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Table of Contents
Item 8. Financial Statements and Supplemental Data

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

FORM 10-K/A
(Amendment No. 2)

Commission File Number 001-14841

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

1515 Arapahoe Street, Tower 2, Suite 700, Denver, Colorado 80202
(Address of principal executive offices)

Registrant's telephone number, including area code: 303-925-9200

        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 ý No o

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K/A or any amendment to this Form 10-K/A.    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, 2006 was approximately $155,351,000.

        The registrant had 11,992,520 shares of common stock, $0.01 per share par value, outstanding as of February 15, 2007.

DOCUMENTS INCORPORATED BY REFERENCE: None

Explanatory Note

        We have determined that, in certain cases, we did not comply with accounting principles generally accepted in the United States of America in the preparation of our 2006 and 2005 consolidated financial statements and, accordingly, this Amendment No. 2 on Form 10-K/A amends the Annual Report on Form 10-K originally filed by MarkWest Hydrocarbon, Inc. (the "Company") on March 6, 2007 for the year ended December 31, 2006 (the "original report") to restate the Company's previously issued consolidated financial statements.

        The Company has determined that previously issued consolidated financial statements for the years ended December 31, 2006 and 2005 and the quarters ended March 31 and June 30, 2007 should be restated to correct an error in accounting for certain revenue arrangements in the Partnership's (as defined below) East Texas segment which were accounted for net as an agent. The effect on the financial statements for the year ended 2004 was deemed immaterial. The Company has determined in these arrangements it acted as the principal and therefore the revenue should have been reported gross. The Company is filing contemporaneously with this Form 10-K/A for the year ended December 31, 2006, which includes restated financial statements for the years ended December 31, 2006 and 2005. Form 10-Q/A for the quarterly period ended March 31, 2007 and Form 10-Q/A for the Quarterly period ended June 30, 2007 which reflect the effects of the restatement in the respective interim periods.

        As discussed in Note 24, Restatement of Consolidated Financial Statements, to the consolidated financial statements in Item 8 of this Form 10-K/A, we have restated our previously reported results to properly record certain types of revenue transactions on a gross presentation in the Partnership's East Texas segment consistent with the guidance in Emerging Issues Task Force ("EITF") Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent. These transactions were previously accounted for Net as an Agent. This guidance requires MarkWest Hydrocarbon to record revenue gross when it acts as a principal and net when it acts as an agent.

        This Form 10-K/A amends and restates only Part I, Item 1, and Part II, Items 6, 7, 8 and 9A of the original report. The remaining items are not amended. Except for the foregoing amended information, this Form 10-K/A continues to describe conditions as of the date of the original report, and the Company has not updated the disclosures contained herein to reflect events that occurred subsequently. Accordingly, this Form 10-K/A should be read in conjunction with Company filings made with the Securities and Exchange Commission subsequent to the filing of the original report, including any amendments of those filings.

        Amendment No. 1 to the Annual Report on Form 10-K of MarkWest Hydrocarbon, Inc. for the fiscal year ended December 31, 2006, was filed for the purpose of correcting MarkWest Hydrocarbon Standalone contract volumes set forth in the columns "Fixed Physical Forwards" and "Fixed Swaps" to appropriately reflect daily volumes rather than total volumes, as previously reported with the Securities and Exchange Commission on March 7, 2007, as discussed in Item 7A—Quantitative and Qualitative Disclosures About Market Risk and Item 8. Financial Statements and Supplemental Data—Note 13. For the convenience of the reader, Amendment No. 1 to Form 10-K set forth the original Form 10-K in its entirety. Amendment No. 1 to Form 10-K did not reflect events occurring after the filing of the original Form 10-K.

        As required by Rule 12b-15 promulgated under the Securities and Exchange Act of 1934, our Chief Executive Officer and Chief Financial Officer provided Rule 13a-14(a) certifications dated March 21, 2007, in connection with Amendment No. 1 to Form 10-K and written statements pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 dated March 21, 2007.

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MarkWest Hydrocarbon, Inc.
Form 10-K/A

Table of Contents

        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" is intended to mean MarkWest Energy Partners, L.P.

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Glossary of Terms

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

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Forward-Looking Statements

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

        Management bases these statements on its expectations, estimates, assumptions and beliefs concerning future events affecting us and therefore they 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. Forward-looking statements include statements relating to, among other things:

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Our expectations regarding MarkWest Energy Partners, L.P.



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



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Our expectations regarding natural gas and NGL products and prices.



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Our efforts to increase fee-based contract volumes.



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Our ability to manage our commodity price risk.



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Our ability to maximize the value of our NGL output.



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



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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:

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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, crude oil and natural gas, including the effectiveness of any hedging activities.



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Our ability to negotiate favorable marketing agreements.



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



•

Competition from other NGL processors, including major energy companies.



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



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The Partnership's ability to successfully integrate its recent and future acquisitions.



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The Partnership's ability to identify and complete organic growth projects or acquisitions complementary to its business.



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The Partnership's substantial debt and other financial obligations could adversely affect its financial condition.



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The Partnership's ability to raise sufficient capital to execute our business plan through borrowing or issuing equity.



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



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The success of our risk management policies.

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•

The operational hazards and availability and cost of insurance on our assets and operations.



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The 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.



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The impact of any failure of our information technology systems.



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The impact of current and future laws and government regulations.



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The liability for environmental claims.



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The impact of the departure of any key executive officers.



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Winter weather conditions.



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The threat of terrorist attacks or war.

        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/A for further information.

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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.

        MarkWest Hydrocarbon's assets consist primarily of partnership interests in MarkWest Energy Partners and certain processing agreements in Appalachia. As of December 31, 2006, the Company owned a 17% interest in the Partnership, consisting of the following (all unit information has been adjusted for the February 2007 unit split; see Note 2 to the Consolidated Financial Statements):

•

3,738,992 common units and 1,200,000 subordinated units, representing a combined 15% limited partner interest in the Partnership; and



•

an 89.7% 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

        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

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then processed to remove the heavier hydrocarbon components and other contaminants that interfere with pipeline transportation or the end-use of the gas. Our business includes providing these services either for a fee or a percentage of the NGLs removed or gas units processed. The industry as a whole is characterized by regional competition, based on the proximity of gathering systems and processing plants to producing natural gas wells, or to facilities that produce natural gas as a by product of refining crude oil.

        MarkWest Energy Partners 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 Partnership's 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 the Partnership's Javelina facilities, the natural gas delivered to its 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, the Partnership also produces a high 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:

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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,

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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.



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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.



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



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Ethylene and propylene are principally used as petrochemical feedstock.



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

Competition

        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 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 high-quality customer relationships.

        The Partnership's competitors include:

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



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major integrated oil companies;



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medium and large sized independent exploration and production companies;



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major interstate and intrastate pipelines; and



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

        We believe the Partnership's competitive strengths include:

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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.



•

Strategic and growing position with high-quality assets in the Southwest and the Gulf Coast. The Partnership's acquisitions and internal growth projects have allowed it to establish and expand its

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presence in several long-lived natural gas supply basins in the Southwest, particularly in Texas, Oklahoma and the Gulf Coast. In 2006 the Partnership expanded this strategy through its Newfield agreement by building the largest gathering system to date in the newly emerging Woodford Shale play in southeastern Oklahoma. All of the Partnership's major acquisitions in these regions have been characterized by several common critical success factors that include:

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an existing strong competitive position;



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



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ample opportunities for long-term continued organic growth;



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ready access to markets; and



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close proximity to other acquisition or expansion opportunities.

Specifically, the Partnership's East Texas and Appleby gathering systems are located in the East Texas basin producing from both the Cotton Valley and Travis Peak reservoirs. The Partnership's Foss Lake gathering system and the associated Arapaho gas processing plant, which it refers to as its western Oklahoma assets, are located in the Anadarko basin in Oklahoma. Additionally, as mentioned above, the Partnership's Woodford gathering system is located in the rapidly growing Woodford Shale reservoir. Finally, the Partnership's Starfish asset gathers gas from multiple reservoirs in the Gulf of Mexico. Each of these basins is highly prolific with long lived reserves and significant growth potential. The Partnership's gathering systems are relatively new and provide producers with low-pressure and fuel-efficient service, a significant competitive advantage for it over many competing gathering systems in those areas. The Partnership believes this competitive advantage is evidenced by its growing throughput volumes on its East Texas, Appleby, western and southeastern Oklahoma operations.

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Long-term contracts. We believe MarkWest Energy Partners' long-term contracts, which we define as contracts with remaining terms of five years or more, lend greater stability to its cash-flow profile. For the year ended December 31, 2006, approximately 67% of the Partnership's inlet volumes were tied to long-term contracts.



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Experienced management with operational, technical and acquisition expertise. Each member of our executive management team has substantial experience in the energy industry. The Partnership's facility managers have extensive experience operating their facilities. The Partnership's operational and technical expertise has enabled it to upgrade its existing facilities, as well as to design and build new ones, specifically the Carthage gas processing plant. Since the Partnership's initial public offering in May 2002, its management team has utilized a disciplined approach to analyze and evaluate numerous acquisition opportunities, and has completed nine acquisitions. The Partnership intends to continue to use its management's experience and disciplined approach in evaluating and acquiring assets to grow through accretive acquisitions. The acquisitions are expected to increase throughput volumes and ultimately increase cash flow distributable to the Partnership's 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:

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The nature of our relationship with MarkWest Energy Partners;



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



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

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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 profit interest in the gathering and processing income earned on quarterly pipeline throughput in excess of 10 MMcf/d. In accordance with accounting principles generally accepted in the United States ("GAAP"), 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, 2006, we accounted for 13% of the Partnership's revenues and 12% of its net operating margin (a non-GAAP financial measure, see Item 1. Business—Contracts), compared to 13% of revenues and 20% of net operating margin for the year ending December 31, 2005. We expect we will account for less of the Partnership's business in the future as it continues to acquire assets and increase its customer base and 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.

Contracts

MarkWest Hydrocarbon

        Excluding the revenues derived from MarkWest Energy Partners, we generate the majority of our revenues and net operating margin 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 content 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 the 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 various operating agreements with one customer related to the delivery of natural gas into its transmission facilities, located 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 it ships on behalf of the Appalachian producers. The initial terms of our agreements with this customer run through February 9, 2015, with annual renewals thereafter.

        In September 2004 we entered into several new and amended agreements with this customer mentioned above in the Appalachia region. These agreements, which expire in 2015 assuming renewals

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we deem likely, will 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 the keep-whole contracts. We also retained our NGL marketing and natural gas supply operations and did not contribute them to MarkWest Energy Partners.

        The 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

        The Partnership generates the majority of its revenue and net operating margin from natural gas gathering, processing and transmission, NGL transportation, fractionation and storage; and crude oil gathering and transportation. In many cases, the Partnership provides services under contracts that contain a combination of more than one of the arrangements described below. While all of these services constitute midstream energy operations, the Partnership provides services under the following different types of arrangements:

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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 arrangements is directly related to the volume of natural gas, NGLs or crude oil that flows through our systems and facilities and is not directly dependent on commodity prices. In certain cases, these arrangements provide for minimum annual payments. If a sustained decline in commodity prices were to result in a decline in volumes, the Partnership's revenues from these arrangements would be reduced.



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Percent-of-proceeds arrangements. The Partnership gathers and processes natural gas on behalf of producers, sells the resulting residue gas, condensate 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, 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. Generally, under these types of arrangements its revenues and net operating margins increase as natural gas, condensate and NGL prices increase, and its revenues and net operating margins decrease as natural gas and NGL prices decrease.



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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, their net operating margins increase during periods of high natural gas prices.

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Keep-whole arrangements. The Partnership gathers natural gas from the producer, processes the natural gas, and sells the resulting condensate and NGLs to third parties at market prices. Because the extraction of the condensate and 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 the Partnership's revenues and net operating margins increase as the price of condensate and NGLs increases relative to the price of natural gas, and decreases as the price of natural gas increases relative to the price of condensate and NGLs.



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Settlement margin. Typically, the Partnership 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.

        The terms of the Partnership's contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements. The Partnership's contract mix and, accordingly, its exposure to natural gas and NGL prices, may change as a result of changes in producer preferences, its expansion in regions where some types of contracts are more common and other market factors. Any change in mix will influence the Partnership's financial results.

        Management evaluates performance on the basis of net operating margin (a non-GAAP financial measure), which is defined as income (loss) from operations, excluding facility cost, 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. 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 of excluding certain charges is not necessarily an indication of the results of operations expected in the future. The following table represents reconciliation to the most comparable GAAP financial measure of this non-GAAP financial measure (in thousands):

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        For the year ended December 31, 2006, MarkWest Energy Partners calculated the following approximate percentages of its revenues and net operating margin from the following types of contracts, exclusive of the impact of commodity derivatives:

(1)

Includes other types of arrangements tied to NGL prices.

(2)

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

(3)

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

        Our short natural gas positions under our keep-whole contracts are largely offset by our long positions in our other operating areas. As a result, our net exposure to natural gas is not significant. While the percentages in the table above accurately reflect the percentages by contract type, we manage our business by taking into account the offset described above, required levels of operational flexibility and the fact that our hedge plan is implemented on this basis. When considered on this basis, the calculated percentages for the net operating margin in the table above for percent-of-proceeds, percent-of-index and keep-whole contracts change to 62%, 0% and 6%, respectively.

Impact of Recent Acquisitions on Comparability of Financial Results

MarkWest Energy Partners

        In reading the discussion of our historical results of operations, you should be aware of the impact of the Partnership's recent acquisitions, which fundamentally affect the comparability of our results of operations over the periods discussed.

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        Since the Partnership's initial public offering, it has completed nine acquisitions for an aggregate purchase price of approximately $810 million, net of working capital. The following table contains information regarding each of these acquisitions (in millions):

(1)

Consideration includes $35.5 million in cash.

(2)

Represents a 50% non-controlling interest.

Segment Reporting

        The Company's financial statements include two reportable segments; MarkWest Hydrocarbon Standalone and MarkWest Energy Partners. For further information regarding our segments, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation and Item 8. Financial Statements and Supplementary Data included in this Form 10-K/A.

        For the year ended December 31, 2006, the MarkWest Hydrocarbon Standalone segment had two significant customers while the MarkWest Energy Partners' segment had three. Of these five significant customers, only one, Targa Resources Partners, L.P., had a significant impact on the Company's consolidated financial statements, accounting for 10% of consolidated revenue.

MarkWest Hydrocarbon Standalone

        Our marketing group markets NGL production in Appalachia. In 2006, we sold approximately 162 million gallons of NGLs extracted at the Partnership's Siloam facility. This includes approximately 43 million gallons sold on behalf of the Partnership at no mark-up in the standalone segment. 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.

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Belvieu index prices or plant posting prices. In addition to our NGL product sales, our marketing operations also purchase natural gas for delivery to the account of producers, pursuant to our keep-whole processing contracts.

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

        In Appalachia, we have entered into various operating agreements with one customer related to the delivery of natural gas into its transmission facilities, located 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 it ships on behalf of the Appalachian producers. The initial terms of our agreements with this customer run through February 9, 2015, with annual renewals thereafter.

        Consistent with the Partnership's operating agreements with this same customer, the Partnership enters into contracts with natural gas producers for production to occur 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 over 250 such producers in Appalachia. 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 Partners as discussed below), we earn a fee and also retain the NGLs produced under keep-whole agreements. In return, we are required to replace, in dry natural gas, the Btu content of the NGLs extracted.

        In September 2004 we entered into several new and amended agreements with one of the largest producers in the Appalachia region. These agreements, which expire in 2015 assuming renewals we deem likely, will 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.

        Our natural gas marketing group markets natural gas for the Partnership, purchases the necessary replacement Btu gas requirements and assists with business development efforts. From February 2004 through June 2006, the Company engaged in the wholesale propane marketing business through a third party agency agreement. The Company completed the terms of the termination agreement with the third party agency in February 2007. MarkWest Hydrocarbon also enters into future sale agreements that, as derivative instruments, are marked to market.

MarkWest Energy Partners

        MarkWest Energy Partners' assets and operations may be summarized as follows:

Southwest Business Unit

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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. The East Texas system is located in Panola, Harrison and Rusk Counties and services the Carthage Field, one of the largest onshore natural gas fields in Texas. Producing

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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.

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Oklahoma. MarkWest Energy Partners owns the Foss Lake gathering system and the Arapaho gas processing plant, located in Roger Mills, Custer and Ellis 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. The Partnership also owns a gathering system in the Woodford Shale Play in the Arkoma Basin of southeastern Oklahoma, and owns the Grimes Gathering System, which is located in Roger Mills and Beckham counties in western Oklahoma.



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Other Southwest. MarkWest Energy Partners owns a number of 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 many areas the Partnership is the primary gatherer, and in some of the areas served by its smaller systems, they are the sole gatherer. The Partnership also owns four lateral pipelines in Texas and New Mexico.

Northeast Business Unit

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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. The Partnership's Appalachian assets include the Kenova, Boldman, Maytown, Cobb and Kermit natural gas-processing plants, a NGL pipeline, a NGL fractionation plant and two caverns for storing propane.



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Michigan. MarkWest Energy Partners owns a common carrier crude oil gathering pipeline in Michigan which is subject to regulation by the Federal Energy Regulatory Commission ("FERC"). They refer to this pipeline as the Michigan crude pipeline. The Partnership also owns the Fisk processing plant in Manistee County, Michigan.

Gulf Coast Business Unit

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

        The Partnership also owns a 50% non-operating membership interest in Starfish Pipeline Company, LLC, whose assets are located in the Gulf of Mexico and southwestern Louisiana. The Starfish interest is part of a joint venture with Enbridge Offshore Pipelines LLC, which is accounted for using the equity method; the financial results for Starfish are included in equity from earnings from unconsolidated affiliates and are not included in the Gulf Coast Business Unit results.

Regulatory Matters

        Our operations are subject to extensive regulations. The failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on our operations increases our cost of doing business and, consequently, affects our profitability. However, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors. Due to the myriad of complex federal, state, provincial and local regulations that may affect us, directly

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or indirectly, you should not rely on the following discussion of certain laws and regulations as an exhaustive review of all regulatory considerations affecting our operations.

Pipeline and Gathering Regulation

        Interstate Gas Pipelines.    Our natural gas pipeline operations are subject to federal, state and local regulatory authorities. Specifically, our Hobbs, New Mexico natural gas pipeline and our Michigan crude oil pipeline facilities and related assets are subject to regulation by the FERC. Federal regulation extends to such matters as:

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rate structures;



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rates of return on equity;



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recovery of costs;



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the services that our regulated assets are permitted to perform;



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the acquisition, construction and disposition of assets; and



•

to an extent, the level of competition in that regulated industry.

        Under the Natural Gas Act, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Its authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services, and various other matters. Natural gas companies may not charge rates that have been determined not to be just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service. The rates and terms and conditions for our service will be found in FERC-approved tariffs. Pursuant to FERC's jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. We cannot assure you that FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity, and transportation facilities. Any successful complaint or protest against our rates, or loss of market-based rate authority by FERC could have an adverse impact on our revenues associated with providing interstate gas transportation services.

        Should our FERC regulated pipeline operations fail to comply with all applicable FERC administered statutes, rules, regulations and orders; we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1,000,000 per day for each violation.

        Gathering and Intrastate Pipeline Regulation.    Section 1(b) of the Natural Gas Act exempts natural gas gathering facilities from the jurisdiction of FERC. We own a number of facilities that we believe meet the traditional tests FERC have used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. In the states in which we operate, regulation of gathering facilities and intrastate pipeline facilities generally includes various safety, environmental and, in some circumstances, open access, nondiscriminatory take requirements and complaint-based rate regulations. For example, some of our natural gas gathering facilities are subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas.

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        Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a less stringent approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

        Our intrastate gas pipeline facilities are subject to various state laws and regulation that affect the rates we charge and terms of service. Although state regulation is typically less onerous than at FERC, state regulation typically requires pipelines to charge just and reasonable rates and to provide service on a non-discriminatory basis. The rates and service of an intrastate pipeline generally are subject to challenge by complaint.

        The Partnership's 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 the 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 the Partnership's results of operations. In such a case, we would be required to file a tariff with FERC and provide a cost justification for the transportation charge. Regardless of any FERC action, however, MarkWest Hydrocarbon has agreed to not challenge the status of the Appalachian pipeline or the transportation charge during the term of its agreements.

        Crude Common Carrier Pipeline Operations.    Our Michigan Crude Pipeline is a crude oil pipeline that is a common carrier and subject to regulation by the FERC under the October 1, 1977 version of the Interstate Commerce Act (ICA) and the Energy Policy Act of 1992 (EPAct 1992). The ICA and its implementing regulations give the FERC authority to regulate the rates charged for service on the interstate common carrier liquids pipelines and generally require the rates and practices of interstate liquids pipelines to be just and reasonable and nondiscriminatory. The ICA also requires tariffs to be maintained on file with the FERC that set forth the rates it charges for providing transportation services on its interstate common carrier liquids pipelines as well as the rules and regulations governing these services. EPAct 1992 and its implementing regulations allow interstate common carrier oil pipelines to annually index their rates up to a prescribed ceiling level. In addition, the FERC retains cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach.

        With respect to our Michigan Crude Pipeline, we filed a tariff establishing a cost-of-service rate structure to be effective starting January 1, 2006. Two shippers and a producer protested the filing. On December 29, 2005, the Commission accepted our filing and permitted the rates to go into effect subject to refund. The Commission established hearing procedures but first referred the parties to settlement discussions before a FERC-appointed settlement judge. On January 31, 2006, the parties submitted a settlement to the FERC that re-established the pre-existing Michigan intrastate pipeline rates with minor modifications and place a moratorium on rate changes or challenges for a three-year

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period, with limited exceptions. On March 7, 2006, the FERC settlement judge certified the settlement to the FERC as uncontested and fair, reasonable, and in the public interest.

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 stringent and comprehensive federal, 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 stringent and comprehensive requirements may expose the Partnership to fines, penalties and/or interruptions in its operations that could influence future results of operations.

        The Partnership believes that its operations and facilities are in substantial compliance with applicable environmental laws and regulations, and that the cost of continued compliance with such laws and regulations will not have a material adverse effect on its results of operations or financial condition. The Partnership cannot ensure, however, that existing environmental laws and regulations will not be revised or that new laws and regulations will not be adopted or become applicable to it. The clear trend in environmental law 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 anticipates. Revised or additional environmental requirements that result in increased compliance costs or additional operating

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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.

Hazardous Substance and Waste

        To a large extent, the environmental laws and regulations affecting the Partnership's operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control environmental pollution of the environment. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, as amended, or CERCLA, also known as the "Superfund" law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to a release of "hazardous substance" into the environment. These persons include the owner or operator of a site where a release occurred, both current and past, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, liability is imposed upon persons under a strict liability theory, that is without regard to intent or fault, and these persons may be subject to joint and several liability for the costs of removing or remediating hazardous substances that have been released into the environment, for restoration and damages to natural resources, and for the costs of certain health studies. Additionally, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. While the Partnership generates materials in the course of its operations that are regulated as hazardous substances, they have not received any notification that they may be potentially responsible for cleanup costs under CERCLA. The Partnership may also incur a liability under the Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes, which impose requirements relating to the handling and disposal of hazardous wastes and non-hazardous solid wastes. The Partnership is not currently required to comply with a substantial portion of the RCRA requirements because its operations generate minimal quantities of hazardous wastes. However, it is possible that some wastes generated by the Partnership that are currently classified as non-hazardous may, in the future, be designated as "hazardous wastes," resulting in the wastes being subject to more rigorous and costly disposal requirements.

        The Partnership currently owns or leases, and have in the past owned or leased, properties that have been used over the years for natural gas gathering and processing, for NGL fractionation, transportation and storage and for the storage and gathering and transportation of crude oil. Although solid waste disposal practices within the NGL industry and other oil and natural gas related industries have improved over the years, a possibility exists that hydrocarbons and other solid wastes or hazardous wastes may have been disposed of on or under various properties owned or leased by the Partnership during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under the Partnership's control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, the Partnership could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination or to perform remedial operations to prevent future contamination. The Partnership does not believe that there presently exists significant surface and subsurface contamination of its properties by hydrocarbons or other solid wastes for which it is currently responsible.

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/

21

operator has accepted sole liability and responsibility for, and indemnifies MarkWest Hydrocarbon against, any environmental liabilities associated with the EPA Administrative Order, the Kentucky Agreed Order or any other environmental condition related to the real property prior to the effective dates of MarkWest Hydrocarbon's lease or purchase of the real property. In addition, the previous owner/operator has agreed to perform all the required response actions at its expense in a manner that minimizes interference with MarkWest Hydrocarbon's use of the properties. On May 24, 2002, MarkWest Hydrocarbon assigned to us the benefit of this indemnity from the previous owner/operator. To date, the previous owner/operator has been performing all actions required under these agreements and, accordingly, we do not believe that the remediation obligation of these properties will have a material adverse impact on the Partnership's financial condition or results of operations.

Air

        The Clean Air Act, as amended and comparable state laws restrict the emission of air pollutants from many sources, including processing plants and compressor stations. These laws and any implementing regulations may require the Partnership to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. While the Partnership may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing other air emission-related issues, it does not believe that such requirements will have a material adverse affect on its operations.

Water

        The Federal Water Pollution Control Act of 1972, as amended, also known as the "Clean Water Act and analogous state laws impose restrictions and controls on the discharge of pollutants into federal and state waters. Such discharges are prohibited, except in accord with the terms of a permit issued by the EPA or the state. Any unpermitted release of pollutants, including natural gas liquids or condensates, could result in penalties, as well as significant remedial obligations. The Partnership believes that it is in substantial compliance with the Clean Water Act.

Pipeline Safety Regulations

        Our pipelines are subject to regulation by the U.S. Department of Transportation ("DOT") under the Pipeline Safety Act of 1992, as amended the newly enacted Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, (collectively the "Pipeline Safety Acts"), 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 of 1992 required 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. The Pipeline Inspection, Protection,

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Enforcement, and Safety Act of 2006 expands the DOT's authority and calls for additional studies and additional regulations to be promulgated in many areas, including integrity management, corrosion control, incident reporting, inspection and enforcement orders. 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 position.

        The Partnership's affiliate MarkWest Energy Appalachia, L.L.C. ("MEA") operates the Appalachia Liquids Pipeline System ("ALPS") pipeline to transport NGLs from its Maytown gas processing plant to its Siloam fractionator. This pipeline is owned by Equitable Production Company, and is leased and operated by MEA. On November 8, 2004, a leak and an ensuing fire occurred on the line in the area of Ivel, Kentucky, and the line was taken out of service pending investigation and repair. In accordance with an Office of Pipeline Safety ("OPS") Corrective Action Order, MEA successfully conducted a hydrostatic test of the affected portion of the ALPS pipeline in 2005 and OPS authorized a partial return to service of the affected pipeline in October 2005. As part of its ongoing operation of the ALPS pipeline, MEA continued to perform pipeline integrity assessments and implement an in-line inspection program on the ALPS pipeline. Preliminary data from a four mile section of its in-line inspection program identified areas for investigation and corrective action. In November 2006 MEA temporarily idled the line while additional assessment and investigation was undertaken to address these concerns. In late January 2007, MEA received the completed report from its in-line inspection operator and consultant. This report indicated areas of significant external corrosion or other defects in the four mile section of pipeline in which the in-line inspection was conducted. The assessment of this completed report, coupled with other information MEA has gathered, will continue to be reviewed and MEA will work with Equitable to determine what the most appropriate corrective action may be. In the interim, the pipeline will be maintained in idle status. MEA is trucking the NGLs produced from our Maytown plant to the Siloam fractionation facility while MEA is maintaining the pipeline in idle status, and as a result, operations have not been interrupted. The additional transportation costs associated with the trucking are not expected to have material adverse effect on our results of operations or financial positions.

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. Even though we cannot accurately estimate these expenditures at this time, we do not expect that they will have a material adverse effect on our results of operations.

Employees

        As of December 31, 2006, we had 318 employees, who operate the Company's facilities and provide general and administrative services. The Paper, Allied Industrial, Chemical and Energy Workers International Union Local 5-372 represents 14 employees at the Partnership's Siloam fractionation facility in South Shore, Kentucky. The collective bargaining agreement with this Union

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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 1515 Arapahoe Street, Tower 2, Suite 700, Denver, Colorado, 80202-2126. Our telephone number is 303-925-9200. 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/A, 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/A, 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' 2006 Annual Report on Form 10-K/A.

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 future acquisitions. We cannot guarantee that the Partnership will successfully integrate any acquisitions into its operations or that the Partnership will achieve the desired profitability and anticipated results from such acquisitions. Failure to achieve such planed results could adversely affect our financial condition and results of operations.

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

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



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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;



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



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the diversion of management's attention from other business concerns;



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the failure to realize expected synergies and cost savings;



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coordinating geographically disparate organizations, systems and facilities;



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integrating personnel from diverse business backgrounds and organizational cultures; and



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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

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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 shareholders 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 crude oil, natural gas and certain NGLs with the intent of reducing volatility in our cash flows due to fluctuations in commodity prices.

        The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. We have a policy to enter into derivative transactions related to only a portion of the volume of our expected production or fuel requirements and, as a result, we will continue to have direct commodity price exposure to the unhedged portion. Our actual future production or fuel requirements may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our hedging activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our hedging policies and procedures are not properly followed. It is possible that the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. 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. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation and Item 7A. Quantitative and Qualitative Disclosures About Market Risk as set forth in this report for more information about our risk management policies and procedures.

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.

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        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 their outstanding notes, the Partnership may incur significant additional indebtedness and other financial obligations.

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

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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 their 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.

        Furthermore, these consequences could limit the Partnership's ability, and the ability of the its subsidiaries, to obtain future financings, make needed capital expenditures, withstand a future downturn in the 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 us to maintain specified financial ratios and satisfy other financial conditions, which may limit our ability to grant liens on its 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 senior to the credit facility, make distributions on equity investments, and declare or make, directly or indirectly, any distribution on the Partnership common units. The Partnership obligations under the credit facility are secured by substantially all of its assets and guaranteed by them and all of their

26

subsidiaries, other than the Partnership's operating company, which is the borrower under the credit facility. In particular, 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 their credit facility, which could result in acceleration of the Partnership's debt and other financial obligations. If the Partnership were unable to repay those amounts, the lenders could initiate a bankruptcy or liquidation proceeding, or proceed against the collateral.

A significant decrease in natural gas production in the Partnership's areas of operation would reduce their ability to make distributions.

        The Partnership's gathering systems are connected to natural gas reserves and wells, from which the production will naturally decline over time, which means that the cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on the partnership's gathering systems and the utilization rate at its processing plants and it's treating and fractionation facilities, they must continually obtain new natural gas supplies. The Partnership's ability to obtain additional sources of natural gas depends in part on the level of successful drilling activity near its gathering systems.

        The Partnership has no control over the level of drilling activity in the areas of its operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, they 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 regulations and the availability and cost of capital. 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. Natural gas prices reached historic highs in 2005 and early 2006 but have declined in the second half of 2006. These recent declines in natural gas prices are beginning to have a negative impact on production activity, and if sustained, could lead to a material decrease in such production activity and ultimately to exploration activity.

        Because of these factors, even if new natural gas reserves are discovered in areas served by the Partnership's assets, producers may choose not to develop those reserves. If the Partnership is not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells due to reductions in drilling activity or competition, throughput on its pipelines and the utilization rates of its treating and processing facilities would decline, which could have a material adverse effect on its business, results of operations, financial condition and ability to make cash distributions.

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

        We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us.

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

27

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.

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

        We are subject to significant risks associated with frequent and often substantial fluctuations in commodity prices. In the past, the prices of natural gas and NGLs have been volatile, and we expect this volatility to continue. The NYMEX daily settlement price of natural gas for the prompt month contract in 2005 ranged from a high of $15.38 per MMBtu to a low of $5.79 per MMBtu in 2005. In 2006, the same index ranged from a high of $12.48 per MMBtu to a low of $4.20 per MMBtu. A composite of the weighted monthly average NGLs price at our Appalachian facilities based on our average NGLs composition in 2005 ranged from a high of approximately $1.25 per gallon to a low of $0.83 per gallon. In 2006, the same composite ranged from approximately $1.27 per gallon to approximately $1.03 per gallon. The markets and prices for natural gas and NGLs depend upon factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:

•

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

28

•

demand for natural gas and NGL products in localized markets;



•

imports of crude oil, natural gas and NGLs;



•

seasonality;



•

the condition of the U.S. economy;



•

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



•

domestic government regulation, legislation and policies.

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

We have found a material weakness in our internal controls that requires remediation and concluded, pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, that our internal controls over financial reporting at December 31, 2006, 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/A, we have discovered deficiencies, including a material weakness, in our internal controls over financial reporting as of December 31, 2006. In particular, we identified the presence of, the following material weakness:

        There was an issue related to our prior year material weakness that had not been fully remediated at year-end. As of year-end, management did not have a process in place for monitoring previously existing contracts for certain technical accounting issues such as accounting for derivatives and revenue recognition and had not conducted a comprehensive review of all significant contracts entered into prior to 2006 for the purpose of ensuring that determinations about derivatives and revenue recognition issues were made appropriately and remained appropriate. A comprehensive review was deemed necessary because the determinations related to these historical contracts were originally made in an environment where material weaknesses are known to have existed.

        The full impact of our efforts to remediate the identified material weaknesses had not been realized as of December 31, 2006 and may not be sufficient to maintain effective internal controls in the future. We may not be able to implement and maintain adequate controls over our financial processes and reporting, which may require us to restate our financial statements in the future. In addition, we may discover additional past, ongoing or future material weaknesses or significant deficiencies in our financial reporting system in the future. Any failure to implement new controls, or difficulty encountered in their implementation, could cause us to fail to meet our reporting obligations or result in material misstatements in our financial statements. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could result in a lower trading price of our common units.

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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 are subject to rate and service regulations under FERC or various state regulatory bodies, depending upon jurisdiction. FERC generally regulates the transportation of natural gas and oil in interstate commerce, and FERC's regulatory authority includes: facilities construction, acquisition, extension or abandonment of services or facilities; accounts and records; and depreciation and amortization policies. Intrastate natural gas pipeline operations and transportation on proprietary natural gas or petroleum products pipelines 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 the Partnership's rates and terms and conditions of service provide no more than a fair return on the aggregate value of the facilities used to render services. The Partnership cannot assure their unitholders that FERC will not at some point determine that such gathering and transportation services are within its jurisdiction, and regulate such services. FERC rate cases can involve complex and expensive proceedings. For more information regarding regulatory matters that could affect our business, see Item 1. Business—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 and distributions to its unitholders 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.

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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, see Item 1 Business—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

31

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 15% 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 income tax on its earnings at the corporate tax rate, which is currently a maximum of 35%, plus any applicable state rates. 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. If MarkWest Energy Partners was taxed 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

32

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.

Our business may suffer if any of our key senior executives discontinues employment with us or if we are unable to recruit and retain highly skilled accounting and finance staff.

        Our future success depends to a large extent on the services of our key corporate employees. Our business depends on our continuing ability to recruit, train and retain highly qualified employees, particularly accounting, finance and other key back-office and mid-office personnel. The competition for these employees is intense, and the loss of these employees could harm our business. Further, our ability to successfully integrate acquired companies depends in part on our ability to retain key management and existing employees at the time of the acquisition.

As a result of damage caused by Hurricanes Katrina and Rita in the Gulf of Mexico and Gulf Coast regions in 2005, insurance costs related to oil and gas assets in these regions have increased significantly. We may be unable to obtain insurance on our interest in Starfish at rates we consider reasonable.

        During 2005, Hurricanes Katrina and Rita caused severe and widespread damage to oil and gas assets in the Gulf of Mexico and Gulf Coast regions. The loss to both offshore and onshore assets resulting from the hurricanes has led to substantial insurance claims within the oil and gas industry. Along with other industry participants, insurance costs have increased within this region as a result of these developments. In the future, we may be unable to obtain adequate insurance on our interest in Starfish at rates we consider reasonable and as a result may experience losses that are not insured or that exceed the maximum limits under our insurance policies. If a significant negative event that is not fully insured occurs with respect to Starfish, it could materially and adversely affect our financial condition and results of operations.

Item 1B. Unresolved Staff Comments

        None.

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Item 2. Properties

MarkWest Hydrocarbon Standalone

        As of December 31, 2006, MarkWest Hydrocarbon Standalone did not own any materially important physical properties.

MarkWest Energy Partners' Properties

Gas Processing Facilities

        The locations and approximate throughput capacity of MarkWest Energy Partners' gas processing facilities as of and for the year ended December 31, 2006, are as follows:

(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.

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Fractionation Facility

        The location, approximate capacity, and throughput of MarkWest Energy Partners' fractionation facility as of and for the year ended December 31, 2006, is as follows:

Natural Gas Gathering Systems and Pipelines

        The name, approximate length in miles, geographical location, and throughput of MarkWest Energy Partners' natural gas pipelines as of and for the year ended December 31, 2006, are as follows:

(4)

MarkWest Energy Partners acquired the Grimes gathering system as part of its December 29, 2006 Santa Fe acquisition.

(5)

In late 2006 the Partnership began the construction and operation of the Woodford gathering system and compression system in a four-county region in the Arkoma Basin in eastern Oklahoma. On December 1, 2006, the Partnership began gathering gas on that system. The volume reported is the average daily rate for the month of December.

(6)

MarkWest Energy Partners acquired the Appleby gathering system, along with 20 other gathering systems, as part of its March 28, 2003 Pinnacle acquisition.

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NGL Pipelines

        The name, approximate length in miles, geographical location, and throughput of MarkWest Energy Partners' NGL pipelines as of and for the year ended December 31, 2006, are as follows:

(7)

Represents a leased pipeline, of which the 40 miles extending from Ranger to Institute is currently unused.

(8)

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.

Crude Oil Pipeline

        The name, approximate length in miles, geographical location, and throughput of MarkWest Energy Partners' crude oil pipeline as of and for the year ended December 31, 2006, is as follows:

Title to Properties

MarkWest Hydrocarbon Standalone

        MarkWest Hydrocarbon Standalone believes that it has satisfactory title to all of its assets.

MarkWest Energy Partners

        Substantially all of the Partnership's pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. The Partnership has obtained, where determined necessary, permits, leases, license agreements and franchise ordinances from public authorities to cross over or under, or to lay facilities in or along water courses, county roads, municipal streets and state highways, as applicable. The Partnership has also obtained easements and license agreements from railroad companies to cross over or under railroad properties or rights-of-way. Many of these authorizations and grants are revocable at the election of the grantor. In some cases, property on which the Partnership's pipelines were built was purchased in fee

36

or held under long-term leases. The Partnership's Siloam fractionation plant and Kenova processing plant are on land that it owns in fee.

        Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that were transferred to the Partnership required the consent of the then-current landowner to transfer these rights, which in some instances was a governmental entity. The Partnership believes that they have obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for it to operate its business. The Partnership also believes they have satisfactory title or other right to all of its material land assets. Title to these properties is subject to encumbrances in some cases; however, the Partnership believes that none of these burdens will materially detract from the value of these properties or from its interests in these properties, or will materially interfere with their use in the operation of its business.

        The Partnership has pledged substantially all of its assets to secure the debt of its subsidiary, MarkWest Energy Operating Company, L.L.C. (the "Operating Company"), as discussed in Note 12 of the accompanying consolidated financial statements.

Item 3. Legal Proceedings

        In the ordinary course of its business the Company is subject to a variety of risks and disputes normal to its business and as a party to various legal proceedings. We maintain insurance policies 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 future claims for property loss or business interruption to the Company; or for third-party claims of personal and property damage; or that the coverages or levels of insurance it currently has will be available in the future at economical prices.

        In 2005 MarkWest Hydrocarbon, the Partnership, several of its affiliates, and an unrelated co-defendant, were served with three lawsuits, which in 2006 were consolidated into a single action captioned Ricky J. Conn, et al. v. MarkWest Hydrocarbon, Inc. et al., Floyd Circuit Court, Commonwealth of Kentucky, and Civil Action No. 05-CI-00137 (consolidated March 27, 2006 of three cases originally filed February, 2005). These actions involved 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 in Ivel Kentucky. The pipeline was owned by an unrelated business entity, Equitable Production Company, and leased and operated by the Partnership's subsidiary, MEA. MEA transports NGLs from the Maytown gas processing plant to MEA's Siloam fractionator. The explosion and fire from the leaked vapors resulted in property damage to several residential structures and injuries to some of the residents.

        The Company notified its general liability insurance carriers of the incident and the lawsuits in a timely manner and coordinated its legal defense with the insurers. As of February 1, 2007, all of the claims in the litigation were fully settled, with MarkWest's insurance carrier and its co-defendant and its separate insurance carrier, funding the settlements.

        In June 2006, a Notice of Probable Violation and Proposed Civil Penalty (NOPV) (CPF No. 2-2006-5001) was issued by OPS to both MarkWest Hydrocarbon and Equitable Production Company, the owner of the pipeline, asserting six counts of violations of applicable regulations, and a proposed civil penalty in the aggregate amount of $1,070,000. An administrative hearing on the matter is presently set for the last week of March, 2007. One of the counts of violations, which count involves $825,000 of the $1,070,000 proposed penalty, concerns alleged activity in 1982 and 1987, which dates predate MarkWest's leasing and operation of the pipeline. MarkWest believes it has viable defenses to the remaining counts and will vigorously defend all applicable assertions of violations at the hearing.

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        Related to the above referenced pipeline incident, MarkWest Hydrocarbon and the Partnership have 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 related to the pipeline incident. These include the Company's internal expenses and costs incurred for damage to, and loss of use of the pipeline, equipment and 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 it is received. Following initial discovery, the Company was granted leave of the Court to amend its complaint to add a bad faith claim, and a claim for punitive damages. The Company has not provided for a receivable for any of the claims in this action because of the uncertainty as to whether and how much the Company will ultimately recover under the policies. Discovery in the action is continuing. 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 just recently learned that a default judgment had been entered against it in May of 2006, in an action entitled Runyan v. Eclipse Realty LLC et al, (Arapahoe County District Court, Colorado, Case No. 06CV1054, filed February 2006). The Company was not aware of having ever received a summons and was not given any notification of a motion for default judgment. The Company is still investigating whether there ever was proper service of process. The action involves a personal injury claim by an individual who allegedly slipped and fell due to snowy conditions while approaching the office building in which the Company was one of several tenants. Eclipse Realty, the landlord of the building, was responsible for the maintenance and upkeep of the common areas of the office building. The Company is seeking to have the default judgment vacated, and then having the Company dismissed as an improper party to the action. The Company also has a contractual indemnification from Eclipse Realty, the landlord of the building, and we have demanded that Eclipse Realty defend and indemnify the Company. We are unable to predict the outcome of our motion to vacate the default judgment or our indemnification claim, but the Company does not expect at this time that the matter should have a material adverse effect on our financial position.

        The Partnership received notice from one of its customers of a potential gas measurement discrepancy and invoice errors, claiming it is owed several hundred thousand MMBtus as a result. The Partnership generally disputes the claims under the facts and under the terms of the contract with the customer, but is in discussions with the customer to evaluate and resolve all issues, and it appears at this time that this claim should not have a material adverse impact on the Partnership or us.

        With regard to the Partnership's Javelina facility, MarkWest Javelina is a party with numerous other defendants to several lawsuits brought by various plaintiffs who had residences or businesses located near the Corpus Christi industrial area, an area which included the Javelina gas processing plant, and several petroleum, petrochemical and metal processing and refining operations. These suits, Victor Huff v. ASARCO Incorporated, et al. (Cause No. 98-01057-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in March 3, 1998); Hipolito Gonzales et al. v. ASARCO Incorporated, et al., (Cause No. 98-1055-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in 1998); Jason and Dianne Gutierrez, individually and as representative of the estate of Sarina Galan Gutierrez (Cause No. 05-2470-A, 28^th Judicial District, severed May 18, 2005, from the Gonzales case cited above); and Esmerejilda G. Valasquez, et al. v. Occidental Chemical Corp., et al.,

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Case No. A-060352-C, 128^thJudicial District, Orange County, Texas, original petition filed July 10, 2006; as refiled from previously dismissed petition captioned Jesus Villarreal v. Koch Refining Co. et al., Cause No. 05-01977-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, originally filed April 27, 2005), set forth claims for wrongful death, personal injury or property damage, harm to business operations and nuisance type claims, allegedly incurred as a result of operations and emissions from the various industrial operations in the area or from products Defendants allegedly manufactured, processed, used, or distributed. The Gonzales action was settled in early 2006 pursuant to a mediation held December 9, 2005. The other actions have been and are being vigorously defended and, based on initial evaluation and consultations; it appears at this time that these actions should not have a material adverse impact on the Partnership or us.

        In the ordinary course of business, the Company is a party to various other legal actions. While it is not possible to predict the outcome of the legal actions with certainty, management is of the opinion that appropriate provision and accruals for potential losses associated with all legal actions have been made in the financial statements. In the opinion of management, none of these actions, either individually or in the aggregate, will have a material adverse effect on the Company's financial condition, liquidity or results of operations.

Item 4. Submission of Matters to a Vote of Security Holders

        No matters were submitted to a vote in the fourth quarter of 2006.

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PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

        Our common stock trades on the American Stock Exchange ("AMEX") national market under the symbol "MWP." As of February 15, 2007, there were 11,992,520 shares of common stock outstanding held by 83 holders of record. The following table sets forth quarterly high and low sales prices as reported by the American Stock Exchange as well as the amount of cash dividends paid per share per quarter for 2006 and 2005. All numbers have been retroactively restated to give effect to the May 2006 stock dividend.

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.

Stock Dividend

        On April 27, 2006, MarkWest Hydrocarbon announced that its Board of Directors approved the issuance of one share of common stock for each ten shares of common stock held by common stockholders. The stock was issued on May 23, 2006, to the stockholders of record as of the close of business on May 11, 2006; the ex-dividend date was May 9, 2006.

Securities Authorized for Issuance under Equity Compensation Plans

        The following table provides information as of December 31, 2006, about the shares of our common stock and units of the Partnership that may be issued upon the exercise of options, warrants and rights under all of the Company's existing equity compensation plans.

        All previously awarded MarkWest Hydrocarbon restricted stock, stock options and other compensation arrangements based on the market value of our common stock have been adjusted to reflect the May 2006 stock dividend. Furthermore, all previously awarded Partnership units have been

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adjusted to reflect the February 2007 two-for-one unit split (see Note 2 to the consolidated financial statements):

(1)

Restricted stock and units are granted with no exercise or conversion price.

Item 6. Selected Financial Data

        The following table sets forth selected consolidated historical financial and operating data for MarkWest Hydrocarbon. We have derived the summary selected historical financial data from our consolidated financial statements and related notes. Certain amounts below have been restated to reflect the Partnership's conclusion that certain types of revenue transactions were incorrectly accounted for net as an agent and should have been recorded in a gross presentation in the Partnership's East Texas segment. Refer to Note 24 to the accompanying consolidated financial statements included in Item 8 of this Form 10-K/A for a more detailed explanation of the financial statement restatements. All earnings per share and dividend information have been updated to reflect the May 2006 stock dividend. The selected financial data should be read in conjunction with the

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consolidated financial statements, including the notes thereto, and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation.

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(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).

(4)

See Note 24 to consolidated financial statements included in Item 8 of this Form 10-K/A.

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Operating Data