell product to meet margin calls, we may have to sell product at prices that are not advantageous, which could adversely affect our financial condition, results of operations and cash flows.

The Partnership’s 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.

The Partnership has substantial indebtedness and other financial obligations.

Subject to the restrictions governing the Partnership’s indebtedness and other financial obligations, and the indenture governing our existing debt, the Partnership may incur significant additional indebtedness and other financial obligations, which may be secured and/or structurally senior to its existing debt.

The Partnership’s substantial indebtedness and other financial obligations could have important consequences. For example, they could:

• make it more difficult for the Partnership to satisfy its obligations with respect to its existing debt;

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

• have a material adverse effect on the Partnership if it fails to comply with financial and restrictive covenants in the Partnership’s debt agreements and an event of default occurs as a result of that failure that is not cured or

waived;

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

• limit the Partnership’s flexibility in planning for, or reacting to, changes in its business and the industry in which it operates; and

• place the Partnership at a competitive disadvantage compared to its competitors that have proportionately less debt.

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

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

Our profitability is influenced by the volume of natural gas the Partnership gathers, transmits and processes, and NGLs the Partnership transports and fractionates at its facilities. A decrease in natural gas or refinery off-gas supplies in the Partnership’s areas of operation would result in a decline in the volume of natural gas delivered to its pipelines and facilities for gathering, transporting and processing and NGLs delivered to its pipelines and facilities for fractionation, storage, transportation and sales. This would reduce the Partnership’s revenue and operating income. Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. We have no control over the level of drilling activity in the areas of operations, the amount of reserves underlying the wells and the “decline rate,” or 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 the Partnership’s gathering systems would, therefore, result in a reduction of the amount of natural gas it gathers, transmits and processes and the amount of NGLs the Partnership transports and fractionates. Over time upon exhaustion of the current wells, this could cause the Partnership to abandon its gathering systems and, possibly, cease gathering operations. As a consequence of such declines, our revenues would decrease.

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.

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

The renewal or replacement of existing contracts with the Partnership’s customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond its 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. The Partnership’s 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 the Partnership does. Additionally, the Partnership’s customers that gather gas through facilities that are not otherwise dedicated to the Partnership may develop their own processing and fractionation facilities in lieu of using the Partnership’s services. Certain of the Partnership’s 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 the Partnership in the marketing of natural gas, the Partnership often competes in the end-user and utilities markets primarily on the basis of price. The inability of the Partnership’s management to renew or replace its current contracts as they expire and to respond appropriately to changing market conditions could affect its profitability.

Relative changes in NGL product and natural gas prices may adversely impact our results due to frac spread, natural gas and liquids exposure.

We are exposed to frac spread risk. Under our keep-whole arrangements, our principal cost is delivering dry gas of an equivalent Btu content to replace Btus extracted from the gas stream in the form of NGLs, or consumed as fuel during processing. The spread between the NGL product sales price and the purchase price of natural gas with an equivalent Btu content is called the “frac spread.” Generally, the frac spread and, consequently, the net operating margins are positive under these contracts. In the event natural gas becomes more expensive on a Btu equivalent basis than NGL products, the cost of keeping the producer “whole” results in operating losses.

Due to timing of gas purchases and liquid sales, direct exposure to either gas or liquids can be created because there is no longer an offsetting purchase or sale that remains exposed to market pricing. Through our marketing and derivatives activity, direct exposure may occur naturally or we may choose direct exposure to either gas or liquids when we favor that exposure over frac spread risk. Given that we have positions, adverse movement in prices to the positions we have taken will negatively impact our results.

Through our interest in the Partnership, our profitability is affected by the volatility of NGL product and natural gas prices.

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;

• imports of crude oil, natural gas and NGLs;

• seasonality;

• the condition of the U.S. economy;

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

• domestic government regulation, legislation and policies.

The net operating margins of the Partnership under its various types of commodity-based contracts are directly affected by changes in NGL product prices and natural gas prices, and thus are more sensitive to volatility in commodity prices than its fee-based contracts. Additionally, its purchase and resale of gas in the ordinary course of business exposes it to significant risk with 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. The Partnership’s Javelina processing agreements are also potentially affected by the profitability of the NGLs and other products relative to the fuel value of the refinery off-gas stream. Finally, changes in natural gas prices may indirectly affect the Partnership’s profitability, since prices can influence drilling activity and well operations and, thus, the volume of gas it gathers and processes. In the past, the prices of natural gas and NGLs have been extremely volatile, and we believe this volatility may continue.

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, were not effective.

As we discuss in our Management’s Report on Internal Control over Financial Reporting in Part II, Item 9A, “Controls and Procedures,” of this Form 10-K, we have discovered deficiencies, including material weaknesses, in our internal controls over financial reporting as of December 31, 2005. In particular, we identified, and Deloitte & Touche’s audit report 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, 2005 confirmed the presence of, the following material weaknesses:

• Ineffective control environment; and

• Risk management and accounting for derivative financial instruments.

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 the defendants 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 the Partnership’s 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 the Partnership’s gas, liquids and crude oil transmission operations may be 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.

The Partnership is indemnified for liabilities arising from an ongoing remediation of property on which its facilities are located and its results of operation and its ability to make payments of principal and interest on its debt 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 the Partnership’s Kenova, Boldman, Cobb and Kermit facilities are located, and is the previous operator of its 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 the Partnership is 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 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 an additional environmental indemnity pursuant to the terms of the Omnibus Agreement. The Company’s results of operation and ability to make cash distributions could be adversely affected if, in the future, Columbia Gas fails to perform under the indemnification provisions of which the Company is 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 and Environmental Matters.

MarkWest Energy Partners may not be able to successfully execute its business plan and may not be able to grow its business, which could adversely affect the value of our investment in the limited partner units and the general partnership interests in MarkWest Energy Partners.

MarkWest Energy Partners’ ability to successfully operate its business, generate sufficient cash to pay the minimum quarterly cash distributions to its unitholders, and to allow for growth, is subject to a number of risks and uncertainty. Similarly, MarkWest Energy Partners may not be able to successfully expand its business through acquiring or growing its assets, because of various factors, including economic and competitive factors beyond its control. If MarkWest Energy Partners is unable to grow its business, or execute on its business plan, the market price of the common units is likely to decline, causing the limited partner units and the general partner interest we hold in MarkWest Energy Partners to also decline in value.

Our cash flow would be adversely affected if operations at any of the Partnership’s facilities were interrupted.

The Partnership’s operations depend upon the infrastructure that it has developed, including processing and fractionation plants, storage facilities, and various means of transportation. Any significant interruption at these facilities or pipelines, or the Partnership’s 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 and cash flows. Operations at the Partnership’s facilities could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within its control, such as:

• unscheduled turnarounds or catastrophic events at our physical plants;

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

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

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

We rely on the revenues generated from the Partnership’s 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.

The tax treatment of MarkWest Energy Partners depends upon its status as a partnership for federal income tax purposes, as well as it not being subject to entity-level taxation by states. If the Internal Revenue Service were to treat MarkWest Energy Partners as a corporation, or if it were to become subject to entity-level taxation for state tax purposes, then its cash available for distribution would be significantly reduced.

We own limited partner units representing approximately 19% of the limited partnership interests in MarkWest Energy Partners, in addition to a 2% general partnership interest. The anticipated after-tax benefit of an investment in the limited partner units of MarkWest Energy Partners depends largely on MarkWest Energy Partners being treated as a partnership for federal income tax purposes.

If MarkWest Energy Partners were treated as a corporation for federal income tax purposes, it would pay federal income tax on its income at the corporate tax rate, which is currently a maximum of 35%. Cash distributions to the holders of limited partnership interests, including the subordinated units we hold and the common units held by the public, would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to the holders of the limited partnership interests to shelter a substantial portion of such distributions from state and federal income taxes. Because a tax would be imposed upon MarkWest Energy Partners as a corporation, its cash available for distribution to limited partners would be significantly reduced. Thus, treatment of MarkWest Energy Partners as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to its owners, including us, as a holder of the limited partner units, likely causing a significant reduction in the value of the market price of the common units.

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

The Partnership’s 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

MarkWest Hydrocarbon Standalone

MarkWest Hydrocarbon has minimal properties, since discontinuing its exploration and production business in 2003, and transferring its natural gas gathering and processing, and NGL transportation, fractionation and storage assets to MarkWest Energy Partners in 2002. At December 31, 2004 and 2003, we had a gross interest (a well in which a working interest is owned) in 3 wells, with a corresponding net interest (one net well is deemed to exist when the sum of the fractional ownership working interest in gross wells equals one producing well) in 0.62 wells. We had no interest in drilling and recompletion activity in 2005 or 2004. As of December 31, 2003, we had a gross interest in 94 wells, with a corresponding net interest in 69.8 wells, primarily for natural gas.

MarkWest Energy Partners’ Assets

The locations and approximate throughput capacity of MarkWest Energy Partners’ gas processing plants as of and for the year ended December 31, 2005, are as follows:

Gas Processing Facilities:

				Year Ended December 31, 2005
Facility	Location	Year of Initial Construction	Design Throughput Capacity	Natural Gas Throughput	Utilization of Design Capacity		NGL Throughput
			(Mcf/d)	(Mcf/d)			(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 MarkWest Energy Partners’ Kenova plant. The Partnership does not receive Kermit gas volume information but does receive all of the liquids produced at the Kermit facility.

(3) MarkWest Energy Partners acquired the Javelina processing plant on November 1, 2005.

The location, approximate capacity, and throughput of MarkWest Energy Partners’ 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 MarkWest Energy Partners’ pipelines as of and for the year ended December 31, 2005, are as follows:

Natural Gas Pipelines:

				Year Ended December 31, 2005
Facility	Location	Miles	Year of Initial Construction	Design Throughput Capacity	Natural Gas Throughput	Utilization of Design Capacity		NGL Throughput
				(Mcf/d)	(Mcf/d)			(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) MarkWest Energy Partners acquired the Appleby gathering system, along with 20 other gathering systems, as part of its March 28, 2003 Pinnacle acquisition.

NGL Pipelines:

				Year Ended December 31, 2005
Pipeline	Location	Miles	Year of Initial Construction	Design Throughput Capacity	NGL Throughput	Utilization of Design Capacity
				(gal/day)	(gal/day)
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 :

Pipeline	Location	Miles	Design Throughput Capacity (gal/day)	Year Ended December 31, 2005
				NGL	Utilization of
				Throughput (gal/day)	Design Capacity

Michigan:
Michigan Crude Pipeline	Manistee County, MI to Crawford County, MI	150	60,000	14,200	24	%

Title to Properties

We believe the Company has satisfactory title to all of its assets.

ITEM 3. LEGAL PROCEEDINGS

The Company, 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 Company 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 Company and several of its affiliates, including MarkWest Energy Partners, 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 Company, the Partnership and several of its

affiliates were 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 Company continue to investigate the incident.

The Company 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 Company 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 Company 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 Company 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 Company for certain expenses. These include the Company’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 Company has not provided for a receivable for these claims because of the uncertainty as to whether and how much the Company will ultimately recover under these policies. The Company 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 Company has also been involved in a lawsuit captioned Ross Bros. Construction v. MarkWest Hydrocarbon, Inc., (U.S. Court of Appeals for the 6^th Circuit, Case No. 05-6251, appealed from U.S. District Court Eastern District of Kentucky, Ashland Division, Civ. Action No. 01-CV-205). The underlying lawsuit involved the construction of the Siloam, Kentucky, plant and a dispute as to the monetary value of additional work beyond the contract’s lump sum price performed by the contractor. The lawsuit involved a claim of approximately $0.7 million in extra costs. The Company was granted Summary Judgment on its defense asserting accord and satisfaction. In August 2005, Plaintiffs filed an appeal of the Summary Judgment to the U.S. Court of Appeals for the 6th Circuit. The Company believes that, while it is not able to predict the outcome of this matter, based on the judge’s discussion on the grant of the summary judgment and denial of Ross Brothers’ motion for reconsideration, it is probable that the Company will prevail in the appeal. As a result, the Company has not provided for a loss contingency.

The Company has also been involved in an arbitration proceeding captioned Kevin Stowe and Scott Daves v. MarkWest Hydrocarbon, Inc., American Arbitration Association arbitration, Case No. 77 168 Y 0052 05 BEAH, Denver, Colorado, 2005. Claimants in this Arbitration had filed a proceeding against the Company seeking further payments out of a dispute and settlement over interests in certain wells in Colorado. On February 8, 2006, the Company was granted Summary Judgment and the Arbitration was accordingly dismissed.

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

At the Annual Meeting of Stockholders held on December 28, 2005, the stockholders of the Company elected the following nominees to the Board of Directors until the next annual stockholder meeting or until their successors are qualified, with votes cast as follows:

	Number of votes
Director Nominees	For	Authority Withheld
John M. Fox	9,270,765	808,759
Frank M. Semple	9,443,281	636,243
Donald D. Wolf	10,003,083	76,441

There were no abstentions or broker non-votes applicable to the election of directors.

The stockholders approved certain amendments to the 1996 Stock Incentive Plan (the “Plan”) to include non-employee directors as eligible participants under the Plan and to minimize the potential application of additional taxes imposed on any Awards granted under the Plan as a result of recent changes in the US Tax Code Section 409.

For:		6,927,490
Against:		124,641
Abstained:		25,602

The stockholders ratified the appointment of Deloitte & Touche, LLP as independent auditors of MarkWest Hydrocarbon, Inc. for the 2005 fiscal year, with votes cast as follows:

For:		10,050,586
Against:		5,395
Abstained:		23,543

Abstentions had the effect of votes “against” this proposal. Broker non-votes were not counted as votes “for” or “against” this proposal and therefore had no impact on the outcome.

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

Our common stock trades on the American Stock Exchange (“AMEX”) national market under the symbol “MWP.” As of January 31, 2006, there were 10,802,488 shares of common stock outstanding held by approximately 44 holders of record. The following table sets forth quarterly high and low sales prices as reported by the American Stock Exchange, as retroactively restated to give effect to the 2004 and 2003 stock dividends (see below), for the periods indicated, as well as the amount of cash dividends paid per share per quarter for 2005 and 2004.

Quarter Ended	High		Low		Dividend		Record Date	Payment Date

December 31, 2005	$	25.49	$	21.05	$	0.125	February 15, 2006	February 22, 2006
September 30, 2005	$	26.95	$	22.05	$	0.125	November 15, 2005	November 22, 2005
June 30, 2005	$	24.99	$	19.85	$	0.100	August 15, 2005	August 22, 2005
March 31, 2005	$	24.24	$	17.17	$	0.100	May 16, 2005	May 23, 2005

December 31, 2004	$	18.18	$	13.86	$	0.075	February 9, 2005	February 21, 2005
September 30, 2004	$	13.92	$	10.45	$	0.050	November 24, 2004	December 6, 2004
June 30, 2004	$	12.00	$	9.10	$	0.023	August 5, 2004	August 19, 2004
March 31, 2004	$	11.70	$	9.20	$	0.023	May 5, 2004	May 19, 2004

Dividend Policy

The Company does not have a formal dividend policy. The Company’s objective, however, is to maintain a regular quarterly dividend. Payment of dividends in the future will depend on our earnings, financial condition and contractual restrictions, including those under our bank line of credit or imposed by law and other factors deemed relevant by our Board of Directors.

Special Cash Dividend

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

Stock Dividends

On October 28, 2004, the Board of Directors declared a stock dividend of one share for each ten shares owned by stockholders of record as of the close of business on November 9, 2004. The stock dividend was paid on November 19, 2004, with an ex-dividend date of November 5, 2004.

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

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected consolidated historical financial and operating data for MarkWest Hydrocarbon. The selected financial information for the Company, as of and for the years ended December 31, 2005, 2004 and 2003, is derived from our audited Consolidated Financial Statements included in Item 8 in this Form 10-K. The selected consolidated statement of operations and balance sheet data set forth below, as of and for the years ended December 31, 2002 and 2001, have been derived from audited financial statements not included in this Form 10-K. 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.”

	Year Ended December 31,
	2005			2004			2003			2002			2001
	(1)			(2)			(3)
	(in thousands, except per share amounts and operating data)

Statement of Operations:
Revenues	$	714,177		$	460,113		$	209,268		$	155,787		$	173,890
Operating expenses:
Purchased product costs	583,084			363,261			187,544			127,526			140,225
Facility expenses	45,577			28,580			20,957			17,145			16,522
Selling, general and administrative	33,350			28,132			15,865			9,614			7,502
Depreciation	20,829			16,895			8,795			6,016			5,156
Amortization of intangible assets	9,656			3,640			—			—			—
Accretion of asset retirement obligation	160			15			—			—			—
Impairments	—			130			2,187			—			—
Total operating expenses	692,656			440,653			235,348			160,301			169,405
Income (loss) from operations	21,521			19,460			(26,080		)	(4,514		)	4,485

Loss from unconsolidated affiliates	(2,153		)	—			—
Interest income	1,060			647			106			65			(3,700		)
Interest expense	(22,622		)	(9,383		)	(4,347		)	(2,474		)	—
Amortization of deferred financing costs	(6,979		)	(5,281		)	(2,104		)	(4,343		)	—
Gain on sale of non-operating assets	—			—			—			5,454			—
Dividend	392			259			—			—			—
Miscellaneous income (expense)	266			788			(92		)	(73		)	(231		)
Income (loss) before income taxes	(8,515		)	6,490			(32,517		)	(5,885		)	554

Income tax (expense) benefit	1,804			(78		)	13,085			3,057			(239		)
Non-controlling interest in net income of consolidated subsidiary	(91		)	(7,315		)	(2,988		)	(1,947		)	—
Income (loss) from continuing operations	(6,802		)	(903		)	(22,420		)	(4,775		)	315

Income from discontinued operations	—			—			11,443			1,766			2,495
Income (loss) before cumulative effect of accounting change	(6,802		)	(903		)	(10,977		)	(3,009		)	2,810

Cumulative effect of change in accounting for asset retirement obligations, net of income taxes	—			—			(29		)	—			—

Net income (loss)	$	(6,802	)	$	(903	)	$	(11,006	)	$	(3,009	)	$	2,810

Income (loss) from continuing operations per share:
Basic	$	(0.63	)	$	(0.08	)	$	(2.17	)	$	(0.46	)	$	0.03
Diluted	(0.63		)	(0.08		)	(2.17		)	(0.46		)	0.03

Net income (loss) per share:
Basic	(0.63		)	(0.08		)	(1.07		)	(0.29		)	0.27
Diluted	(0.63		)	(0.08		)	(1.07		)	(0.29		)	0.27

Weighted average number of outstanding shares of common stock:
Basic	10,785			10,686			10,328			10,285			10,259
Diluted	10,785			10,686			10,328			10,285			10,284

Balance Sheet Data (at December 31):
Working capital	$	61,156		$	53,907		$	44,747		$	(4,331	)	$	13,498
Property, plant and equipment, net	494,698			283,193			232,257			211,518			200,853
Total assets	1,132,304			593,574			280,495			257,503			250,511
Total long-term debt	608,762			225,000			126,200			64,223			104,850
Stockholder’s equity	39,982			49,761			50,914			53,139			69,033

Cash Flow Data:
Net cash flow provided by (used in):
Operating activities	$	16,874		$	26,616		$	(6,411	)	$	36,301		$	12,980
Investing activities	(445,848		)	(303,017		)	(36,887		)	(22,719		)	(77,643		)
Financing activities	437,098			247,101			78,956			(9,520		)	66,087

(1) MarkWest Energy Partners completed its investment in Starfish on March 31, 2005, and acquired Javelina on November 1, 2005.

(2) MarkWest Energy Partners acquired the East Texas System in late July 2004.

(3) MarkWest Energy Partners acquired the Foss Lake gathering system in December 2003.

MarkWest Energy Partners acquired the Arapaho processing plant in December 2003.

MarkWest Energy Partners acquired the Michigan Crude Pipeline in December 2003.

MarkWest Energy Partners acquired the Pinnacle gathering systems in late March 2003.

MarkWest Energy Partners acquired the Lubbock pipeline in September 2003 and the Hobbs lateral pipeline in April 2004.

MarkWest Energy Partners sold most of its exploration and production operations in July 2003 (U.S.) and December 2003 (Canada).

Operating Data

	Year Ended December 31,
	2005	2004	2003	2002	2001

MarkWest Hydrocarbon
Marketing:
NGL product sales (gallons) (1)	162,000,000	178,000,000	177,000,000	183,000,000	152,200,000

Wholesale:
NGL product sales (gallons) (2)	68,879,000	42,154,000	NA	NA	NA

MarkWest Energy Partners:
*Southwest:*
East Texas (3)
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) (4)	75,800	60,900	57,000	NA	NA
Arapaho NGL product sales (gallons) (5)	60,903,000	45,273,000	2,910,000	NA	NA

Other
Appleby gathering systems throughput (Mcf/d) (6)	33,400	27,100	23,800	NA	NA
Other gathering systems throughput (Mcf/d) (6)	16,500	17,000	20,500	NA	NA
Lateral throughput volumes (Mcf/d) (7)	81,000	75,500	32,100	NA	NA

*Appalachia:*
Natural gas processed for a fee (Mcf/d) (8)	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 (gallons)	5,697,000	9,818,000	11,800,000	11,100,000	8,000,000
Crude oil transported for a fee (Bbl/d) (9)	14,200	14,700	15,100	NA	NA

*Gulf Coast:*
Natural gas processed for a fee (Mcf/d) (10)	115,000	NA	NA	NA	NA
NGLs fractionated for a fee (gal/day) (10)	19,400	NA	NA	NA	NA

(1) Represents sales at the Siloam fractionator.

(2) Represents sales from our wholesale business. Volumes are from the period since the Company started the line of business in February 2004.

(3) The Partnership acquired its East Texas System in late July 2004. Volumes are for the period of time the Partnership owned the facility during 2004.

(4) The Partnership acquired its Foss Lake gathering system in December 2003.

(5) The Partnership acquired its Arapaho processing plant in December 2003.

(6) The Partnership acquired its Pinnacle gathering systems in late March 2003.

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

(8) Includes throughput from the Partnership’s Kenova, Cobb and Boldman processing plants.

(9) The Partnership acquired its Michigan Crude Pipeline in December 2003.

(10) The Partnership acquired the Javelina facilities in November 2005.

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 a net loss of $6.8 million for the year ended December 31, 2005, or a $0.63 loss per diluted share, compared to a net loss of $0.9 million, or an $0.08 loss per diluted share, for the year ended December 31, 2004.

On January 26, 2006, the board of directors of the Company declared a quarterly cash dividend of $0.125 per share for the fourth quarter of 2005. The fourth quarter dividend was paid February 22, 2006, to unitholders of record on February 15, 2006.

Developments Impacting Financial Results

MarkWest Hydrocarbon

In October 2005, MarkWest Hydrocarbon disposed of all production and exploration assets held by its subsidiary, Matrex, L.L.C.

During the year ended December 31, 2003, MarkWest Hydrocarbon discontinued its exploration and production business. Through a series of dispositions, we sold off substantially all of our U.S. and Canadian oil and gas properties. For the years ended December 31, 2003, revenues from our discontinued operations were $30.1 million, and income from discontinued operations before income taxes was $2.1 million.

The dispositions were as follows:

Sales of San Juan Basin Properties

During the second and third quarters of 2003, we completed the sale of our San Juan Basin (U.S.) oil and gas properties for net proceeds aggregating approximately $55.3 million. We recognized an aggregate net pretax gain of $23.3 million on these sales for the year ended December 31, 2003. The proceeds from the sales were used for working capital and general corporate purposes.

Sales of Canadian Properties

During December 2003, we completed the sales of all of our Canadian oil and gas properties for net proceeds aggregating approximately $49.1 million. We recognized an aggregate pretax loss of $4.8 million on these sales for the year ended December 31, 2003. The proceeds from the sales were primarily used to pay off our remaining outstanding debt, exclusive of MarkWest Energy’s debt.

Sale of Eastern Michigan Properties

During December 2003, we completed the sale of certain oil and gas properties and related assets located in Eastern Michigan for net proceeds of less than $0.1 million. We recognized a pretax loss of $1.8 million on the sale.

MarkWest Energy Partners

The Partnership completed eight acquisitions in three years 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 Partnership’s 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 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 the 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.

Results of Operations

Segment Reporting

Our two reportable segments are: MarkWest Hydrocarbon Standalone and MarkWest Energy Partners. We capture information by reportable 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. The segment information appearing in Note 21 to the consolidated financial statements, Segment Information, is presented on a basis consistent with the Company’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

	MarkWest Hydrocarbon Standalone						MarkWest Energy Partners		Eliminating Entries			Total
	(in thousands)
Year Ended December 31, 2005:
Revenues	$				280,015		$	499,084	$	(64,922	)	$	714,177
Purchased product costs	258,188						366,878		(41,982		)	583,084
Facility expenses	20,545						47,972		(22,940		)	45,577
Selling, general and administrative expenses	11,777						21,573		—			33,350
Depreciation	1,295						19,534		—			20,829
Amortization of intangible assets	—						9,656		—			9,656
Accretion of asset retirement and lease obligations	1						159		—			160
Total operating expenses	$			291,806			$	465,772	$	(64,922	)	$	692,656

Operating income (loss)	$		(11,791			)	$	33,312	$	—		$	21,521

Year Ended December 31, 2004:
Revenues	$	218,337					$	301,314	$	(59,538	)	$	460,113
Purchased product costs	185,951						211,534		(34,224		)	363,261
Facility expenses	23,983						29,911		(25,314		)	28,580
Selling, general and administrative expenses	11,999						16,133		—			28,132
Depreciation	1,339						15,556		—			16,895
Amortization of intangible assets	—						3,640		—			3,640
Accretion of asset retirement and lease obligations	2						13		—			15
Impairments	—						130		—			130
Total operating expenses	223,274						276,917		(59,538		)	440,653

Operating income (loss)	$	(4,937				)	$	24,397	$	—		$	19,460

	Year Ended December 31,
	2005			2004
	(in thousands)

Operating income	$	21,521		$	19,460
Loss from unconsolidated subsidiary	(2,153		)	$	—
Interest income	1,060			647
Interest expense	(22,622		)	(9,383		)
Amortization of deferred financing cost (a component of interest expense)	(6,979		)	(5,281		)
Dividend income	392			259
Other income	266			788
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	(8,515		)	6,490
Income tax (expense) benefit	1,804			(78		)
Non-controlling interest in net income of consolidated subsidiary	(91		)	(7,315		)
Loss from continuing operations	$	(6,802	)	$	(903	)

MarkWest Hydrocarbon Standalone

Revenues. Revenues increased $61.7 million, or 28%, for the year ended December 31, 2005, compared to the corresponding period of 2004. Higher volumes and better pricing drove revenue in our wholesale propane marketing business, representing a $30.9 million increase in revenue, and our gas marketing business, representing an $18.8 million increase. NGL product revenues increased $18.5 million due to favorable pricing, offset by a decrease in volumes. Increases to revenues were offset by a $5.2 million unfavorable mark-to-market adjustment to replacement gas that resulted from an increase in natural gas prices, and a $1.0 million decrease in Michigan operations, primarily from a reduction in volumes.

Purchased Product Costs. Purchased product costs increased $72.2 million, or 39%, for the year ended December 31, 2005, compared to the corresponding period of 2004. The increase was primarily due to volumes from our wholesale propane marketing business, a $30.7 million increase, introduced in February 2004, and our gas marketing business, an $18.1 million increase. NGL product costs rose $23.2 million because of higher pricing, offset by reduced volumes.

Facility Expenses. Facility expenses decreased by approximately $3.4 million, or 14%, during the year ended December 31, 2005, compared to corresponding period of 2004. The decrease was the result of a $1.4 million favorable fuel reimbursement at our Kenova, Cobb and Boldman facilities, a reduction to inventory losses at the Appalachia Liquids Pipeline System (ALPS) of $0.7 million, a net reduction to Siloam fractionation fees and Kenova and Boldman processing fees of $1.6 million, and a net decrease of costs in Michigan of $0.2 million, offset by an increase to inventory losses at Siloam of $0.5 million.

Selling, General and Administrative Expenses. Selling, general and administrative expenses decreased by $0.2 million, or 2%, during the year ended December 31, 2005, compared to the corresponding period of 2004 as a result of a decrease in compensation expense attributed to the Participation Plan (see Stock and Incentive Compensation Plans on page

44) and the 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan, and an increase to allocations of selling, general and administrative expenses to the Partnership.

MarkWest Energy Partners

Revenues. Revenues for the year ended December 31, 2005, were higher by $197.8 million, or 66%, compared to 2004. The increase was primarily due to higher volumes and natural gas prices in the Partnership’s Oklahoma operations, $80.3 million, and Other Southwest operations, $37.2 million, as well as operating East Texas System for a full year, $64.3 million. Revenues reflected nine months of activity during 2005 compared to two months of activity during 2004. Revenue also increased in Western Oklahoma during the year ended December 31, 2005 relative to the corresponding period of 2004 due to increased well volumes contracted to the gathering system, higher crude oil prices enhancing condensate sales and higher liquids revenue that resulted from ethane recovery during 2005 versus ethane rejection during 2004 that contributed to incremental revenue of $42.0 million. In addition, Other Southwest revenues increased $21.3 million due to a 27% increase in natural gas volumes, primarily on the Appleby and Edwards gathering systems.

Purchased Product Costs. Purchased product costs were higher during the year ended December 31, 2005, by $155.3 million, or 73%, compared to 2004. The combination of an increase in purchased volumes and price contributed to increases in Western Oklahoma and Other Southwest, primarily Appleby and Edwards, of $75.5 million and $37.1 million, respectively. In addition, the Partnership’s July 30, 2004, East Texas System acquisition had incremental purchased product costs of $35.3 million due, in part, to being operational for a full year, but also higher prices.

Facility Expenses. Facility expenses increased approximately $18.1 million, or 60%, during the year ended December 31, 2005, relative to 2004. East Texas accounted for $7.2 million of the increase, related to operating the facility for a full year, as well as performing repairs and a global overhaul of our compressors. Appalachia increased $5.9 million due, in part, to repairs to the ALPS pipeline. Gulf Coast, acquired November 1, 2005, contributed $2.2 million to the increase. Oklahoma, $1.3 million, and Other Southwest, $1.3 million, increased due to repairs and an overhaul of compressors.

Selling, General and Administrative Expenses. Selling, general and administrative expenses, which are not allocated to segments by the Partnership, increased by $5.4 million, or 34%, during the year ended December 31, 2005, compared to 2004 as a result of the increase in incentive compensation expense of $1.9 million, and audit and Sarbanes-Oxley related costs of $3.2 million.

Depreciation. Depreciation expense increased $4.0 million, or 26%, during the year ended December 31, 2005, compared to 2004 primarily due to the Partnership’s 2004 East Texas acquisition, $3.3 million, and 2005 Gulf Coast acquisition, $1.1 million. These changes were offset by a decrease in depreciation in Appalachia, due to accelerated depreciation in 2004 for the old Cobb facility.

Amortization of Intangible Assets. Amortization expense increased $6.0 million during the year ended December 31, 2005, compared to 2004 due primarily to the November 2005 Gulf Coast acquisition and amortization of the East Texas customer contracts.

Other Income and Expenses

Loss from Unconsolidated Subsidiary. Loss from unconsolidated subsidiary increased $2.2 million during the year ended December 31, 2005, compared to 2004. The Partnership acquired a 50%, non-operating interest in Starfish on March 31, 2005. The path of Hurricane Rita, however, was along the Starfish pipeline corridor. Consequently, Starfish incurred significant losses in the fourth quarter of 2005, of which the Partnership’s share was approximately $2.1 million.

Interest Income. Interest income increased by $0.4 million during the year ended December 31, 2005, compared to 2004. The increase is primarily due to an increase in interest earned on cash equivalents.

Interest Expense and Amortization of Deferred Financing Costs (a component of interest expense). Interest expense increased by $13.2 million, or 143%, during the year ended December 31, 2005, compared to 2004. Amortization of deferred financing costs increased by $1.7 million, or 32%, during the year ended December 31, 2005, compared to 2004. The increase was principally attributable to MarkWest Energy Partners’ additional outstanding debt from financing its Javelina and Starfish acquisitions.

Dividend Income. Dividend income increased by approximately $0.1 million, or 51%, during the year ended December 31, 2005, compared to 2004 as a result of the increase in investments in master limited partnerships. We began receiving distributions on the master limited partnerships during the second quarter of 2004.

Income tax (expense) benefit. The Company’s results of operations reflected a $1.8 million benefit for 2005 compared to a $0.1 million expense for 2004. The change was primarily due to the decrease in earnings from continuing operations, including non-controlling interest in net income of consolidated subsidiary.

Non-controlling Interest in Net Income of Consolidated Subsidiary. Non-controlling interest in net income of consolidated subsidiary decreased by $7.2 million as a result of the decrease in earnings of MarkWest Energy compared to 2004.

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

	MarkWest Hydrocarbon Standalone						MarkWest Energy Partners		Eliminating Entries			Total
	(in thousands)
Year Ended December 31, 2004:
Revenues	$				218,337		$	301,314	$	(59,538	)	$	460,113
Purchased product costs	185,951						211,534		(34,224		)	363,261
Facility expenses	23,983						29,911		(25,314		)	28,580
Selling, general and administrative expenses	11,999						16,133		—			28,132
Depreciation	1,339						15,556		—			16,895
Amortization of intangible assets	—						3,640		—			3,640
Accretion of asset retirement and lease obligations	2						13		—			15
Impairments	—						130		—			130
Total operating expenses	223,274						276,917		(59,538		)	440,653

Operating income (loss)	$			(4,937		)	$	24,397	$	—		$	19,460

Year Ended December 31, 2003:
Revenues	$		142,569				$	117,430	$	(50,731	)	$	209,268
Purchased product costs	142,633						70,832		(25,921		)	187,544
Facility expenses	25,304						20,463		(24,810		)	20,957
Selling, general and administrative expenses	7,267						8,598		—			15,865
Depreciation	1,247						7,548		—			8,795
Impairments	1,039						1,148		—			2,187
Total operating expenses	177,490						108,589		(50,731		)	235,348

Operating income (loss)	$	(34,921				)	$	8,841	$	—		$	(26,080	)

	Year Ended December 31,
	2004			2003
Operating income (loss)	$	19,460		$	(26,080	)
Interest income	647			106
Interest expense	(9,383		)	(4,347		)
Amortization of deferred financing cost (a component of interest expense)	(5,281		)	(2,104		)
Dividend income	259			—
Other income (expense)	788			(92		)
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	6,490			(32,517		)
Income tax (expense) benefit	(78		)	13,085
Non-controlling interest in net income of consolidated subsidiary	(7,315		)	(2,988		)
Loss from continuing operations	$	(903	)	$	(22,420	)

MarkWest Hydrocarbon Standalone

Revenues. Revenues increased $75.8 million, or 53%, over 2003 revenue primarily due to increases in NGL product sale prices and a 4% increase in volumes in Appalachia, which combined to increase revenue by approximately $37.1 million. In addition, revenue increased $33.2 million due to the commencement of a wholesale propane marketing business in 2004. Revenue in 2003 was reduced by losses on crude oil derivatives of $15.9 million. These increases were offset, in part, by a decrease in third party NGL sales of $10.1 million, as a result of the sale of the two terminals in 2003.

Purchased Product Costs. Purchased product costs increased $43.3 million, or 30%, in 2004 primarily due to costs from our wholesale propane marketing business introduced in 2004, adding $32.6 million. Our Appalachian natural gas liquids business incurred an additional $20.1 million, as a result of a 4% increase in volume and an increase in price of 27%. These increases were offset in part by a decrease in third party NGL product costs of $10.2 million as a result of the sale of the two terminals in 2003.

Facility Expenses. Facility expenses decreased by approximately $1.3 million, or 5%, as a result of a decrease in costs associated with two terminals in Appalachia, that were sold in 2003.

Selling, General and Administrative expenses. Selling, general and administrative expenses increased by $4.7 million, or 65%, as a result of stock option compensation of $2.0 million, increased incentive compensation and severance related expenses of $1.0 million and an increase in Sarbanes-Oxley compliance expenses and audit fees of $0.9 million. In addition, compensation expense resulting from the sale of the subordinated Partnership units and interests in the general partner to certain of MarkWest Hydrocarbon’s employees and directors from 2002 through 2004 increased selling, general and administrative expenses by $1.0 million. These increases were partially offset by a decrease in selling, general and administrative expenses attributed to discontinued operations that were sold in 2003.

Impairments. Impairments decreased by $1.0 million, or 100%, as a result of a 2003 write down in the value of the Company’s remaining Western Michigan oil and gas operations.

MarkWest Energy Partners

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

Purchased Product Costs. Purchased product costs were higher in 2004 by $140.7 million primarily due to the Partnership’s late 2003 and 2004 acquisitions, which increased its purchased product costs by $128.3 million. The remainder of the increase is primarily attributable to price and volume increases for our Appalachia NGL product sales. Price increases contributed $7.8 million and volume increases contributed an additional $4.6 million to purchased product costs.

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

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased by $7.5 million during the year ended December 31, 2004, compared to 2003 because MarkWest Hydrocarbon was contractually limited in the amount it could charge the Partnership to $4.9 million annually, from May 24, 2002, the date of the Partnership’s initial public offering, through May 23, 2003. In addition, selling, general and administrative expenses have increased due to increased administrative costs of $2.1 million associated with the Partnership’s acquisitions, increased Sarbanes-Oxley compliance related expenses and audit fees of $1.4 million, an increase in incentive compensation and severance expense of $1.0 million and professional services costs of $0.8 million. In addition, the allocation of compensation expense to the Partnership resulting from the sale of the subordinated Partnership units and interests in the Partnership’s general partner to certain of MarkWest Hydrocarbon’s employees and directors from 2002 through 2004 increased selling, general and administrative expenses by $1.4 million. The charge did not affect management’s determination of the Partnership’s distributable cash flow for any period, and did not affect net income attributed to the limited partners.

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

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

Impairments. During the fourth quarter of 2004, the Partnership recorded a write-off of $0.1 million of costs associated with an isomerization unit taken out of service. During the fourth quarter of 2003, the Partnership’s general partner’s board of directors approved a plan to replace the Partnership’s existing Cobb extraction facility with a new facility. Consequently, in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, Accounting for the Impairment or Disposal of Long Lived Assets, the Partnership wrote down the carrying value of the current Cobb facility by $1.1 million to its estimated fair value.

Other Income and Expenses

Interest Expense. Interest expense increased $5.0 million, or 116%, during 2004 relative to 2003 primarily due to increased debt levels resulting from the Partnership’s financing of its 2003 and 2004 acquisitions. A significant amount of the Partnership’s 2004 acquisitions were financed through additional borrowings under its credit facility and the issuance of its senior notes.

Amortization of Deferred Financing Costs. The increase in amortization of deferred financing costs in 2004 relative to 2003 primarily is attributable to the debt refinancings completed in 2004 as well as an increase in deferred financing cost as a result of the issuance of the Partnership’s senior notes. During 2004, we amortized approximately $5.2 million of deferred financing costs related to debt issuance costs incurred to finance the Partnership’s 2004 acquisitions, of which $1.5 million represented accelerated amortization due to the refinancing of the Partnership’s 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.

Dividend Income. Dividend income increased to $0.3 million during 2004 as a result of investments in marketable securities of Master Limited Partnerships. The Company did not have these investments in 2003.

Income from Discontinued Operations. The income from discontinued operations in 2003 is primarily attributable to the net gain on sales of our oil and gas properties during 2003.

Provision (benefit) for Income taxes. The Company’s results of operations reflected a $0.1 million provision for 2004 compared to a $13.1 million benefit for 2003. The change was due primarily to the $34.7 million increase in earnings from continuing operations, including non-controlling interest in net income of consolidated subsidiary.

Non-controlling Interest in Net Income of Consolidated Subsidiary. Non-controlling interest in net income of consolidated subsidiary increased by $4.3 million, or 145%, as a result of the increase in earnings of MarkWest Energy and an increase in ownership of non-controlling interests commensurate with private placements and public offerings to finance acquisitions.

Liquidity and Capital Resources

MarkWest Hydrocarbon Standalone

Our primary source of liquidity, to meet operating expenses and fund capital expenditures, is cash flow from operations, principally from the marketing of NGLs, and quarterly distributions received from MarkWest Energy Partners. Based on current volume, price and expense assumptions, we expect cash flow from operations and distributions from the Partnership to fund our operations and capital expenditures in 2005. Most of our future capital expenditures are discretionary. During 2005, we spent $0.8 million for capital expenditures, consisting principally of computer hardware and software.

We own 89% of the general partner of MarkWest Energy Partners, excluding interests held by certain employees and directors, but deemed owned by the Company through the Participation Plan. The general partner of MarkWest Energy Partners owns the 2% general partner interest and all of the incentive distribution rights. The incentive distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they entitle us to receive 13% of all cash distributed in a quarter after each unit has received $0.55 for that quarter; 23% of all cash distributed after each unit has received $0.625 for that quarter; and 48% of all cash distributed after each unit has received $0.75 for that quarter. For the year ended December 31, 2005, we received $7.7 million in distributions from our limited units, and $4.4 million from our general partner interest, of which $4.2 million represented payments on incentive distribution rights.

Cash flows generated from our NGL marketing and natural gas supply operations are subject to volatility in energy prices, especially prices for NGLs and natural gas. Our cash flows are enhanced in periods when the prices received for NGLs are high relative to the price of natural gas we purchase to satisfy our “keep-whole” contractual arrangements in Appalachia. Conversely, they are reduced in periods when the prices received for NGLs are low relative to the price of natural gas we purchase to satisfy such contractual arrangements. Under “keep-whole” contracts, we retain and sell the NGLs produced in our processing operations for third-party producers, and then reimburse or “keep-whole” the producers for the energy content of the NGLs removed through the re-delivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas. Generally, the value of the NGLs extracted is greater than the cost of replacing those Btus with dry gas, resulting in positive operating margins under these contracts. Periodically, natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, and the cost of keeping the producer “whole” can result in operating losses. We entered into several new and amended agreements in September 2004 with one of the largest Appalachia producers that allow us to significantly reduce our exposure to commodity price risk for approximately 25% of our keep-whole gas volumes. Under these agreements, the Company is limited on the costs it would have to pay to the producer should natural gas becomes more expensive than the NGL product sales price, thereby mitigating the risk of incurring operating losses. In connection with these agreements, we paid $3.3 million of consideration to the producer, that is being amortized as additional cost of the gas purchased over the term of the contracts, October 1, 2004, through February 9, 2015.

Debt

In October 2004, the Company entered into a $25.0 million senior credit facility with a term of one year. The $25.0 million revolving facility has a variable interest rate based on the base rate or the London Inter Bank Offering Rate (“LIBOR”), as discussed below. In October, November, and December 2005, the Company entered into the first, second and third amendment to the credit agreement. The first amendment extended the term of the original agreement to November 15, 2005. The second amendment reduced the lending amount from $25.0 million to $16.0 million, of which $6.0 million of availability is committed to a letter of credit, leaving $10.0 million available for revolving loans. The second amendment also extended the term of the revolving credit to December 30, 2005. The third amendment extended the term of the revolving credit to January 31, 2006 and reduced the lending amount from $16.0 million to $13.5 million, of which $6.0 million of availability is committed to a letter of credit, leaving $7.5 million available for revolving loans. On January 31, 2006, the Company entered into the first amended and restated credit agreement which reinstated the maximum lending limit of $25.0 million for a one year term.

The credit facility bears interest at a variable interest rate, plus basis points. The variable interest rate is typically based on 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 Revolver Facility Usage (as defined in the Company Credit Facility) to the Borrowing Base (as defined in the Company Credit Facility), ranging from 0.75% to 1.75% for Base Rate loans, and 1.75% to 2.75% for Eurodollar Rate loans. The Company pays a quarterly commitment fee on the unused portion of the credit facility at an annual rate of 50.0 basis points.

Under the provisions of the credit facility, the Company 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; declare or make, directly or indirectly, any restricted distributions.

As of December 31, 2005, the Company had outstanding borrowings of $7.5 million and no borrowing capacity.

We spent $0.3 million for capital expenditures for the year ending December 31, 2005. We have budgeted $0.8 million for 2006, consisting principally of computer hardware and software. We believe that cash on hand, cash received from quarterly distributions (including the incentive distribution rights) from MarkWest Energy Partners, and projected cash generated from our marketing operations will be sufficient to meet our working capital requirements and fund our required

capital expenditures, if any, for the foreseeable future. Cash generated from our marketing operations will depend on our operating performance, which will be affected by prevailing commodity prices and other factors, some of which are beyond our control.

MarkWest Energy Partners

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

The Partnership borrowed approximately $432.8 million, primarily to finance its acquisitions. The Partnership received approximately $100.0 million in proceeds from a private placement of common units, which was used to pay down its 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. 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 investment; incur liens; create any consensual limitation on the ability of the Partnership’s restricted subsidiaries to pay dividends, make loans or transfer property to the Partnership; engage in transactions with the Partnership’s affiliates; sell assets, including equity interest 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 has agreed to file an exchange offer registration statement, or under certain circumstances, a shelf registration statement, pursuant to a registration rights agreement relating to the 2004 senior notes. 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 the Partnership’s credit facility and funds from its private and public equity offerings are its primary sources of liquidity. The timing of the Partnership’s efforts to raise equity in the future, however, will be influenced by the Partnership’s inability to timely file its Annual Report on Form 10-K for the year ended December 31, 2004, and its quarterly report on Form 10-Q for the quarter ending March 31, 2005. The Partnership will no longer have the ability to incorporate by reference information from its filings into a new registration statement until June 25, 2006, should they choose to raise capital through a public offering registered on Form S-3. If the Partnership raises additional capital through public debt or equity offerings, it is 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 will affect the Partnership’s ability to access the capital markets on a timely basis and may increase the costs of doing so. The Partnership believes, nonetheless, that funds from raising equity, together with cash generated from operations and borrowings under its credit facility, will be sufficient to meet both its 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 the Partnership’s credit facility, or both.

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

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 its assets, or facilitate an increase in volumes within its 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

	Year Ended December 31,
	2005			2004			2003
	(in thousands)

Net cash provided by operating activities	$	16,874		$	26,616		$	(6,411	)
Net cash used in investing activities	(445,848		)	(303,017		)	(36,887		)
Net cash provided by financing activities	437,098			247,101			78,956

Net cash provided by operating activities decreased by $9.7 million during the year ended December 31, 2005, compared to the corresponding period of 2004, primarily due to a greater net loss in 2005, offset by increases in depreciation expense and amortization of intangibles, arising from the Partnership’s acquisition of Javelina in November 2005. Increases in inventory, customer margin deposits and prepaid fuel also contributed to the decline.

Net cash used in investing activities during the year ended December 31, 2005, consisted primarily of the $356.9 million for the Javelina acquisition, $41.7 million investment in Starfish, capital expenditures of $71.3 million for existing facilities and $8.7 million for purchases of marketable securities, offset by $17.3 million from sales of marketable securities. Net cash used in investing activities during the year ended December 31, 2004, primarily related to the $240.7 million East Texas System acquisition, $2.3 million Hobbs acquisition, capital expenditures of $12.7 million for existing facilities, $3.3 million for a contract to reduce exposure to commodity price risk and $11.5 million for investment in marketable securities.

Net cash provided by financing activities during the year ended December 31, 2005, consisted primarily of proceeds from long-term debt in excess of repayments of $386.5 million, proceeds from MarkWest Energy Partners private placements of $92.9 million, payments of debt issuance costs of $11.8 million, distributions by MarkWest Energy Partners of $26.1 million to unitholders other than MarkWest Hydrocarbon and the general partner, and cash dividends paid to shareholders of $4.3 million. Net cash provided by financing activities during the year ended December 31, 2004, consisted primarily of proceeds from long-term debt in excess of repayments of $791.4 million, proceeds from MarkWest Energy Partners’ public offerings and private placements of $183.7 million, payments of debt issuance costs of $15.6 million, distributions by MarkWest Energy Partners of $15.4 million to unitholders other than MarkWest Hydrocarbon and the general partner, proceeds from stock option exercises of $1.4 million, and cash dividends paid to shareholders of $5.8 million.

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(1)
MarkWest Energy Partners	$	604,000			$	2,738		$	7,300			$	368,962			$	225,000
MarkWest Hydrocarbon Standalone	7,500				—			7,500				—				—
Operating leases	11,869			4,755				4,936				1,975				203
Purchase obligations	2,163			2,163				—				—				—
Asset retirement obligations	1,102			—				—				—				1,102
Total contractual cash obligations	$		626,634	$			9,656	$		19,736		$		370,937		$		226,305

(1) Excluding interest

Off-Balance Sheet Arrangements

Other than facility and equipment leasing arrangements, we do 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 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. In early 2005, the Company 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 Company 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 Company continue to investigate the incident.

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

The Company has also been involved in a lawsuit captioned Ross Bros. Construction v. MarkWest Hydrocarbon, Inc., (U.S. Court of Appeals for the 6th Circuit, Case No. 05-6251, appealed from U.S. District Court Eastern District of Kentucky, Ashland Division, Civ. Action No. 01-CV-205). The underlying lawsuit involved the construction of the Siloam Kentucky plant and a dispute as to the monetary value of additional work beyond the contract’s lump sum price performed by the contractor. The lawsuit involved a claim of approximately $0.7 million in extra costs. The Company was granted Summary Judgment on its defense asserting accord and satisfaction. In August 2005, Plaintiffs filed an appeal of the Summary Judgment to the U.S. Court of Appeals for the 6th Circuit. The Company believes that, while it is not able to predict the outcome of this matter, based on the judge’s discussion on the grant of the summary judgment and denial of Ross Brothers’ motion for reconsideration, it is probable that the Company will prevail in the appeal. As a result, the Company has not provided for a loss contingency.

The Company has also been involved in an arbitration proceeding captioned Kevin Stowe and Scott Daves v. MarkWest Hydrocarbon, Inc., American Arbitration Association arbitration, Case No. 77 168 Y 0052 05 BEAH, Denver, Colorado, 2005. Claimants in this Arbitration had filed a proceeding against the Company seeking further payments out of a dispute and settlement over interests in certain wells in Colorado. On February 8, 2006, the Company was granted Summary Judgment and the Arbitration was accordingly dismissed.

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. In general, we store a portion of the propane that we produce in the summer as well as pre-purchase in the summer a portion of the natural gas that we are required to replace during the winter in accordance with our Appalachian keep-whole processing agreements.

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.

Critical Accounting Policies

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 Company’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.

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 dividends of $1.8 million, and accrued $1.5 million for a capital call. The Partnership’s share of Starfish’s loss in 2005 was $2.2 million.

The Partnership’s accounting policy requires it 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 the Partnership to determine if an equity method investment should be impaired and that an impairment, if any, is fairly reflected in its 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 Company’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 / relationships relate, likelihood of renewals, competitive factors, regulatory or legal provisions, and maintenance and renewal costs.

Impairment of Long-Lived Assets

The Company 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 is 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.

Derivative Instruments

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 Company elects hedge accounting treatment for specific derivatives, the Company formally documents, designates and assesses the effectiveness. As of December 31, 2005, no transactions had been designated for hedge accounting treatment. In general, the Company 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.

Revenue Recognition

The Company 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 Partners 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. The Partnership 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, the Partnership gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, the Partnership must either purchase natural gas at market prices for return to producers or make cash payment to the producers equal to the difference in the energy content of the natural gas stream before and after processing.

• 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, it is 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 those 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 Company meets all four revenue recognition criteria, and it is at such time that the Company recognizes revenue.

The Company’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.

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.

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. 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.

Stock and Incentive Compensation Plans

The Company 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.

Stock options are issued under the Company’s 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan. The plans allow for the exercise of stock options using the cashless method, but only at the discretion of the Company. Under a cashless exercise, the Company withholds those shares that otherwise would be issued upon the exercise of the option, the number of shares with a fair market value equal to the option exercise price and remits the remaining shares to the employees. Prior to April 2004, the Company did not allow participants to exercise their stock options using the cashless method. Accordingly, compensation expense was not recognized for stock options granted unless the options were granted at an exercise price less than the quoted market price of the Company on the grant date. In April 2004, the Company changed its policy to allow participants to exercise their stock options using the cashless method. Under APB No. 25, a fixed stock option plan that permits the use of a cashless exercise becomes variable if a pattern of exercising the stock options using the cashless method is demonstrated. As a result, in April 2004, the Company was required to account for stock options issued under the plans as variable awards. Compensation expense for stock options issued as variable awards is measured as the difference in the market value of the Company’s common stock and the exercise price of the stock options. The difference is amortized into earnings over the period of service as the options vest, adjusted quarterly for the change in the fair value of the unvested stock options awarded. Increases or decreases in the market value of the Company’s common stock between April 2004 and the end of each reporting period result in a change in the measure of compensation for vested awards, which is reflected currently in operations in selling, general and administrative expenses.

The Company also issues restricted stock under the Company’s 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan. In accordance with APB No. 25, the Company applies fixed accounting for the plans. As a result, since the restricted stock is granted for no consideration, compensation expense is recognized on the date of grant equal to the market price of the Company’s common stock. The fair value of the stock awarded is amortized into earnings over the period of service. The restricted stock vests over a stated period. These charges are included in selling, general and administrative expenses.

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 the statement of 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 Company. Compensation attributable to interests that were sold to individuals who serve on both the board of MarkWest Hydrocarbon and the Partnership’s board of directors is allocated equally.

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.

Recent Accounting Pronouncements

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

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 Company 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, 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 Company 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.

MarkWest Hydrocarbon Risk Management Activity

Since year end and as of March 1, 2006, MarkWest Hydrocarbon has pre-purchased natural gas for shrink requirements in future months and has entered into forward financial NGL sales to manage frac spread risk. The following table includes information on our specific derivative activities:

Commodity	Period	Quantity	Average Price
Natural Gas (pre-bought)	Oct-Dec 2006	1,000,000 MMBtu	$	7.02
Propane	Oct-Dec 2006	6,415,200 gal	$	0.93
Iso-Butane	Oct-Dec 2006	668,252 gal	$	1.12
Normal-Butane	Oct-Dec 2006	2,004,752 gal	$	1.10
Natural Gasoline	Oct-Dec 2006	1,336,500 gal	$	1.39

Hydrocarbon may enter into additional physical and/or financial positions to manage its risks related to commodity price exposure. Due to timing of gas purchases and liquid sales, direct exposure to either gas or liquids can be created because there is no longer an offsetting purchase or sale that remains exposed to market pricing. Through our marketing and derivatives activity, direct exposure may occur naturally or we may choose direct exposure to either gas or liquids when we favor that exposure over frac spread risk.

The Partnership’s Derivative Activity

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:

						Fair Value at
Costless Collars:	Period	Floor		Cap		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

				Fair Value at
Swaps		Fixed Price		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 the Partnership’s 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 Risk

The Company’s primary interest rate risk exposure results from the Partnership’s $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 the Partnership’s debt portfolio.

Long-term Debt	Due	Outstanding at December 31, 2005
Variable Rate ($25.0 million)	January 30, 2007	$	7.5 million
Variable Rate ($615.0 million)	December 31, 2010	$	379.0 million
Fixed Rate ($225.0 million)	November, 2014	$	225.0 million

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 Stockholders’ Equity 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

Report of Independent Registered Public Accounting Firm

To the Board of Directors of
MarkWest Hydrocarbon, Inc.
Englewood, Colorado

We have audited the accompanying consolidated balance sheet of MarkWest Hydrocarbon, Inc. and subsidiaries (the “Company”) as of December 31, 2005, and the related consolidated statements of operations, comprehensive income, changes in stockholders' equity, and cash flows for the year then ended. These financial statements are the responsibility of the Company’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 Hydrocarbon, Inc. 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 Company’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 20, 2006 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an adverse opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado
March 20, 2006

Report of Independent Registered Public Accounting Firm

The Board of Directors MarkWest Hydrocarbon, Inc.:

We have audited the accompanying consolidated balance sheet of MarkWest Hydrocarbon, Inc. and its subsidiaries (the Company) as of December 31, 2004, and the related consolidated statements of operations, comprehensive income, changes in stockholders’ equity, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’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 Hydrocarbon, Inc. 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

October 14, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of MarkWest Hydrocarbon, Inc.

In our opinion, the accompanying consolidated statements of operations, of comprehensive income, of changes in stockholders’ equity 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 Hydrocarbon, Inc., a Delaware company, and its subsidiaries (the Company) 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 Company’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.

As discussed in Note 10 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143 on January 1, 2003.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado
March 30, 2004, except as to the 2004 stock dividend described in Note 16 (presented herein), the reclassifications described in Note 2 and the restatements described in Note 23 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 October 17, 2005

MARKWEST HYDROCARBON, INC.

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)

	December 31, 2005			December 31, 2004
ASSETS
Current assets:
Cash and cash equivalents	$	20,968		$	12,844
Restricted cash	—			15,000
Marketable securities	6,070			14,815
Receivables, net of allowance for doubtful accounts of $175 and $249, respectively	145,539			64,856
Inventories	30,500			11,292
Prepaid replacement natural gas	10,567			10,245
Deferred income taxes	—			25
Other current assets	16,314			1,898
Total current assets	229,958			130,975

Property, plant and equipment	573,198			342,636
Less: accumulated depreciation	(78,500		)	(59,443		)
Total property, plant and equipment, net	494,698			283,193

Other assets:
Investment in Starfish	39,167			—
Intangible assets, net	346,496			162,001
Deferred financing costs, net of accumulated amortization of $4,424 and $5,541, respectively	18,463			13,849
Deferred contract cost, net of accumulated amortization of $390 and $78, respectively	2,860			3,172
Investment in and advances to other equity investee	182			177
Other long term assets	326			—
Notes receivable from related parties	154			207
Total other assets	407,648			179,406
Total assets	$	1,132,304		$	593,574

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable (including related party payables of $25 and $30, respectively)	$	119,105		$	45,103
Accrued liabilities	45,869			30,908
Fair value of derivative instruments	728			1,057
Deferred income taxes	362			—
Current portion of long-term debt	2,738			—
Total current liabilities	168,802			77,068

Deferred income taxes	3,487			6,258
Long-term debt	608,762			225,000
Other long-term liabilities	10,256			7,487
Non-controlling interest in consolidated subsidiary	301,015			228,000

Commitments and contingencies (Note 17)

Stockholders’ equity:
Preferred stock, par value $0.01, 5,000,000 shares authorized, no shares outstanding	—			—
Common stock, par value $0.01, 20,000,000 shares authorized, 10,857,939 and 10,821,760 shares issued, respectively	108			108
Additional paid-in capital	48,797			51,455
Deferred compensation	(398		)	—
Accumulated deficit	(8,425		)	(1,623		)
Accumulated other comprehensive income, net of tax	357			246
Treasury stock, 55,619 and 63,586 shares, respectively	(457		)	(425		)
Total stockholders’ equity	39,982			49,761
Total liabilities and stockholders’ equity	$	1,132,304		$	593,574

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

	Year Ended December 31,
	2005			2004			2003

Revenues	$	714,177		$	460,113		$	209,268

Operating expenses:
Purchased product costs	583,084			363,261			187,544
Facility expenses	45,577			28,580			20,957
Selling, general and administrative expenses	33,350			28,132			15,865
Depreciation and depletion	20,829			16,895			8,795
Amortization of intangible assets	9,656			3,640			—
Accretion of asset retirement obligation	160			15			—
Impairments	—			130			2,187
Total operating expenses	692,656			440,653			235,348

Income (loss) from operations	21,521			19,460			(26,080		)

Other income and (expense):
Loss from unconsolidated subsidiary	(2,153		)	—			—
Interest income	1,060			647			106
Interest expense	(22,622		)	(9,383		)	(4,347		)
Amortization of deferred financing costs (a component of interest expense)	(6,979		)	(5,281		)	(2,104		)
Dividend income	392			259			—
Miscellaneous income (expense)	266			788			(92		)
Income (loss) from continuing operations before non-controlling interest in net income of consolidated subsidiary and income taxes	(8,515		)	6,490			(32,517		)

Income tax (expense) benefit
Current	(554)			(20		)	13,680
Deferred	2,358			(58		)	(595		)
Income tax (expense) benefit	1,804			(78		)	13,085

Non-controlling interest in net income of consolidated subsidiary	(91		)	(7,315		)	(2,988		)

Loss from continuing operations	(6,802		)	(903		)	(22,420		)

Discontinued operations (Note 18):
Income from discontinued exploration and production operations (less applicable income taxes of $962 in 2003)	—			—			1,095
Gain from disposal of discontinued exploration and production operations (less applicable income taxes of $6,322)	—			—			10,348
Income from discontinued operations	—			—			11,443

Loss before cumulative effect of accounting change	(6,802		)	(903		)	(10,977		)

Cumulative effect of change in accounting for asset retirement obligations, net of income taxes	—			—			(29		)

Net loss	$	(6,802	)	$	(903	)	$	(11,006	)

Loss from continuing operations per share (Note 2):
Basic	$	(0.63	)	$	(0.08	)	$	(2.17	)
Diluted	$	(0.63	)	$	(0.08	)	$	(2.17	)

Net loss per share (Note 2):
Basic	$	(0.63	)	$	(0.08	)	$	(1.07	)
Diluted	$	(0.63	)	$	(0.08	)	$	(1.07	)

Weighted average number of outstanding shares of common stock (Note 2):
Basic	10,785			10,686			10,328
Diluted	10,785			10,686			10,328

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

	Year Ended December 31,
	2005			2004			2003

Net loss	$	(6,802	)	$	(903	)	$	(11,006	)

Other comprehensive income (loss):
Unrealized gains (losses) on marketable securities, net of income tax benefit of $92 and income tax provision of $291, respectively	(153		)	526			—
Unrealized gains (losses) on commodity derivative instruments accounted for as hedges, net of income taxes of $158, $825 and $4,134, respectively	264			1,513			6,390
Foreign currency translation, net of income taxes	—			—			675
Total other comprehensive income	111			2,039			7,065

Comprehensive income (loss)	$	(6,691	)	$	1,136		$	(3,941	)

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDERS’ EQUITY

(in thousands)

	Shares of Common Stock		Shares of Treasury Stock		Common Stock		Additional Paid-In Capital			Deferred Compensation			Accumulated Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total Stockholders’ Equity

Balance, December 31, 2002	10,308		(50	)	$	105	$	48,808		—			$	13,412		$	(8,858	)	$	(328	)	$	53,139
Exercise of options	294		—		1		1,897			—			—			—			—			1,898
Treasury stock acquired	—		(58	)	—		—			—			—			—			(390		)	(390		)
Treasury stock reissued	—		32		—		—			—			—			—			208			208
Net loss	—		—		—		—			—			(11,006		)	—			—			(11,006		)
Other comprehensive income	—		—		—		—			—			—			7,065			—			7,065
Balance, December 31, 2003	10,602		(76	)	106		50,705			—			2,406			(1,793		)	(510		)	50,914
Exercise of options	175		—		2		1,390			—			—			—			—			1,392
Modification of stock options	45		—		—		1,994			—			—			—			—			1,994
Treasury stock acquired	—		(3	)	—		—			—			—			—			(39		)	(39		)
Treasury stock reissued	—		15		—		68			—			—			—			124			192
Net loss	—		—		—		—			—			(903		)	—			—			(903		)
Other comprehensive income	—		—		—		—			—			—			2,039			—			2,039
Dividends paid	—		—		—		(2,702		)	—			(3,126		)	—			—			(5,828		)
Balance, December 31, 2004	10,822		(64	)	108		51,455			—			(1,623		)	246			(425		)	49,761
Stock option exercises	15		—		—		77			—			—			—			—			77
Issuance of restricted stock	—		3		—		(57		)	—			—			—			57			—
Grant of restricted stock	—		—		—		482			(482		)	—			—			—			—
Amortization of deferred stock-based compensation	—		—		—		—			84			—			—			—			84
Stock options converted to restricted stock	—		—		—		66			—			—			—			—			66
Cashless stock options	21		—		—		965			—			—			—			—			965
Treasury stock acquired	—		(7	)	—		—			—			—			—			(161		)	(161		)
Contribution of treasury shares to 401(k) benefit plan	—		12		—		124			—			—			—			72			196
Net loss	—		—		—		—			—			(6,802		)	—			—			(6,802		)
Dividends	—		—		—		(4,315		)	—			—			—			—			(4,315		)
Other comprehensive income	—		—		—		—			—			—			111			—			111
Balance, December 31, 2005		10,858	(56	)	$	108	$	48,797		$	(398	)	$	(8,425	)	$	357		$	(457	)	$	39,982

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2005			2004			2003

Cash flows from operating activities:
Net loss	$	(6,802	)	$	(903	)	$	(11,006	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Cumulative effect of change in accounting principle	—			—			29
Depreciation and depletion	20,829			16,895			24,489
Amortization of intangible assets	9,656			3,640			—
Amortization of deferred financing costs	6,979			5,281			2,104
Amortization of gas contract	312			78			—
Accretion of asset retirement obligation	160			15			—
Impairments	—			130			2,187
Non-controlling interest in net income of consolidated subsidiary	91			7,315			2,988
Equity in loss of investees	2,153			73			—
Distribution from Starfish	1,849			—			—
Unrealized losses/(gains) on derivative instruments	—			762			(3,188		)
Deferred income taxes	(2,358		)	39			(2,139		)
Stock option compensation expense	965			1,994			—
Restricted stock compensation expense	150			—			—
Restricted unit compensation expense	1,076			1,065			1,357
Participation Plan compensation expense	3,244			3,711			1,303
Contribution of treasury shares to 401(k) benefit plan	196			192			208
Gain from sale of San Juan Basin properties	—			—			(23,279		)
Loss from sales of MarkWest Resources Canada Corp. and MarkWest Midstream Services, Inc.	—			—			4,822
Loss from sale of eastern Michigan oil and gas properties	—			—			1,788
Loss from sale of other operating assets	—			—			30
Gain from sale of property, plant and equipment	(407		)	(63		)	—
Gain from sale of marketable securities	(56		)	(37		)	—
Reclassification of Enron hedges to purchased product costs	—			—			(153		)
Other	—			(1		)	—

Changes in operating assets and liabilities, net of working capital acquired in acquisitions:
Increase in receivables	(1,372		)	(34,946		)	(390		)
Increase in inventories	(17,420		)	(5,744		)	(1,201		)
Increase in prepaid replacement natural gas and other assets	(322		)	(4,305		)	(7,380		)
Increase in other current assets	(14,742		)	(1,395		)	—
Decrease in notes receivables from officers	53			10			—
Decrease in other assets	—			28			—
Increase in accounts payable and accrued liabilities	12,640			32,299			8,210
Increase (decrease) in other long-term liabilities	—			483			(7,190		)
Net cash provided by (used in) operating activities	16,874			26,616			(6,411		)

Cash flows from investing activities:
Decrease (increase) in restricted marketable securities	—			2,500			(2,500		)
Decrease (increase) in restricted cash	15,000			(15,000		)	—
Purchase of marketable securities	(8,725		)	(15,053		)	—
Proceeds from sale of marketable securities	17,275			1,092			—
Javelina acquisition, net of cash acquired	(356,917		)	—			—
East Texas system acquisition	—			(240,726		)	—
Hobbs pipeline acquisition	—			(2,275		)	—
Pinnacle acquisition, net of cash acquired	—			—			(38,526		)
Lubbock pipeline acquisition	—			—			(12,235		)
Western Oklahoma acquisition	—			—			(37,951		)
Michigan Crude Pipeline acquisition	—			—			(21,283		)
Capital expenditures	(71,343		)	(30,654		)	(31,007		)
Proceeds from sale of San Juan Basin properties	—			—			55,251
Proceeds from the sale of MarkWest Resources Canada Corp. and MarkWest Midstream Services, Inc.	—			—			49,097
Payments on financing lease receivable	—			133			—
Proceeds from sale of property, plant and equipment	550			216			2,517
Payment on long-term gas purchase contracts	—			(3,250		)	—
Investment in equity affiliate	(41,688		)	—			(250		)
Net cash used in investing activities	(445,848		)	(303,017		)	(36,887		)

Cash flows from financing activities:
Payments for deferred offering costs	—			—			(389		)
Proceeds from long-term debt	910,500			220,100			452,778
Repayments of long-term debt	(524,000		)	(346,300		)	(373,925		)
Proceeds from private placement of senior notes	—			225,000			—
Proceeds from secondary public offerings, net	—			139,630			—
Payments for debt issuance costs	(11,809		)	(15,643		)	(4,070		)
Proceeds from MarkWest Energy’s private placements, net	92,887			44,139			9,774
Distributions to MarkWest Energy unitholders	(26,081		)	(15,350		)	(7,214		)
Payment of dividends	(4,315		)	(5,828		)	—
Exercise of stock options	77			1,392			1,899
Purchase of treasury shares	(161		)	(39		)	(390		)
Proceeds from sale of MarkWest Energy units	—			—			493
Net cash provided by financing activities	437,098			247,101			78,956

Effect of exchange rate on changes on cash	—			—			76

Net increase (decrease) in cash and cash equivalents	8,124			(29,300		)	35,734
Cash and cash equivalents at beginning of year	12,844			42,144			6,410
Cash and cash equivalents at end of year	$	20,968		$	12,844		$	42,144

Supplemental disclosures of cash flow information:
Cash paid (received) during the year for:
Interest, net of amounts capitalized	$	22,225		$	6,532		$	3,868
Income taxes	549			—			(114		)

Supplemental disclosures of non-cash investing and financing activities:
Construction projects in process obligation	$	1,545		$	4,037		—
Property, plant and equipment asset retirement obligation	561			377			3,994
Deferred offering costs	—			—			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 HYDROCARBON, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

MarkWest Hydrocarbon, Inc. (“MarkWest Hydrocarbon”) manages MarkWest Energy Partners, L.P. (“MarkWest Energy Partners” or the “Partnership”), a publicly traded master limited partnership, engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids (“NGLs”); and the gathering and transportation of crude oil. The Company also markets natural gas and NGLs. MarkWest Hydrocarbon and MarkWest Energy Partners provide services primarily in Appalachia, Michigan, East Texas, Western Oklahoma and other areas of the southwest. Through eight acquisitions completed during 2003, 2004 and 2005, the Company expanded its natural gas-gathering, processing and transmission geographic coverage to the southwest United States. In addition, one of the Company’s acquisitions has allowed it to enter into the Michigan crude oil transportation business. The Company’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 Hydrocarbon, Inc., MarkWest Energy Partners, L.P. and all of its majority-owned subsidiaries (collectively “the Company”) and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The Company’s consolidated financial statements include the accounts of all majority-owned subsidiaries. Equity investments in which the Company exercises significant influence, but does not control and is not the primary beneficiary, are accounted for using the equity method. Intercompany balances and transactions have been eliminated.

Non-Controlling Interest in Consolidated Subsidiary

The non-controlling interest in consolidated subsidiary on the consolidated balance sheet represents the initial investment by the partners other than MarkWest Hydrocarbon in the Partnership, plus those partners’ share of the net income of the Partnership since its initial public offering on May 24, 2002. Non-controlling interest in net income of consolidated subsidiary in the consolidated statement of operations represents those partners’ share of the net income of the Partnership.

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 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.

Cash and Cash Equivalents

The Company 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.

Restricted Cash

Under the Company’s credit facility, it can be required to keep a minimum available cash and/or marketable securities reserve of $15.0 million, which is to be reduced to zero in the event the Company restructures a keep-whole contract with one of its significant customers.

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.

Prepaid Replacement Natural Gas

Prepaid replacement natural gas consists of natural gas purchased in advance of its actual use valued using the weighted average cost method.

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 Company 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 Company 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 Company.

Investment in Starfish

• 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

Impairment of Long-Lived Assets

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.

Deferred Contract Costs

The Company entered into a series of agreements with a gas producer in September 2004, under which the Company processes natural gas under modified keep-whole arrangements. In connection with these agreements, the Company paid $3.3 million of consideration to the producer in connection with these non-separable contracts, which are being amortized as additional cost of the gas purchased over the term of the contracts, October 1, 2004 through February 9, 2015. Amortization related to these contracts for the years ended December 31, 2005 and 2004 was $0.4 million and $0.1 million, respectively.

Deferred income

Deferred income represents prepayments received under fixed fee contracts to deliver NGLs at a future date. Deferred income is recognized as revenue upon delivery of the product.

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 Company elects hedge accounting treatment for specific derivatives, the Company formally documents, designates and assesses the effectiveness. As of December 31, 2005, no transactions had been designated for hedge accounting treatment. In general, the Company 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.

Treasury Stock

Treasury stock purchases are accounted for under the cost method, whereby the entire cost of the acquired stock is recorded as treasury stock. Treasury stock reissued is relieved on a weighted average cost basis.

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 MarkWest Hydrocarbon’s Credit Facility and the Partnership’s Credit Facility (Note 11) approximates fair value due to their variable interest rates. The estimated fair value of the Partnership’s Senior Notes (Note 11) 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 12) are recorded at fair value, based on available market information.

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.

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.

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.

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.

Stock and Incentive Compensation Plans

The Company has elected to continue to measure compensation costs for equity-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 Company has also entered into arrangements with certain directors and employees of the Company referred to as the Participation Plan. Periodically, the Company sells subordinated partnership units of the Partnership, and interests in the Partnership’s general partner, to employees and directors of the Company under a purchase and sale agreement. In accordance with the provisions of APB No. 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.

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.

Had compensation cost for the Company’s stock-based and unit-based compensation plans been determined based on the fair value at the grant dates under those plans consistent with the method prescribed by SFAS No. 123, Accounting for Stock-Based Compensation, the Company’s net income and earnings per share would have been reduced to the pro forma amounts listed below (in thousands, except per share data):

	Year Ended December 31,
	2005			2004			2003

Net loss, as reported	$	(6,802	)	$	(903	)	$	(11,006	)
Add: compensation expense included in reported net loss	6,341			6,770			2,701
Deduct: total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effect	(5,215		)	(4,681		)	(2,927		)
Pro forma net income (loss)	$	(5,676	)	$	1,186		$	(11,232	)

Net loss per share:
Basic, as reported	$	(0.63	)	$	(0.08	)	$	(1.07	)
Basic, pro forma	$	(0.53	)	$	0.11		$	(1.09	)
Diluted, as reported	$	(0.63	)	$	(0.08	)	$	(1.07	)
Diluted, pro forma	$	(0.53	)	$	0.11		$	(1.09	)

Income Taxes

Deferred income taxes are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases using enacted tax rates. A valuation allowance is provided for deferred tax assets if it is more likely than not these items will expire before the Company is able to realize their benefit.

Comprehensive Income

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

Earnings (Loss) Per Share

Basic earnings (loss) per share is computed on the basis of the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share is computed on the basis of the weighted average number of shares of common stock plus the effect of dilutive potential common shares outstanding during the period using the treasury stock method. Dilutive potential common shares include outstanding stock options and stock awards. All share information has been adjusted to give retroactive effect to stock dividends paid, see Note 16.

The following are the number of shares used to compute the basic and diluted earnings per share (in thousands):

	Year ended December 31,
	2005	2004	2003

Basic earnings per share:
Weighted average shares outstanding	10,785	10,686	10,328
Dilutive earnings per share:
Weighed average shares outstanding	10,785	10,686	10,328
Dilutive effect of exercise of options outstanding	116	54	19
Dilutive shares	10,901	10,740	10,347

Foreign Currency Translation

On December 2, 2003, the Company sold all of its Canadian subsidiaries and, consequently, no longer has assets, liabilities or operations that require foreign currency translation. Prior thereto, assets and liabilities of the Company’s Canadian subsidiary, which used the Canadian dollar as its functional currency, were translated into United States dollars at the foreign currency exchange rate in effect at the applicable reporting date, and the statements of operations data were translated at the average rates in effect during the applicable period. The resulting cumulative translation adjustment was recorded as a separate component of other comprehensive income.

Recent Accounting Pronouncements

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 Company 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.

3. Acquisitions by MarkWest Energy Partners

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. 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	$	970,041		$	766,692	$	301,537
Net income (loss) from continuing operations	$	(16,362	)	$	53,909	$	(28,085	)

Net income (loss) from continuing operations per share:
Basic	$	(1.52	)	$	0.38	$	(2.72	)
Diluted	$	(1.52	)	$	0.38	$	(2.72	)

Weighted average number of outstanding shares of common stock:
Basic	10,785			10,686		10,328
Diluted	10,785			10,740		10,328

4. Marketable Securities

Marketable securities are classified as available-for-sale and stated at market based on the closing price of the securities at the balance sheet date. Accordingly, unrealized gains are reflected in other comprehensive income, net of applicable income taxes. For losses that are other than temporary, the cost basis of the securities is written down to fair value, and the amount of the write down is reflected in the statement of operations. The Company utilizes a first-in first-out cost basis to compute realized gains and losses. Realized gains and losses, dividends, interest income, and the amortization of discounts and premiums are reflected in the statement of operations.

The following are the components of marketable securities (in thousands):

	Cost Basis		Unrealized gains		Unrealized losses			Recorded Basis
December 31, 2005
Equity securities:
Master limited partnership units	$	5,497	$	714	$	(142	)	$	6,070

December 31, 2004
Equity securities:
Master limited partnership units	$	5,248	$	872	$	(19	)	$	6,101
Fixed maturities:
Mortgage backed securities (due after one year through five years)	8,750		10		(46		)	8,714
Total marketable securities, classified as current	$	13,998	$	882	$	(65	)	$	14,815

Net unrealized gains on marketable securities of $0.4 million, net of the related tax effect of $0.2 million, are reflected as a component of other comprehensive loss at December 31, 2005.

At December 31, 2004, unrealized gains of $0.9 million relate primarily to investments in equity securities of domestic energy partnerships. Unrealized losses of $0.1 million relate primarily to master limited partnership units and mortgage backed securities and are primarily attributable to changes in interest rates. Net unrealized gains on marketable securities of $0.8 million, net of the related tax effect of $0.3 million, are reflected as a component of other comprehensive income at December 31, 2004.

5. Significant Customers and Concentration of Credit Risk

For the year ended December 31, 2005 sales to one customer from MarkWest Hydrocarbon Standalone (see note 21 for discussion of segments) accounted for 10% of its revenues. MarkWest Hydrocarbon had a $1.7 million receivable from this customer as of December 31, 2005.

MarkWest Energy Partners’ business is concentrated within the Appalachian Basin, Southwest United States and Michigan geographic areas. Changes and events within these regions have the potential to impact the Partnership. For the years ended December 31, 2005, 2004 and 2003, sales to one customer other than MarkWest Hydrocarbon of the Partnership accounted 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.

6. Receivables and Other Current Assets

Receivables consist of the following (in thousands):

	December 31,
	2005		2004
Trade, net	$	135,008	$	56,057
Related party	—		44
Other	10,531		8,755
Total receivables	$	145,539	$	64,856

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

	December 31,
	2005		2004
Customer margin deposits	$	6,598	$	245
Prepaid fuel	8,696		1,174
Prepaid other	1,020		479
Total other current assets	$	16,314	$	1,898

7. Properties, Plant and Equipment

Property, plant and equipment consist of:

	December 31,
	2005			2004
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
Furniture, office equipment and other	2,864			4,113
Land, building and other equipment	13,823			9,418
Construction in-progress	41,895			28,944
	573,198			342,636
Accumulated depreciation	(78,500		)	(59,443		)
	$	494,698		$	283,193

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

Cobb Processing Plant

During 2003, MarkWest Energy Partners 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, MarkWest Energy Partners 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.

8. Intangible Assets

The Company’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

9. Accrued Liabilities

Accrued liabilities consist of the following (in thousands):

	December 31,
	2005		2004
Product and operations	$	17,987	$	14,407
Customer obligations	3,380		1,911
Professional services	2,054		518
Taxes	3,014		1,901
Interest	3,273		2,876
Javelina working capital adjustment	5,402		—
Starfish contribution	1,486		—
Construction in progress	2,652		2,602
Deferred income	1,937		3,518
Bonus and profit sharing, severance and vacation accruals	3,349		2,028
Phantom unit compensation expense accrual	958		327
Other	377		820
Total accrued liabilities	$	45,869	$	30,908

10. Asset Retirement Obligation

The Company adopted SFAS 143, Accounting for Asset Retirement Obligations, on January 1, 2003. Under SFAS 143, the fair value of a liability for an asset retirement obligation is recognized 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 Company’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 Company also has land leases that require the Company to return the land to its original condition upon the termination of the lease. In connection with the adoption of SFAS 143, the Company reviewed current laws and regulations governing obligations for asset retirements and leases, as well as the Company’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	$	3,367
Liabilities accrued during the period	1,197
Liabilities settled	(4,188		)
Accretion expense	128
Asset retirement obligation as of December 31, 2003	504
Liabilities accrued during the period	377
Liabilities settled	(4		)
Accretion expense	15
Asset retirement obligation as of December 31, 2004	892
Liabilities accrued during the period	554
Liabilities settled	(504		)
Accretion expense	160
Asset retirement obligation as of December 31, 2005	$	1,102

MarkWest Hydrocarbon’s assets subject to asset retirement obligations, exclusive of assets owned by MarkWest Energy, were primarily oil and gas wells. The Company discontinued its exploration and production business and sold off substantially all of its assets as of December 31, 2003.

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

11. Debt

Debt as of December 31, 2005 and 2004, is summarized below (in thousands):

	December 31,
	2005			2004
	(in thousands)

MarkWest Hydrocarbon Credit Facility
Revolver facility, 8.75% interest at December 31, 2005, due January 30, 2007	$	7,500		$	—

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			—

Partnership Senior Notes
Senior Notes, 6.875% interest, due November 2014	225,000			225,000
Total debt	611,500			225,000
Less: obligations due in one year	(2,738		)	—
Long-term portion	$	608,762		$	225,000

MarkWest Hydrocarbon Credit Facility

In October 2004, the Company entered into a $25.0 million senior credit facility with a term of one year. The $25.0 million revolving facility had a variable interest rate based on the base rate, which is equal to the higher of a) the Federal Funds Rate plus ½ of 1%, and b) the rate of interest in effect for such day as publicly announced from time to time by the Administrative Agent as its prime rate, plus the applicable rate, which is based on a utilization percentage. In October, November, and December 2005, the Company entered into the first, second and third amendment to the credit agreement. The first amendment extended the term of the original agreement to November 15, 2005. The second amendment reduced the lending amount from $25.0 million to $16.0 million, of which $6.0 million of availability is committed to a letter of credit, leaving $10.0 million available for revolving loans. The second amendment also extended the term of the revolving credit to December 30, 2005. The third amendment extended the term of the revolving credit to January 31, 2006 and reduced the lending amount from $16.0 million to $13.5 million, of which $6.0 million of availability is committed to a letter of credit, leaving $7.5 million available for revolving loans. If the revolving credit is converted into a term loan, the term will be extended to December 29, 2006.

On January 31, 2006, the Company entered into the first amended and restated credit agreement, which provides a maximum lending limit of $25.0 million for a one year term.

The credit facility bears 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 Revolver Facility Usage (as defined in the Company Credit Facility) to the Borrowing Base (as defined in the Company Credit Facility), ranging from 0.75% to 1.75% for Base Rate loans, and 1.75% to 2.75% for Eurodollar Rate loans. The Company pays a quarterly commitment fee on the unused portion of the credit facility at an annual rate of 50.0 basis points.

Under the provisions of the Company Credit Facility, the Company 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; declare or make, directly or indirectly, any restricted distributions.

The credit facility also contains covenants requiring the Company to maintain:

• a ratio of not more than 3.50 to 1.00 of total consolidated debt to consolidated EBITDA for any fiscal quarter-end;

• a minimum net worth of a) $34.0 million plus, b)50% of consolidated net income (if positive) earned on or after October 1, 2005 plus, c) 100% of net proceeds of all equity issued by the Company subsequent to January 31, 2006; and

• a minimum available cash and marketable securities reserve of $13.0 million, which is to be reduced to zero in the event the Company restructures a keep-whole contract with one of its significant customers.

MarkWest Energy Partners

Partnership Credit Facility

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 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 16).

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 indenture governing the senior notes limits the activity of the Partnership and its restricted subsidiaries. The provisions of such indenture places limits on the ability of the Partnership and its restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of the Partnership’s restricted subsidiaries to pay dividends, make loans or transfer property to the Partnership; engage in transactions with the Partnership’s affiliates; sell assets, including equity interest 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. Subject to compliance with certain covenants, the Partnership 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 Partnership has agreed to file an exchange offer registration statement or, under certain circumstances, a shelf registration statement, pursuant to a registration rights agreement relating to the 2004 senior notes. 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%. The registration statement was filed on January 17, 2006, and the interest penalty ceased on March 7, 2006.

The aggregate amount of minimum principal payments required on long-term debt in each of the years indicated are as follows as of December 31, (in thousands):

2006	$	2,738
2007	11,150
2008	3,650
2009	3,650
2010	365,312
2011 and thereafter	225,000
	$	611,500

12. Derivative Financial Instruments

Commodity Instruments

MarkWest Hydrocarbon

MarkWest Hydrocarbon may enter into physical and/or financial positions to manage its risks related to commodity price exposure. Due to timing of gas purchases and liquid sales, direct exposure to either gas or liquids can be created because there is no longer an offsetting purchase or sale that remains exposed to market pricing. Through our marketing and derivatives activity, direct exposure may occur naturally or we may choose direct exposure to either gas or liquids when we favor that exposure over frac spread risk.

As of December 31, 2004, the Company had NGL swap agreements relating to 11,928,000 NGL gallons with a weighted average fixed price of $0.85 per gallon. These swaps settled in the first quarter of 2005. The NGL swaps were not designed as hedges. As a result, changes in the fair value of the NGL swaps were reflected currently in earnings.

MarkWest Energy Partners

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, NGL’s and crude. 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	Period	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

As of December 31, 2004, the Partnership had natural gas swap agreements relating to 182,500 MMBtu, of forecasted natural gas sales with a fixed price of $4.26 per MMBtu. These swaps settled in the first quarter of 2005. 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	$	(2,541	)	$	(3,661	)	$	(19,501	)
Unrealized gains (losses) – revenue	(657		)	(84		)	2,400
Other comprehensive income – changes in fair value	(1,279		)	(1,826		)	(12,842		)
Other comprehensive income – settlement	1,593			3,661			19,501

	December 31,
	2005			2004
Unrealized losses – current liability	$	(728	)	$	(1,057	)
Accumulated other comprehensive income (loss)	—			314

Interest rate swap

The Company reclassified $0.3 million and $0.2 million from other comprehensive income, net of $0.1 million and $0.1 million of deferred taxes, in 2004 and 2003, respectively, related to a discontinued interest rate hedge.

13. Income Taxes

The components of the provision (benefit) for income taxes from continuing operations are as follows (in thousands):

	December 31,
	2005			2004			2003

Current income tax expense (benefit):
Federal	$	502		$	20		$	(12,258	)
State	52			—			(1,422		)
Total current	554			20			(13,680		)

Deferred income tax expense (benefit):
Federal	(2,839		)	(286		)	554
State	481			344			41
Total deferred	(2,358		)	58			595

Provision (benefit) for income taxes	$	(1,804	)	$	78		$	(13,085	)

A reconciliation of the actual provision (benefit) for income taxes from continuing operations and the amount computed by applying the federal statutory rate of 34% to the income (loss) before income taxes is as follows (in thousands):

	December 31,
	2005			2004			2003

Federal income tax at statutory rate (1)	$	(2,926	)	$	(280	)	$	(12,072	)
State income taxes, net of federal benefit	(294		)	7			(834		)
Permanent items	16			—			—
Stock options subject to variable accounting	—			369			—
Percentage depletion in excess of cost basis	—			(37		)	—
Nondeductible expenses	—			21			—
Prior year adjustment for state NOL carryforward	—			(1,085		)	—
Change in valuation allowance	1,053			1,121			—
Change in estimate of blended state rate	117			117			—
Impact of state amended tax returns	—			177			—
Alternative minimum tax credit	—			(373		)	—
Other	230			41			(179		)

Provision (benefit) for income taxes	$	(1,804	)	$	78		$	(13,085	)

(1) The calculation of federal income tax at statutory rate has been adjusted for the non-controlling interest in net income of consolidated subsidiary.

The deferred tax assets and liabilities resulting from temporary book-tax differences are comprised of the following (in thousands):

	December 31,
	2005			2004
Current deferred tax assets
Accruals and Reserves	$	157		$	261
Deferred Income	—			80
Derivative Instruments	—			202
Stock Compensation	32			—
Other	7			—
Current deferred tax assets	196			543

Current deferred tax liabilities
Investment in Third Party Partnerships	343			171
Marketable Securities	215			302
Other	—			45
Current deferred tax liabilities	558			518

Current Subtotal	(362		)	25

Long-term deferred tax assets
Accruals and Reserves	—			21
Participation Plan Compensation	1,626			1,418
Property, Plant, and Equipment	135			1,630
Stock Compensation	84			—
Tax Credit Carryforward	2,920			2,995
Federal Net Operating Loss Carryforward	6,145			—
State Net Operating Loss Carryforward	2,278			1,121
Other	—			(7		)
Long-term deferred tax assets	13,188			7,178
Valuation Allowance	(2,278		)	(1,121		)
Net long-term deferred tax assets	10,910			6,057

Long-term deferred tax liabilities
Investment in Consolidated Subsidiary	14,397			12,315
Long-term deferred tax liabilities	14,397			12,315

Long-term Subtotal	(3,487		)	(6,258		)

Net deferred tax liability	$	(3,849	)	$	(6,233	)

At December 31, 2005, the Company had federal net operating loss carryforwards of $18.1 million that expire in 2026 and state net operating loss carryforwards of $51.5 million that expire between 2013 and 2026. The Company expects that future taxable income will likely be apportioned to states other than those in which the net operating loss was generated. As a result, the Company believes it is more likely than not that the state net operating losses will not be realized and has provided a 100% valuation allowance against this long-term deferred tax asset. The Company had federal alternative minimum tax credit carryforwards of $2.9 million that have no expiration date and can be applied as a credit to reduce regular federal income tax.

14. Stock and Incentive Compensation Plans

At December 31, 2005, the Company has four stock-based compensation plans, one of which is through its consolidated subsidiary, MarkWest Energy. These plans are described below.

Stock Options

Under the 1996 Stock Incentive Plan, the Company may grant options to its employees for up to 925,000 shares of common stock. Under this plan, the exercise price of each option equals the market price of the Company’s stock on the date of the grant, and the maximum term of the option is ten years. Options are granted periodically throughout the year and vest at the rate of 25% per year for options granted in 1999 and thereafter, and 20% per year for options granted prior to 1999. At December 31, 2005, there were 176,078 options available for grant under this plan.

Under the 1996 Non-employee Director Stock Option Plan, the Company may grant options to its non-employee directors for up to 30,000 shares of common stock. There are no options available for grant at December 31, 2005. Under this plan, the exercise price of each option equals the market price of the Company’s stock on the date of the grant, and the maximum term of an option is three years. Options are granted upon the date the director first becomes a director and biannually thereafter. Options granted upon the date the director first becomes a director vest at the rate of 33% per year. Subsequent, biannual options vest 100% on the first anniversary of the option grant date.

The plans allow for the exercise of stock options using the cashless method, but only at the discretion of the Company. In April 2004, the Company changed its policy to allow participants to exercise their stock options using the cashless method and, as a result recognized $1.6 million of compensation expense. During the three months ended March 31, 2004, two officers resigned from the Company. Because the former officers continued to serve on the Company’s Board of Directors, the Company agreed that the individual’s stock options would continue to vest and be exercisable in accordance with the original vesting and exercise provisions. Consequently, the Company recognized $0.4 million of expense. Due to the modification to the stock options for these officers, the outstanding stock options are accounted for as a variable award.

The following summarizes the impact of the Company’s stock option plans (in thousands):

	2005		2004		2003
Options exercised, cashless	33		126		—
Shares issued, cashless	21		45		—
Options exercised, cash	15		155		261
Shares issued, cash	15		175		294
Compensation expense	$	1.0	$	2.0	$	—

Shares issued for cash are greater than the number of options exercised due to stock splits in 2004 and 2003.

The Company did not grant any stock options in 2005. The fair value of each option granted in 2004 and 2003 was estimated using the Black-Scholes option-pricing model. The following assumptions were used to compute the weighted average fair value of options granted:

	2004		2003
Expected life of options	6 years		6 years
Risk free interest rates	3.62	%	3.48	%
Estimated volatility	32	%	51	%
Dividend yield	4.7	%	0.0	%

A summary of the status of the Company’s stock option plans as of December 31, 2005, 2004 and 2003, and changes during the years then ended are presented below. Stock option information in the following table has not been adjusted to give retroactive effect to stock dividends paid. See note 16.

	2005				2004				2003
	Shares		Weighted- Average Price		Shares		Weighted- Average Price		Shares		Weighted- Average Price
Outstanding at beginning of year	171,688		$	8.43	440,080		$	8.35	728,315		$	9.06
Granted	—		—		33,500		12.62		45,750		8.44
Effect of stock dividends	—				15,072				83,042
Exercised	(48,170	)	7.62		(280,776	)	8.37		(261,141	)	8.11
Cancelled	(9,511	)	14.37		(36,188	)	11.67		(155,886	)	8.78
Outstanding at end of year	114,007		8.28		171,688		8.35		440,080		8.35

Options exercisable	75,414				92,362				342,043
Weighted-average fair value of options granted during the year			$	—			$	2.46			$	2.41

The following table summarizes information about fixed stock options outstanding at December 31, 2005:

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number Outstanding	Weighted- Average Remaining Contractual Life	Weighted- Average Exercise Price		Number Exercisable	Weighted- Average Exercise Price
$4.00 to $6.00	22,740	6.8	$	4.76	12,151	$	4.79
$6.00 to $8.00	17,956	4.6	6.78		17,956	6.79
$8.00 to $10.00	61,211	6.5	9.30		36,415	9.16
$10.00 to $12.00	8,800	2.4	11.29		7,975	11.26
$12.00 to $14.00	2,200	8.7	13.25		550	13.25
$14.00 to $16.00	1,100	8.8	14.27		367	14.27
$4.41 to $14.27	114,007	6.0		8.28	75,414		8.17

Restricted Stock

The Company also issues restricted stock under the Company’s 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan. Restricted stock is granted for no consideration, and vests over a stated period. No shares were granted prior to 2005. The following summarizes the impact of the Company’s restricted stock plans (in thousands, except for per share data):

	2005

Balance, beginning of period	—
Granted	22,673
Vested	—
Forfeited	—
Balance, end of period	22,673

Fair value, end of year	$	482

Compensation expense for the year	$	84

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.

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

The Partnership’s general partner has adopted the MarkWest Energy Partners, L.P. Long-Term Incentive Plan for employees and directors of the general partner and employees of its affiliates who perform services for us. The long-term incentive plan consists of two components, restricted units and unit options. The long-term incentive plan currently permits the grant of awards covering an aggregate of 500,000 common units, 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 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 share 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.

15. Employee Benefit Plan

The Company made contributions of $0.2 million, $0.5 million and $0.4 million to a 401(k) savings and profit-sharing plan for the years ended December 31, 2005, 2004 and 2003, respectively. The Company contributed approximately 12,000, 15,000 and 32,000 common shares to a 401(k) savings and profit-sharing plan for the years ended December 31, 2005, 2004 and 2003, respectively, with an aggregate fair value of $0.2 million, $0.2 million and $0.2 million, respectively. The plan is discretionary, with annual contributions determined by the Company’s Board of Directors.

16. Stockholder’s Equity

Cash Dividends - Quarterly

The Company paid quarterly cash dividends for the years ended December 31, 2005 and 2004 as follows:

Quarter Ended	Dividend		Record Date	Payment Date

December 31, 2005	$	0.125	February 15, 2006	February 22, 2006
September 30, 2005	$	0.125	November 15, 2005	November 22, 2005
June 30, 2005	$	0.100	August 15, 2005	August 22, 2005
March 31, 2005	$	0.100	May 16, 2005	May 23, 2005

December 31, 2004	$	0.075	February 9, 2005	February 21, 2005
September 30, 2004	$	0.050	November 24, 2004	December 6, 2004
June 30, 2004	$	0.023	August 5, 2004	August 19, 2004
March 31, 2004	$	0.023	May 5, 2004	May 19, 2004

The Company did not pay cash dividends during the year ended December 31, 2003.

Cash Dividends – Special

Stock Dividends

On October 28, 2004, the Company’s Board of Directors declared a stock dividend of one share of MarkWest Hydrocarbon’s common stock for each ten shares owned by stockholders. The stock dividend of 976,974 shares was paid on November 19, 2004 to the stockholders of record as of the close of business on November 9, 2004.

On July 10, 2003, the Company’s Board of Directors declared a stock dividend of one share of MarkWest Hydrocarbon’s common stock for each ten shares held by its stockholders. The stock dividend of 852,248 shares was paid on August 11, 2003 to the stockholders of record as of the close of business on July 31, 2003.

All share and per share information has been adjusted to give retroactive effect to stock dividends paid.

Public Offerings and Private Placements by MarkWest Energy Partners

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.

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.

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.

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.

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.

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.

17. Commitments and Contingencies

Legal

MarkWest Hydrocarbon, 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.

The Company and several of its affiliates, including the Partnership, were served in early 2005 with two lawsuits, Ricky J. Conn, et al. v. MarkWest Hydrocarbon, Inc. et al. and Charles C. Reid, et al. v. MarkWest Hydrocarbon, Inc. et al., presently under the jurisdiction of the U.S. District Court for the Eastern District of Kentucky, Pikeville Division. In early November 2005, the Company, the Partnership and its affiliates were served with an additional lawsuit, Community Trust and Investment Co., et al. v. MarkWest Hydrocarbon, Inc. et al., filed 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 Company has timely 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 immediately after the incident, pipeline and valve integrity evaluation, testing and repairs were conducted on the affected pipeline segment before service could be resumed. Partial return to service of the affected pipeline began in October 2005. The Company has filed an independent action against its All-Risks Property and Business Interruption insurance carriers as a result of the companies’ refusal to honor their insurance coverage obligation to pay the Company 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 Company has not provided for a receivable for these claims because of the uncertainty as to whether and how much the Company will ultimately recover under these policies. The Company has also asserted that the cost of pipeline testing, replacement and repair are subject to an equitable sharing arrangement with its owner, pursuant to the terms of the pipeline lease agreement.

The Company has also been involved in a lawsuit captioned Ross Bros. Construction v. MarkWest Hydrocarbon, Inc., (U.S. Court of Appeals for the 6th Circuit, Case No. 05-6251, appealed from U.S. District Court Eastern District of Kentucky, Ashland Division, Civ. Action No. 01-CV-205). The underlying lawsuit involved the construction of the Siloam, Kentucky plant and a dispute as to the monetary value of additional work beyond the contract’s lump sum price performed by the contractor. The lawsuit involved a claim of approximately $0.7 million in extra costs. The Company was granted Summary Judgment on its defense asserting accord and satisfaction. In August 2005, Plaintiffs filed an appeal of the Summary Judgment to the U.S. Court of Appeals for the 6th Circuit. The Company believes that, while it is not able to predict the outcome of this matter, based on the judge’s discussion on the grant of the summary judgment and denial of Ross Brothers’ motion for reconsideration, it is probable that the Company will prevail in the appeal. As a result, the Company has not provided for a loss contingency.

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 Company has various non-cancelable operating lease agreements for equipment expiring at various times through fiscal 2015. Annual rent expense under these operating leases was $7.0 million, $5.2 million and $2.2 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	$	4,755
2007	3,005
2008	1,931
2009	1,516
2010	459
2011 and thereafter	203
Total	$	11,869

18. Discontinued Operations

During 2003 the Company discontinued its exploration and production business. Through a series of dispositions noted below, the Company sold off substantially all of its U.S. and Canadian oil and gas properties. The dispositions were as follows:

Sales of San Juan Basin Properties

During the second and third quarters of 2003 the Company completed the sales of its San Juan Basin (U.S.) oil and gas properties to certain third parties for net proceeds aggregating approximately $55.3 million. The Company recognized an aggregate net pretax gain of $23.3 million on these sales for the year ended December 31, 2003. The proceeds from the sales were used for working capital and general corporate purposes.

Sales of Canadian Properties

During December 2003, the Company completed the sales of all of its Canadian oil and gas properties to certain third parties for net proceeds aggregating approximately $49.1 million. The Company recognized an aggregate pretax loss of $4.8 million on these sales for the year ended December 31, 2003. The proceeds from the sales were primarily used to pay off the Company’s remaining outstanding debt, exclusive of MarkWest Energy’s debt.

Sale of Eastern Michigan Properties

During December 2003, the Company completed the sale of certain oil and gas properties and related assets located in Eastern Michigan for net proceeds of less than $0.1 million. The Company recognized a pretax loss of $1.8 million.

19. Related Party Transactions

Through the Company’s wholly owned subsidiary, Matrex, LLC, the Company held interests in a few exploration and production assets in which MAK-J Energy Partners Ltd. (“MAK-J”) also owns interests. These interests were sold on October 7, 2005. The general partner of MAK-J is a corporation owned and controlled by the Company’s former President and Chief Executive Officer and current Chairman of the Board of Directors.

The Company has receivables due from MAK-J, representing its share of operating and capital costs generated in the normal course of business, of less than $0.1 million as of December 31, 2004. There were no outstanding related party receivables as of December 31, 2005. The Company also has payables to MAK-J, representing its share of revenues generated in the normal course of business, of less than $0.1 million as of both December 31, 2005 and December 31, 2004.

20. Subsequent Events

On January 31, 2006, MarkWest Hydrocarbon entered into the first amended and restated credit agreement, which provides a maximum lending limit of $25.0 million for a one year term.

On January 17, 2006, the Partnership filed a Form S-4 exchange offer registration statement related to the Senior Notes (see Note 11). The registration became effective February 3, 2006. The interest rate penalty (1% at December 31, 2005) on the Senior Notes ceased on March 7, 2006.

21. Segment Information

MarkWest Hydrocarbon’s operations are classified into two reportable segments. For further information regarding our two business segments, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in Item 7 of this Form 10-K and “Financial Statements and Supplementary Data,” included in Item 8 of this Form 10-K:

1. MarkWest Energy Partners — 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.

2. MarkWest Hydrocarbon Standalone — The Company sells its equity and third-party NGLs, purchases third-party natural gas, and sells its equity and third-party natural gas. Since February 2004, the Company is also engaged in the wholesale marketing of propane. MarkWest Hydrocarbon Standalone operates MarkWest Energy Partners, a publicly traded limited partnership.

During 2003, the Company discontinued its exploration and production business segment.

The Company evaluates the performance of its segments and allocates resources to them based on operating income. There were no intersegment revenues prior to May 24, 2002. The Company conducts its continuing operations in the United States.

The table below presents information about operating income for the reported segments for the three years ended December 31, 2005, 2004 and 2003. Operating income for each segment includes total revenues minus purchased product costs, facility expenses, selling, general and administrative expenses, depreciation, amortization of intangible assets, accretion of asset retirement obligations and impairments and excludes interest income, interest expense, amortization of deferred financing costs, gain on sale of non-operating assets, non-controlling interest in net income of consolidated subsidiary, miscellaneous income (expense) and income taxes.

Selling, general and administrative expenses are allocated to the segments based on direct expenses incurred by the segments or allocated based on the percent of time that employees devote to the segment in accordance with the Partnership’s services agreement with the Company.

Year Ended December 31, 2005:	MarkWest Hydrocarbon Standalone				MarkWest Energy Partners			Eliminating Entries				Total
Revenues	$		280,015		$		499,084	$		(64,922	)	$		714,177
Purchased product costs	258,188				366,878			(41,982			)	583,084
Facility expenses	20,545				47,972			(22,940			)	45,577
Selling, general and administrative expenses	11,777				21,573			—				33,350
Depreciation	1,295				19,534			—				20,829
Amortization of intangible assets	—				9,656			—				9,656
Accretion of asset retirement and lease obligations	1				159			—				160
Total operating expenses	291,806				465,772			(64,922			)	692,656

Operating income (loss)	$	(11,791		)	$	33,312		$	—			$	21,521
Total assets	$		86,211		$		1,046,039	$		—		$		1,132,304

Year Ended December 31, 2004:	MarkWest Hydrocarbon Standalone				MarkWest Energy Partners			Eliminating Entries				Total
Revenues	$		218,337		$		301,314	$		(59,538	)	$		460,113
Purchased product costs	185,951				211,534			(34,224			)	363,261
Facility expenses	23,983				29,911			(25,314			)	28,580
Selling, general and administrative expenses	11,999				16,133			—				28,132
Depreciation	1,339				15,556			—				16,895
Amortization of intangible assets	—				3,640			—				3,640
Accretion of asset retirement and lease obligations	2				13			—				15
Impairments	—				130			—				130
Total operating expenses	223,274				276,917			(59,538			)	440,653

Operating income (loss)	$		(4,937	)	$		24,397	$		—		$		19,460
Total assets	$		64,152		$		529,422	$		—		$		593,574

Year Ended December 31, 2003:	MarkWest Hydrocarbon Standalone				MarkWest Energy Partners			Eliminating Entries				Total
Revenues	$		142,569		$		117,430	$		(50,731	)	$		209,268
Purchased product costs	142,633				70,832			(25,921			)	187,544
Facility expenses	25,304				20,463			(24,810			)	20,957
Selling, general and administrative expenses	7,267				8,598			—				15,865
Depreciation	1,247				7,548			—				8,795
Impairments	1,039				1,148			—				2,187
Total operating expenses	177,490				108,589			(50,731			)	235,348

Operating income (loss)	$		(34,921	)	$		8,841	$		—		$		(26,080	)
Total assets	$		67,624		$		212,871	$		—		$		280,495

A reconciliation of operating income (loss) to total consolidated income (loss) from continuing operations before taxes is as follows (in thousands):

	December 31,
	2005			2004			2003
Operating income (loss)	$	21,521		$	19,460		$	(26,080	)
Loss from unconsolidated subsidiary	(2,153		)	—			—
Interest income	1,060			647			106
Interest expense	(22,622		)	(9,383		)	(4,347		)
Amortization of deferred financing cost (a component of interest expense)	(6,979		)	(5,281		)	(2,104		)
Dividend income	392			259			—
Other income (expense)	266			788			(92		)
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	$	(8,515	)	$	6,490		$	(32,517	)

22. Quarterly Results of Operations (Unaudited)

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

	Three months ended
2005	March 31		June 30			September 30			December 31
Revenue	$	138,353	$	141,040		$	170,625		$	264,159
Income (loss) from operations	1,539		(1,609		)	(5,688		)	(1,044		)
Net Income (loss)	1,539		(1,609		)	(5,688		)	(1,044		)

Earnings (loss) per share:
Basic	$	0.14	$	(0.15	)	$	(0.53	)	$	(0.09	)
Diluted	$	0.14	$	(0.15	)	$	(0.53	)	$	(0.09	)

	Three months ended
2004	March 31		June 30			September 30			December 31
Revenue	$	93,700	$	89,024		$	121,511		$	155,878
Income (loss) from continuing operations	720		(6,368		)	(1,966		)	6,711
Net Income (loss)	720		(6,368		)	(1,966		)	6,711

Earnings (loss) per share:
Basic	$	0.07	$	(0.60	)	$	(0.18	)	$	0.63
Diluted	$	0.07	$	(0.60	)	$	(0.18	)	$	0.63

23. 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	$	249		$	120		$	87
Charged to costs and expenses	46			277			177
Deductions (Collections)	(120		)	(148		)	(144		)
Balance at end of period	$	175		$	249		$	120

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

On September 20, 2005, the Company informed KPMG LLP (KMPG) that it would be dismissing KPMG as its registered independent accounting firm effective upon the completion of their audit of the Company’s consolidated financial statements for the year ended December 31, 2004. The Registrant’s Audit Committee made the decision to change independent accountants and that decision was approved, ratified and adopted by the Company’s Board of Directors. KPMG completed its audit and the Company’s Form 10-K was filed with the Securities and Exchange Commission on October 21, 2005.

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 Company 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 during the subsequent interim period through October 21, 2005, there have been 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 October 21, 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 Company’s Audit Committee the existence of material weaknesses related to (i) ineffective control environment, (ii) insufficient 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.

On September 20, 2005, the Company engaged Deloitte & Touche LLP as the Registrant’s registered independent accounting firm for the year ending December 31, 2005, and to perform procedures related to the financial statements included in the Company’s quarterly reports on Form 10-Q, beginning with the quarter ended March 31, 2005. The Audit Committee made the decision to engage Deloitte & Touche LLP and that decision was then approved, adopted and ratified by the Company’s Board of Directors. The Company has not consulted with Deloitte & Touche LLP 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 Company nor oral advice was provided that Deloitte & Touche LLP concluded was an important factor considered by the Company 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 Company 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 Company’s management and Audit Committee in connection with the audit for fiscal 2003 certain deficiencies in the Company’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 Company 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 Company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles 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 Company;

• 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

• 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.

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 Company’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 the Partnership’s Southwest Business Unit, and 4) Inadequately designed controls and procedures over property, plant and equipment.

While the Company 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 Company’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.

• Accounting for Income Taxes related to reconciliation of tax accounts.

Risk Management and Accounting for Derivative Financial Instruments – The Company 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 Company did not maintain effective internal control over financial reporting.

The Company’s independent registered accounting firm has issued an attestation report on management’s assessment of the Company’s internal control over financial reporting, which appears on page 92.

Date: March 20, 2006	By:	/s/FRANK M. SEMPLE
		Frank M. Semple
		Chief Executive Officer

Date: March 20, 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.”

REMEDIATION OF MATERIAL WEAKNESSES IN INTERNAL CONTROL

In response to the material weaknesses identified in the 2004 Form 10-K and those still existing at December 31, 2005, our management, with oversight from our audit committee, has dedicated significant resources to improve our control environment and to remedy the identified material weaknesses. These ongoing efforts are 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 have made significant strides. Among other things:

• We have hired a Senior Vice President, Chief Accounting Officer with public company accounting and reporting technical expertise.

• We have hired additional external reporting, tax and accounting staff to supplement our existing technical accounting resources and mitigate segregation of duties deficiencies.

• We have hired a Vice President of Risk and Compliance to coordinate our internal audit and internal control compliance efforts and to oversee and ensure improvements in our commodity transacting verification and monitoring capabilities.

• We have implemented an internal audit outsourcing and technical consultation arrangement with a professional accounting and consulting firm.

• We have hired a Director of Risk Management and staff to establish appropriate verification and monitoring activities associated with our commodity transacting.

All of these resources were added in the third and fourth quarters of 2005 or the first quarter of 2006 and, 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.

We have and will continue to implement changes to our processes to improve disclosure controls and procedures and to improve our internal control over financial reporting. Among the changes we have made and intend to make are the following:

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

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

• We have conducted an entity-level risk assessment, established an internal audit plan and we have begun to execute that internal audit plan. Results are reported directly to our audit committee.

• We are segregating front-office, mid-office and back-office processes related to commodity transacting to ensure that proper segregation of duties exists and that control procedures are carried out by the appropriate groups. We are enhancing hedge reporting to executive management. We are enhancing risk management policies and procedures related to the review and approval of material purchase or sale contracts that may meet the definition of derivatives.

• We have enhanced entity level controls through the implementation of significant new controls. We have strengthened our disclosure review committee charter to solicit and review input from management personnel throughout the Company regarding possible instances of fraud or significant events requiring disclosure. Also, we have implemented a technical accounting issues forum to address non-routine transactions and the use of estimates and judgment.

• 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 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 Hydrocarbon, Inc.
Englewood, Colorado

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that MarkWest Hydrocarbon, Inc. and subsidiaries (the “Company”) 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 the 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% and 42% of net and total assets, respectively, 3% 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 Company’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 Company’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 Company’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.

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

• And, accounting for income taxes related to reconciliations of tax accounts.

Risk Management and Accounting for Derivative Financial Instruments — The Company 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 Company’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 Company’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 Company and this report does not affect our report on such financial statements.

In our opinion, management’s assessment that the Company 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 Company 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 Company and our report dated March 17, 2006 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado
March 20, 2006

ITEM 9B. OTHER INFORMATION

None.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The following table shows information for the directors and executive officers of MarkWest Hydrocarbon, Inc. Executive officers are appointed and directors are elected for three-year terms.

Name	Age	Position

John M. Fox	65	Chairman of the Board of Directors
Michael L. Beatty	58	Director
Donald C. Heppermann	63	Director
William A. Kellstrom	64	Director
Anne E. Mounsey	39	Director
Karen L. Rogers	49	Director
William F. Wallace	66	Director
Donald D. Wolf	62	Director
Frank M. Semple	54	President, Chief Executive Officer and Director
C. Corwin Bromley	48	Vice President, General Counsel and Secretary
James G. Ivey	54	Senior Vice President and Chief Financial Officer
Nancy K. Masten	36	Senior Vice President, Chief Accounting Officer
John C. Mollenkopf	44	Senior Vice President, Southwest Business Unit
Randy S. Nickerson	44	Senior Vice President, Corporate Development
Richard A. Ostberg	40	Vice President, Risk and Compliance
Andrew L. Schroeder	47	Vice President, Finance and Treasurer
David L. Young	46	Senior Vice President, Northeast Business Unit

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.

Michael L. Beatty has served as a member of the Board of Directors of MarkWest Hydrocarbon, Inc. since June 2005. Mr. Beatty is currently Chairman and CEO of the law firm of Beatty & Wozniak, P.C. located in Denver, Colorado, with a practice focused on energy, oil and gas, business and commercial litigation. A Harvard Law School graduate, Mr. Beatty began his career in the energy industry as in-house counsel for Colorado Interstate Gas Company, and ultimately became Executive Vice President, General Counsel and a Director of The Coastal Corporation. Mr. Beatty also served as Chief of Staff to Colorado Governor Roy Romer from 1993 to 1995. Mr. Beatty has handled numerous energy related cases in his career, including successfully arguing a case before the U. S. Supreme Court. Prior to his work as an energy litigator, Mr. Beatty was a tenured law professor at the University of Idaho, and visiting law professor at the University of Wyoming. Mr. Beatty graduated from the University of California, Berkeley with a Bachelor of Arts degree, and received his juris doctorate from Harvard Law School. Mr. Beatty has also been active in a number of civic organizations, including as a member of the board of directors of the Colorado Leadership Alliance and of the Bighorn Action Committee, and served as coach with several championship teams in the Colorado State High School Mock Trial competitions.

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 and 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 a 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 employed by Pinnacle West Capital Corporation, the holding company for Arizona Public Service Company, where he was Vice President of Finance. From 1965 to 1987, Enron Corporation and its predecessors employed Mr. Heppermann in a

variety of positions, including Executive Vice President, Gas Pipeline Group.

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.

Anne E. Mounsey has served as a member of the Company’s Board of Directors since October 2004. From 1991 to 2003, Ms. Mounsey held various positions with the Company, her most recent as Manager of Marketing and Business Development. Ms. Mounsey is the daughter of John M. Fox, the Company’s Chairman of the Board of Directors.

Karen L. Rogers has served as a member of the Board of Directors of MarkWest Hydrocarbon since June 2000. In June 2005, Ms. Rogers joined Blacksand Energy, Inc., a privately held oil and gas development and production company, as the chief financial officer. Prior to joining Blacksand Energy, Inc. Ms. Rogers was employed since 2000 as Vice President, Energy Group, for Wells Fargo Bank N.A. Prior to 1997, Ms. Rogers was Senior Vice President and Manager of NationsBank Energy Group Denver, Inc. She has more than 25 years of experience in energy finance and corporate banking.

William F. Wallace has served as a member of the Board of Directors of MarkWest Hydrocarbon since June 2004. Prior to his retirement in 2001, Mr. Wallace was Vice Chairman of the board of directors of Barrett Resources Corp. since 1996, after being named to that position in 1995 following the merger of Barrett Resources and Plains Petroleum Co., both oil and gas exploration companies. From 1994 to 1995, Mr. Wallace was President, Chief Operating Officer and a Director of Plains Petroleum Co. Prior to joining Plains Petroleum, Mr. Wallace spent 23 years with Texaco Inc., an integrated oil and gas company, including six years as Vice President of Exploration for Texaco USA and as Regional Vice President of Texaco’s Eastern Region. Mr. Wallace has served on the Kerr McKee Corporation board of directors since 2004. Previously, he served as a director of Westport Resources Corporation from 1997 until Westport’s merger with Kerr McKee Corporation in 2004.

Donald D. Wolf has served as a member of the Company’s Board of Directors since June 1996. In September 2004, Mr. Wolf joined Aspect Energy as President and Chief Executive Officer. Mr. Wolf served as Chairman, Chief Executive Officer and Director of Westport Resources Corporation from April 2000 until Westport’s merger with Kerr McKee Corporation in 2004. He joined Westport Oil and Gas Company, Inc. in June 1996 as Chairman and Chief Executive Officer and has a diversified 35-year career in the oil and natural gas industry.

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.

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.

Part III

Audit Committee Financial Expert

The members of the Company’s Audit Committee of the Board of Directors are Mr. Kellstrom (chairman), Mr. Beatty, Ms. Rogers, Mr. Wallace and Mr. Wolf. Each of the individuals serving on our Audit Committee satisfies the standards for independence of the AMEX and the SEC as they relate to audit committees. Our Board of Directors believes each of the members of the Audit Committee is financially literate. In addition, our Board of Directors has determined that Mr. Kellstrom is financially sophisticated and qualifies as an “audit committee financial expert” within the meaning of the regulations of the SEC.

Audit Committee Pre-Approval Policy

The Audit Committee pre-approves all audit and permissible non-audit services provided by the independent auditors on a case-by-case basis. These services may include audit services, audit-related services, tax services and other services. Our Chief Accounting Officer is responsible for presenting the Audit Committee with an overview of all proposed audit, audit-related, tax or other non-audit services to be performed by the independent auditors. The presentation must be in sufficient detail to define clearly the services to be performed. The Audit Committee does not delegate its responsibilities to pre-approve services performed by the independent auditor to management or to an individual member of the Audit Committee. The Audit Committee may, however, from time to time delegate its authority to the Audit Committee Chairman, who reports on the independent auditor services approved by the Chairman at the next Audit Committee meeting.

Code of 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 shareholder who sends a request to the office of the Secretary of MarkWest Hydrocarbon, Inc. 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 directors and executive officers, and persons who own more than 10% of any class of our equity securities registered under Section 12 of the Exchange Act, to file with the SEC initial reports of ownership and reports of changes in ownership in such securities and other equity securities of our Company. SEC regulations also require directors, executive officers and greater than 10% stockholders 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% stockholders 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	2	—	2
Mr. Beatty	2	1	1
Mr. Heppermann	2	—	2
Mr. Kellstrom	2	—	2
Ms. Mounsey	1	—	1
Ms. Rogers	2	—	2
Mr. Wallace	3	—	3
Mr. Wolf	2	—	2
Mr. Ostberg	1	1	—

We are not aware of any other failure to file a Section 16(a) form with the SEC, or any transaction that was required to be reported, but that was not reported on a timely basis.

ITEM 11. EXECUTIVE COMPENSATION

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 the Company in 2005 and the four other highest paid officers, whose salary and bonus exceeded $100,000 for services rendered during 2005 (the “Named Executive Officers”).

Summary Compensation Table

	Annual Compensation					Long-Term Compensation
Name and Principal Positions						Restricted Unit Awards ($) (3)		LTIP Payouts ($) (4)		Other Compensation ($) (5)

	Fiscal Year	Salary ($) (1)		Bonus ($) (2)

Frank M. Semple	2005	$	288,462	$	143,000	$	84,280	$	22,634	$	20,550
President and Chief Executive Officer	2004	280,385		47,250		108,750		20,500		52,838
	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 Development	2004	181,155		30,625		108,750		5,363		13,686
	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
Senior Vice President, Southwest Business Unit	2004	180,865		30,625		65,250		6,703		13,426
	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 Business Unit	2004	161,538		25,521		77,000		4,380		—
	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.

Option Grants in Last Year

None

SAR Grants in Last Year

The Company has also entered into arrangements with certain directors and officers of the Company. These arrangements are referred to as the Participation Plan. Under the Participation Plan, the Company sells subordinated partnership units of the Partnership and interests in the Partnership’s general partner to employees and directors of the Company under a purchase and sale agreement. The interests in the general partner are sold with certain put and call provisions that allow the individual to require MarkWest Hydrocarbon to buy back or requires the individual to sell back their interest in the general partner to MarkWest Hydrocarbon. 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 Company 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 following table provides information on the potential appreciation of the interests in the Partnership’s general partner that were sold to the Named Executive Officers during the year ended December 31, 2005. There were no subordinated partnership units sold during 2005. All interests were sold under the Company’s Participation Plan. The plan has not been approved by the Stockholders.

Individual Grants

Exercise or base

Expiration

Potential realizable value at
assumed annual rates of
stock price appreciation for
SAR term

Grant Date

Percent of General
Partner Interest
underlying SAR

Percent of
SARs granted
to employees

granted (%)

in year

price ($ /Sh)(1)

date(2)

5% ($ )(2)

10% ($ )(2)

Present Value ($ )

—

(1) The Company sells interests in the Partnership’s general partner under a variable plan to certain directors and employees of the Company. The interest in the Partnership’s general partner are sold with certain put and call provisions that allow the individual to require MarkWest Hydrocarbon to buy back or requires the individual to sell 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 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. The Company 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. As the stock appreciation right is exercised through a callable or puttable event, there is no defined expiration date.

(2) The interests in the Partnership’s general partner are sold without an expiration date. As a result, when calculating the potential realizable value of the appreciation of the award, the Company assumed a 10 year life to be consistent with the terms used on the Company’s other stock based compensation awards.

Aggregated Option Exercises in Last Year and Year-End Option Values

The following table provides information as to options exercised during the year ended December 31, 2005, and the value of outstanding options held by the Named Executive Officers at December 31, 2005.

	Shares Acquired on	Value		Number of Securities Underlying Unexercised Options at End of 2005 (#)		Value of Unexercised In-the- Money Options at End of 2005 (#)
	Exercise (#)	Realized ($ )		Exercisable	Unexercisable	Exercisable		Unexercisable

Frank M. Semple	—	$	—	11,000	11,000	$	137,110	$	137,110
James G. Ivey	—	—		2,750	8,250	32,652		97,957
Randy S. Nickerson	—	—		3,859	—	53,832		—
John C. Mollenlkopf	—	—		7,119	—	102,070		—
David L. Young	—	—		687	2,063	8,201		24,627

(1) Value based on the difference between the closing price of our common stock, as reported by the American Stock Exchange on December 31, 2005, and the option price per share multiplied by the number of shares subject to the option.

Aggregated SAR Exercises in Last Year and Year-End SAR Values

The following table provides information as to the value of the subordinated partnership units of the Partnership and interests in the Partnership’s general partner held by the Named Executive Officers at December 31, 2005. We did not buy back any of the subordinated partnership units of the Partnership or interests in the Partnership’s general partner from the Named Executive Officers during the year ended December 31, 2005.

	Percent of General Partner Interest Underlying Unexercised SAR at End of 2005 (%)(1)		Number of Partnership subordinated units Underlying Unexercised SAR at End of 2005 (#)(1)	Value of GP Interest Underlying SAR at End of 2005 ($ )(2)		Value of Subordinated Units Underlying SAR at End of 2005 ($ )(3)

Frank M. Semple	2.0	%	—	$	1,403,961	—
James G. Ivey	0.5	%	—	201,547		—
Randy S. Nickerson	1.6	%	—	1,179,349		—
John C. Mollenlkopf	1.6	%	—	1,179,349		—

(1) The Company sells subordinated partnership units of the Partnership and interests in the Partnership’s general partner under a variable plan to certain directors and employees of the Company. 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 the Company under a purchase and sale agreement. The interest in the Partnership’s general partner are sold with certain put and call provisions that allow the individual to require MarkWest Hydrocarbon to buy back or requires the individual to sell 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,

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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 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. The Company 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 Company 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 employees’ and directors’ subordinated units converted into MarkWest Energy’s common units on August 15, 2005.

(2) The value of the executive’s interests in the Partnership’s general partner is measured as the difference in the formula value of the general partner interest, as measured at December 31, 2004, and the amount paid by the executive. The formula value is the amount MarkWest Hydrocarbon would have to pay the employees and directors to repurchase the Partnership’s general partner interests which is derived from the current market value of the Partnership’s common units, as reported by the American Stock Exchange on December 31, 2004, and the quarterly distributions previously paid by the Partnership.

(3) The value of the executive’s subordinated partnership units of the Partnership underlying the executive’s is measured as the difference in the market value of the Partnership’s common units, as reported by the American Stock Exchange on December 31, 2004, and the amount paid by the named executive.

Indemnification Agreements

In February 2004, MarkWest Hydrocarbon entered into Indemnification Agreements with certain directors and officers (“Indemnitees”). By the terms of the Indemnification Agreement, the Company shall indemnify Indemnitees to the fullest extent permitted by law against all expenses and liabilities (as defined in the Indemnification Agreement) if Indemnitees were or are, or are threatened to be made a party to, any threatened, pending or completed action, suit, proceeding, or alternative dispute resolution mechanism, whether civil, criminal, administrative, investigative or other and whether brought by or in the right of the Company or otherwise, by reason of (or arising in part out of) any event or occurrence related to the fact that Indemnitees are or were a director, officer, employee, agent or fiduciary of the Company, or any subsidiary of the Company, or are or were serving at the request of the Company as a director, officer, employee, agent or fiduciary of another corporation, partnership, joint venture, trust or other enterprise, or by reason of any action or inaction on the part of the Indemnitees while serving in such capacity.

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 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

101

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.

Director Compensation

On January 27, 2006, the Board of Directors of the Company approved director compensation for 2006. Each non-officer/employee director will receive an annual retainer of $20,000 and 1,000 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 $18,000 and 1,000 restricted units per year. In addition, each non-officer/employee director received compensation of $2,000 for either in-person or telephonic attendance at meetings of the board of directors or committees of the board of directors. The members of the Audit, Conflicts and Compensation 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 general partner who also serve as directors will not receive additional compensation.

Compensation Committee Interlocks and Insider Participation

There are no Compensation Committee interlocks.

Board Compensation Committee Report On Executive Compensation

The Compensation Committee of the Board of Directors is composed of five non-employee directors, including Mr. Wolf (chairman), Mr. Fox, Mr. Kellstrom, Mr. Wallace and Ms. Mounsey. The Committee is responsible for developing and approving our executive compensation policies. In addition, the Compensation Committee determines, on an annual basis, the compensation to be paid to the Chief Executive Officer and to each of the other executive officers. The overall objectives of our executive compensation program are to provide compensation that will attract and retain superior talent and reward performance.

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 our compensation program for our executive officers include base salary, performance based cash bonuses, and long-term incentive compensation in the form of stock options, restricted stock awards and restricted unit grants of MarkWest Energy Partners, L.P.

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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 and the Company’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 Plans

The Committee believes that a key component to the compensation of its executive officers should be through the issuance of stock options, restricted stock awards and restricted unit grants of MarkWest Energy Partners, L.P. Stock options, restricted stock awards and restricted unit grants 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.

Under the 1996 Stock Incentive Plan, the Company may grant options to its employees for up to 925,000 shares of common stock. Under this plan, the exercise price of each option equals the market price of the Company’s stock on the date of the grant, and the maximum term of the option is ten years. Options are granted periodically throughout the year and vest at the rate of 25% per year for options granted in 1999 and thereafter, and 20% per year for options granted prior to 1999. At December 31, 2005, there were 409,935 options available for grant under this plan.

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 evaluates several factors 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 competitive point of view to retain the services of a valued executive officer.

Savings Plan Benefits

We make a matching contribution under our 401(k) Savings and Profit Sharing Plan. We may also make a discretionary profit sharing payment annually to executives and all other employees under this plan based upon our financial performance compared to corporate goals for that year. In addition, we provide medical and other miscellaneous benefits to executive officers that are generally available to all employees.

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Chief Executive Officer 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 Hydrocarbon, Inc.:

Mr. Donald D. Wolf, Chairman

Mr. John M. Fox

Mr. William A. Kellstrom

Mr. William F. Wallace

Ms. Anne E. Mounsey

Deductibility of Executive Compensation. Section 162(m) of the Internal Revenue Code generally disallows a tax deduction for compensation in excess of $1.0 million paid to the Company’s Chief Executive Officer and certain other highly compensated executive officers. Qualifying “performance-based” compensation will not be subject to the deduction limit if certain requirements are met. We anticipate that incentive-based compensation paid in excess of $1.0 million will be deductible under Section 162(m). The Compensation Committee believes, however, that there may be circumstances in which our interests are best served by providing compensation that is not fully deductible under Section 162(m) and reserves the ability to exercise discretion to authorize such compensation.

PERFORMANCE GRAPH

Source: FactSet Research Systems and Bloomberg.

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(a) Peer group companies include Crosstex Energy, Inc., Kinder Morgan, Inc. and Transmontaigne, Inc. Crosstex Energy, Inc., began trading on 1/13/04. The index is weighted based on market capitalization. Peer group companies were selected based on their business mix and market capitalization.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information as of December 31, 2005, regarding the beneficial ownership of our common stock held by beneficial owners of 5% or more of common stock, by each director, by each Named Executive Officer and by all of the directors and officers of the Company as a group.

Stockholder (1)	Number of Shares	Acquirable within 60 days of January 1, 2006 (2)	Total Shares Beneficially Owned (3)	Percent of Total Shares (4)

John M. Fox (5)	4,992,346	—	4,992,346	46.2	%
Wellington Management Company, LLP 75 State Street Boston, Massachusetts 02109 (6)	444,750	—	444,750	4.1	%
Kayne Anderson Capital Advisors, L.P. 1800 Avenue of the Stars, Second Floor Los Angeles, CA 90067 (7)	862,046	—	862,046	8.0	%
Richard A. Kayne 1800 Avenue of the Stars, Second Floor Los Angeles, CA 90067 (7)	862,046	—	862,046	8.0	%
Michael L. Beatty	—	—	—		*
Donald C. Heppermann	18,925	—	18,925		*
William A. Kellstrom	18,110	—	18,110		*
Anne E. Mounsey	10,798	—	10,798		*
Karen L. Rogers	12,270	—	12,270		*
William F. Wallace	2,367	—	2,367		*
Donald D. Wolf	22,680	—	22,680		*
Frank M. Semple	17,316	723	18,039		*
C. Corwin Bromley	550	86	636		*
James G. Ivey	2,750	237	2,987		*
Nancy K. Masten	—	—	—		*
John C. Mollenkopf	7,738	282	8,020		*
Randy S. Nickerson	10,848	282	11,130		*
Richard A. Ostberg	—	—	—		*
Andrew L. Schroeder	1,511	907	2,418		*
David L. Young	687	926	1,613		*
All directors and executive officers as a group (17 persons)	5,118,896	3,443	5,122,339	47.4	%

* Indicates less than 1.0%.

(1) Unless otherwise noted, the address for the stockholder listed is c/o MarkWest Hydrocarbon, Inc., 155 Inverness Drive West, Suite 200, Englewood, Colorado 80112-5000.

(2) This column reflects the number of shares that could be purchased by the exercise of options exercisable on December 31, 2005, or within sixty days thereafter under our stock option plans.

(3) For executive officers, the numbers include interests in shares held in employee benefit plans. Unless otherwise indicated, the directors and Named Executive Officers have sole voting and dispositive power over the shares listed above, other than shared rights created under joint tenancy or marital property laws as between the directors or named executive officers and their respective spouses.

(4) All percentages have been determined at December 31, 2005, in accordance with Rule 13d-3 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). For purposes of this table, a person or group of persons is deemed to have “beneficial ownership” of any shares of common stock that such person or group has the right to acquire within sixty days after December 31, 2005. For purposes of computing the percentage of outstanding shares of common stock held by each person or group of persons named above, any security which such person or group has the right to acquire within sixty days after December 31, 2005, is deemed to be outstanding for the purpose of computing the percentage ownership of such person or group. At December 31, 2005, a total of 10,802,488 shares were outstanding. Options to acquire a total of 83,270 shares of common stock were exercisable within sixty days.

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(5) Includes an aggregate of (i) 4,509,443 shares owned directly by MWHC Holding, Inc., an entity controlled by Mr. Fox, of which Mr. Fox is also considered a beneficial owner (Mr. Fox has an indirect pecuniary interest in the MWHC shares); (ii) 73,864 shares held in the aggregate in the Brian T. Crabtree Trust which Mr. Fox is the Trustee; and (iii) 112,941 shares held by the MaggieGeorge Foundation, for which certain family members of Mr. Fox are directors. Mr. Fox disclaims beneficial ownership of the shares held in the MaggieGeorge Foundation within the meaning of Rule 13d-3 under the Exchange Act.

(6) Information is based solely on a Schedule 13G/A filed with the Securities and Exchange Commission by Wellington Management Company, LLP (“Wellington”), on February 14, 2006, with respect to shares held as of December 31, 2005. The Schedule 13G indicates that Wellington has shared voting power with respect to 654,250 shares and shared dispositive power with respect to 858,250.

(7) 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 shares 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 714,850 shares. The reported shares 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 shares reported, except those shares attributable to it by virtue of its general partner interests in the limited partnerships. Mr. Kayne disclaims beneficial ownership of the shares reported, except those shares 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 stock of the registered investment company.

MarkWest GP, L.L.C.

The following table sets forth the beneficial ownership of the Partnership’s general partner as of December 31, 2005, held by the directors, each named executive officer and by all directors and officers as a group.

Name of Beneficial Owner		Percentage of Limited Liability Company Interests Owned
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.

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MarkWest Energy Partners, L.P.

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	%

* 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.

Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information about the shares of our common stock that may be issued upon the exercise of options, warrants and rights under all of the Company’s existing equity compensation plans, including the Stock Incentive Plan and Non-Employee Director Plan as of December 31, 2004. We do not have equity plans that have not received stockholder approval.

Equity Compensation Plan Information

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	114,007	$	8.28	176,078
Equity compensation plans not approved by security holders	—	—		—

Total	114,007	$	8.28	176,078

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Investment with Affiliate

Through our wholly owned subsidiary, MarkWest Resources, Inc. (“Resources”), we held varied undivided interests in several exploration and production assets in which MAK-J Energy Partners Ltd. (“MAK-J”) also owns or owned an undivided interest, varying from 25% to 51%. The general partner of MAK-J is a corporation owned and controlled by our former President and Chief Executive Officer and current Chairman of the Board of Directors. Two former officers, both of who left the Company during 2003, were limited partners in MAK-J. The properties were operated pursuant to joint operating agreements entered into between Resources and MAK-J. Resources was the operator under such agreements. The joint operating agreements were governed by a Participation and Operations Agreement, most recently amended June 2, 2003. The joint property acquisitions and joint operating agreements were subject to the approval of the independent members of our Board of Directors. As the operator, Resources was obligated to provide certain accounting and well operations services to the parties. The Participation and Operations Agreement provided for a monthly fee ($2,000 per month) payable to Resources to offset the costs of accounting and well operations on a monthly basis. As a part of the sale of our San Juan Basin oil and gas properties to a third party on June 30, 2003, the Participation and Operations Agreement was assigned to the purchasing third party.

From time to time, MarkWest Hydrocarbon entered into hedges with counterparties on behalf of MAK-J. MarkWest Hydrocarbon billed or remitted to MAK-J, as circumstances dictated, its portion of transaction costs and settlements on a monthly basis. As of July 2003, all such hedges had been settled.

Through our wholly owned subsidiary, Matrex, LLC, we hold interests in certain exploration and production assets in which MAK-J also owns interests. Both parties are participants to joint operating agreements with third parties operators.

We have receivables due from MAK-J, representing its share of operating and capital costs generated in the normal course of business, of less than $0.1 million as of December 31, 2004 and 2003, respectively. As of December 31, 2005 there were outstanding related party receivables. We also have payable to MAK-J, representing its share of revenues generated in the normal course of business, of less than $0.1 million as of December 31, 2005, 2004 and 2003, respectively.

Mr. Fox has agreed that as long as he is an officer or director of MarkWest Hydrocarbon and for two years thereafter, he will not, directly or indirectly, participate in any future oil and gas exploration or production activities with us except and to the extent that our independent and unaffiliated directors deem it advisable and in our best interest to include one or more additional participants, which participants may include entities controlled by Mr. Fox.

Relationship of Directors with MarkWest Hydrocarbon

Donald D. Wolf, a member of the Board of Directors, was the Chairman and Chief Executive Officer of Westport Resources Corporation and William F. Wallace, also a member of the Board of Directors, was a director of Westport Resources Corporation until Westport’s merger with Kerr McKee Corporation in 2004. Mr. Wallace is currently a director of the Kerr McKee Corporation. Westport Resources Corporation was a party to certain 1997 contracts with indirect subsidiaries of MarkWest Hydrocarbon for transportation, treating and processing services in Western Michigan. No services were performed in the last year pursuant to these contracts. The terms of these contracts were negotiated on an arm’s length basis prior to Mr. Wolf’s 1999 election and Mr. Wallace’s 2004 election to the Board of Directors.

Related Transactions

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

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

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

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

In April 2004 the Company entered into an agreement with a third party to buy Mr. Semple’s house as a part of his relocation to Denver, Colorado. Under the agreement, MarkWest Hydrocarbon agreed to pay the value of Mr. Semple’s equity in the house and associated operating costs of $0.3 million to the third party until the house was subsequently sold to a buyer. Upon the sale, the third party agreed to refund the equity paid by MarkWest Hydrocarbon to the extent that the proceeds covered the established value minus certain costs incurred to sell the home. In 2005 the house was sold and the Company paid total costs of approximately $0.1 million.

Participation Plan

From time to time, MarkWest Hydrocarbon sells to certain of its executive officers and directors (i) a certain amount of the subordinated units the Company obtained during the formation of MarkWest Energy in May 2002 and (ii) a portion of its ownership interest in the general partner, which was also obtained by the Company during the formation of the Partnership. These transactions are accounted for as compensatory arrangements, consistent with the guidance in APB No. 25, Accounting for Stock Issued to Employees and EITF No 95-16, Accounting for Stock Compensation Arrangements with Employer Loan Features under APB Opinion No. 25, which requires the Company to record compensation expense based on the market value of the subordinated Partnership units and the formula value of the general partner interests held by the employees and directors, at the end of each reporting period. The sales are governed by a purchase and sales agreement that outlines the terms and conditions. Immediately after MarkWest Energy’s initial public offering on May 24, 2002, MarkWest Hydrocarbon sold an 8.6% interest in the general partner of the Partnership and 24,864 of its Partnership subordinated units, to certain officers of MarkWest Hydrocarbon for $0.2 million and $0.4 million, respectively. The officers and executives paid approximately 30% of the purchase price in cash and financed the remainder with loans from MarkWest Hydrocarbon. The loans are evidenced by non-recourse promissory notes requiring the principal balance to be repaid no later than June 30, 2009 and bearing interest at the rate of 7% per annum on the unpaid balance. MarkWest Hydrocarbon has sold additional interests in the general partner to employees and directors of 3.9% for $0.2 million and Partnership subordinated units of 12,500 for $0.3 million. In 2004, the Company sold interests aggregating 0.7% in the general partner of the Partnership to employees and directors for $0.2 million and 1,500 Partnership subordinated units for $0.1 million. Outstanding notes receivable from officers pertaining to the loans made in May 2002 were approximately $0.2 million as of December 31, 2004 and 2003. In the second quarter of 2005, one former director/executive re-paid his outstanding loan for less than $0.1 million. Outstanding notes receivable of approximately $0.1 million were payable by Mr. Mollenkopf and Mr. Nickerson at both December 31, 2004 and 2003. In accordance with the Sarbanes-Oxley Act of 2002, the Company no longer grants loans to employees.

Future Transactions

The terms of any future transactions between us and our directors, officers, principal stockholders or other affiliates, or the decision to participate or not participate in transactions offered by our directors, officers, principal stockholders or other affiliates will be approved by a majority of our independent and unaffiliated directors. Our Board of Directors will use such procedures in evaluating their terms as are appropriate considering the fiduciary duties of the Board of Directors under Delaware law. In any such review the Board may use outside experts or consultants including independent legal counsel, secure appraisals or other market comparisons, refer to generally available statistics or prices or take such other actions as are appropriate under the circumstances. Although such procedures are intended to ensure that transactions with affiliates will be at least as favorable to the Company as an arm’s length transaction with an unaffiliated third party, though no assurance can be given that such procedures will produce such result.

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:

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	2005		2004
Audit fees	$	3,282	$	2,945
Audit-related fees (1)	125		110
Tax fees (2)	—		—
All other fees (3)	5		—

Total accounting fees and services	$	3,412	$	3,055

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

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

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

Pre-Approval of Audit and Permitted Non-Audit Services. The Audit Committee is responsible for appointing, setting compensation and overseeing the work of the independent public accountants. The Audit Committee established a policy that requires the Partnership to have the Audit Committee pre-approve all audit and permitted non-audit services from the independent public accountants. The Company’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: 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.

(3) Exhibits: See (b) below.

(b) Exhibits required by Item 601 of Regulation S-K.

Exhibit Number		Description

2.1(4)		Share Purchase Agreement between MarkWest Hydrocarbon Acquisition Corporation and Kaiser Energy, Ltd., dated as of August 10, 2001.

2.2(4)		Share Purchase Agreement between MarkWest Hydrocarbon Acquisition Corporation and Brian E. Hiebert, Guy C. Crierson, Ian R. DeBie, Gordon A. Maybee, Erin Hiebert, Raylene Grierson, Kathleen DeBie and Patricia Maybee, dated as of August 10, 2001.

2.3(8)		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.

2.4(8)		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.

2.5(12)		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.

2.6(11)		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.

2.7(15)		Asset Purchase and Sale Agreement and addendum, thereto, dated as of July 1, 2004 by and between American Central Eastern Texas Gas Company Limited Partnership, ACGC Gathering Company, L.L.C. and MarkWest Energy East Texas Gas Company’s L.P.

3.1(1)		Certificate of Incorporation of MarkWest Hydrocarbon, Inc.

3.2(1)		Bylaws of MarkWest Hydrocarbon, Inc.

4.1(7)		Subordinated Unit Purchase Agreement among MarkWest Hydrocarbon, Inc. and Tortoise MWEP, L.P., dated as of November 20, 2002.

4.2(14)		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.

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4.3(14)		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.

4.4(15)		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.

4.5(15)		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.

4.6(16)		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.

4.7(16)		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.

4.8(16)		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.

4.9(16)		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.

4.10(16)		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 4.9 hereto).

10.1(2)		1996 Incentive Compensation Plan.

10.2(1)		1996 Stock Incentive Plan.

10.3(1)		1996 Non-employee Director Stock Option Plan.

10.4(1)		Form of Non-Compete Agreement between John M. Fox and MarkWest Hydrocarbon, Inc.

10.5(3)		MarkWest Hydrocarbon, Inc., 1997 Severance and Non-Compete Plan.

10.6(5)		Amendment to Gas Processing Agreement (Maytown) dated as of March 26, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc.

10.7(11)		Credit Agreement dated as of May 20, 2002, among MarkWest Energy Operating Company, L.L.C. (as borrower), MarkWest Energy Partners, L.P. (as a Guarantor), and various lenders.

10.8(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.

10.9(6)		Fifth Amended and Restated Credit Agreement among MarkWest Hydrocarbon, Inc. and various lenders, dated as of May 24, 2002.

10.10(11)		Amended and Restated Canadian Credit Agreement among MarkWest Resources Canada Corp. and various lenders, dated as of May 24, 2002.

10.11(5)		Omnibus Agreement dated as of May 24, 2002, among MarkWest Hydrocarbon, Inc.; MarkWest

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		Energy GP, L.L.C.; MarkWest Energy Partners, L.P.; and MarkWest Energy Operating Company, L.L.C.

10.12(5)+		Fractionation, Storage and Loading Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.

10.13(5) +		Gas Processing Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.

10.14(5) +		Pipeline Liquids Transportation Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.

10.15(5)		Natural Gas Liquids Purchase Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.

10.16(5) +		Gas Processing Agreement (Maytown) dated as of May 28, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc.

10.17(9)		Purchase and Sale Agreement, dated as of June 5, 2003, by and among MarkWest Hydrocarbon, Inc., MarkWest Resources, Inc., and XTO Energy Inc.

10.18(10)		Purchase and Sale Agreement dated as of July 31, 2003, among Raptor Natural Plains Marketing LLC, Raptor Gas Transmission LLC, Power-Tex Joint Venture and MarkWest Pinnacle L.P.

10.19(11)		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.

10.20(14) ^		Executive Employment Agreement effective November 1, 2003 between MarkWest Hydrocarbon, Inc. and Frank Semple.

10.21(15)		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.

10.22(15)		First Amendment to the Second Amended and Restated Credit Agreement dated as of August 20, 2004, among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe Generale, as Documentation Agent.

10.23(17)		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.

10.24(5) ^		MarkWest Energy Partners, L.P. Long-Term Incentive Plan.

10.24(5) ^		First Amendment to MarkWest Energy Partners, L.P. Long-Term Incentive Plan.

10.25(18)		Credit Agreement among MarkWest Hydrocarbon, Inc. as the Borrower, Royal Bank of Canada, as Administrative Agent and The Lenders Party Hereto to the $25,000,000 Senior Credit Facility.

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10.26+		Purchase and Sale of Natural Gas Agreement dated as of September 24, 2004, between MarkWest Hydrocarbon, Inc. and Equitable Production Company.

10.27+		A Firm Natural Gas Processing Agreement dated as of September 24, 2004, between MarkWest Hydrocarbon, Inc. and Equitable Production Company.

10.28+		A Netting, Financial and Security Agreement dated as of September 24, 2004, between MarkWest Hydrocarbon, Inc. and Equitable Production Company.

10.29(21)		Fourth Amended and Restated Credit Agreement, dated as of November 1, 2005.

10.30(22)		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.

11.1(13)		Statement regarding computation of earnings per share.

16.1(19)		Letter from KPMG LLP regarding Change in Certifying Accountants.

16.2(20)		Letter from PricewaterhouseCoopers LLP regarding Change in Certifying Accountants.

21.1 *		List of Subsidiaries of MarkWest Hydrocarbon, Inc.

23.1 *		Consent of Deloitte & Touche LLP.

23.2 *		Consent of KPMG LLP.

23.3 *		Consent of PricewaterhouseCoopers LLP.

31.1 *		Chief Executive Officer Certification Pursuant to Rule 13a-14(a) of the Securities Exchange Act.

31.2 *		Chief Financial Officer Certification Pursuant to Rule 13a-14(a) of the Securities Exchange Act.

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

(1)	Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Registration Statement on Form S-1, Registration No. 333-09513, filed with the Commission on August 2, 1996.
(2)	Incorporated by reference to Amendment No. 1 to MarkWest Hydrocarbon Inc.’s Registration Statement on Form S-1, Registration No. 333-09513, filed with the Commission on September 13, 1996.
(3)	Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Quarterly Report on Form 10-Q for the three months ended September 30, 1997, filed with Commission on November 13, 1997.
(4)	Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Current Report on Form 8-K, filed with the Commission on August 27, 2001.
(5)	Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K, filed with the Commission on June 7, 2002.
(6)	Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Quarterly Report on Form 10-Q for the three months ended June 30, 2002, filed with the Commission on August 14, 2002.
(7)	Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Current Report on Form 8-K, filed with the Commission on November 25, 2002.

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(8)	Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K, filed with the Commission on April 14, 2003.
(9)	Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K filed with the Commission on June 29, 2003.
(10)	Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Current Report on Form 8-K, filed with the Commission on July 15, 2003.
(11)	Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K, filed with the Commission on September 17, 2003.
(12)	Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K, filed with the Commission on December 16, 2003.
(13)	Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K, filed with the Commission on December 31, 2003.
(14)	Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Annual Report on Form 10-K filed with the Commission on March 30, 2004.
(15)	Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K/A filed with the Commission on September 13, 2004.
(16)	Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K filed with the Commission on October 25, 2004.
(17)	Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K filed with the Commission on October 29, 2004.
(18)	Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Current Report on Form 8-K filed with the Commission on October 29, 2004.
(19)	Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Current Report on Form 8-K, filed with the Commission on September 23, 2005.
(20)	Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Current Report on Form 8-K, filed with the Commission on April 6, 2004.
(21)	Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K filed with the Commission on November 7, 2005.
(22)	Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K filed with the Commission on January 5, 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 has been filed separately with the Securities and Exchange Commission.
*	Filed herewith.
^	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 Hydrocarbon, Inc.
		(Registrant)

Date: March 20, 2006	By:	/S/Frank M. Semple
		Frank M. Semple
		President and Chief Executive Officer
		(Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities with MarkWest Hydrocarbon Inc., the Registrant, and on the dates indicated.

Date: March 20, 2006	By:	/S/Frank M. Semple
		Frank M. Semple
		President and Chief Executive Officer
		(Principal Executive Officer)

Date: March 20, 2006	By:	/S/James G. Ivey
		James G. Ivey
		Chief Financial Officer
		(Principal Financial Officer)

Date: March 20, 2006	By:	/S/NANCY K. MASTEN
		Nancy K. Masten
		Chief Accounting Officer
		(Principal Accounting Officer)

Date: March 20, 2006	By:	/S/John m. Fox
		John M. Fox
		Chairman of the Board and Director


Date: March 20, 2006	By:	/S/MICHAEL L. BEATTY
		Michael L. Beatty
		Director

Date: March 20, 2006	By:	/S/Donald C. Heppermann
		Donald C. Heppermann
		Director

Date: March 20, 2006	By:	/S/WILLIAM A. KELLSTROM
		William A. Kellstrom
		Director

Date: March 20, 2006	By:	/S/ANNE E. MOUNSEY
		Anne E. Mounsey
		Director

Date: March 20, 2006	By:	/S/karen l. rogers
		Karen L. Rogers
		Director

Date: March 20, 2006	By:	/S/William f. WALLACE
		William f. Wallace
		Director

Date: March 20, 2006	By:	/S/DONALD D. WOLF
		Donald D. Wolf
		Director

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