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MarkWest Energy Partners, LP 10-K 2007

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Table of Contents
ITEM 8. Financial Statements and Supplementary Data
Starfish Pipeline Company, LLC Index December 31, 2006 and 2005



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


FORM 10-K/A
(Amendment No. 3)

ý   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006.

or

o

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

for the transition period from                        to                         .

Commission File Number 001-31239


MARKWEST ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)

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

1515 Arapahoe Street, Tower 2, Suite 700, Denver, CO 80202-2126
(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 Units, $0.01 par value, American Stock Exchange

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

        Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No o

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

        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 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 Common Units held by non-affiliates of the registrant on June 30, 2006 was approximately $556,894,000.

        As of March 1, 2007, the number of the registrant's Common Units and Subordinated Units were 31,206,514 and 1,200,000, respectively.

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. 3 on Form 10-K/A amends the Annual Report on Form 10-K originally filed by MarkWest Energy Partners, LP (the "Partnership") on March 6, 2007 for the year ended December 31, 2006 (the "original report") to restate the Partnership's previously issued consolidated financial statements.

        The Partnership has determined that previously issued 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 our East Texas segment which were accounted for net as an agent. The Partnership has determined in these arrangements it acted as the principal and therefore the revenue should have been reported gross. The Partnership is filing contemporaneously with this Form 10-K/A for the year ended December 31, 2006, 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 23, 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 the Partnership 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 Partnership 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 Partnership filings made with the Securities and Exchange Commission subsequent to the filing of the original report, including any amendments of those filings.

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

Table of Contents

PART I
  Item 1.   Business
  Item 1A.   Risk Factors
  Item 1B.   Unresolved Staff Comments
  Item 2.   Properties
  Item 3.   Legal Proceedings
  Item 4.   Submission of Matters to a Vote of Security Holders

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

PART III
  Item 10.   Directors, Executive Officers and Corporate Governance
  Item 11.   Executive Compensation
  Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
  Item 13.   Certain Relationships and Related Transactions, and Director Independence
  Item 14.   Principal Accountant Fees and Services

PART IV
  Item 15.   Exhibits and Financial Statement Schedules

SIGNATURES

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

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Glossary of Terms

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

Bbls   barrels
Bbl/d   barrels per day
Bcf   one billion cubic feet of natural gas
Btu   one British thermal unit, an energy measurement
Gal/d   gallons per day
Mcf   one thousand cubic feet of natural gas
Mcf/d   one thousand cubic feet of natural gas per day
MMBtu   one million British thermal units, an energy measurement
MMcf   one million cubic feet of natural gas
MMcf/d   one million cubic feet of natural gas per day
MTBE   methyl tertieary butyl ether
Net operating margin (a non-GAAP financial measure)   revenues less purchased product costs
NGLs   natural gas liquids, such as propane, butanes and natural gasoline
NA   not applicable
Tcf   one trillion cubic feet of natural gas

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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 "could," "may," "will," "should," "expect," "plan," "project," "anticipate," "believe," "estimate," "intend" and similar expressions to identify forward-looking statements.

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

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

    our ability to successfully integrate our recent or future acquisitions;

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

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

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

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

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

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

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

    competition from other NGL processors, including major energy companies;

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

    our ability to identify and consummate grass roots projects or acquisitions complementary to our business;

    the success of our risk management policies;

    continued creditworthiness of, and performance by, contract counterparties;

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

    the impact of any failure of our information technology systems;

    the impact of current and future laws and government regulations;

    liability for environmental claims;

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

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

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

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

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PART I

ITEM 1.    Business

General

        MarkWest Energy Partners, L.P. is a publicly traded Delaware limited partnership formed by MarkWest Hydrocarbon, Inc. on January 25, 2002, to acquire most of the assets, liabilities and operations of the MarkWest Hydrocarbon Midstream Business. The MarkWest Hydrocarbon Midstream Business included natural gas gathering and processing assets and NGL transportation, fractionation and storage assets. We are a master limited partnership engaged in the gathering, transportation and processing of natural gas; the transportation, fractionation and storage of NGLs; and the gathering and transportation of crude oil. We are the largest processor of natural gas in the Appalachia region. We also have a large natural gas gathering and transmission business in the southwestern United States, built primarily through acquisitions and investments: Pinnacle Natural Gas, the Lubbock transmission pipeline and the Foss Lake gathering system, all in 2003; the Carthage gas processing plant in East Texas in July 2004; a non-controlling, 50% interest in Starfish Pipeline Company, LLC ("Starfish") and the Javelina entities' natural gas processing and fractionation facility and pipeline in Corpus Christi, Texas, both in 2005; the initial construction of the Woodford gathering system in the Arkoma Basin of southeastern Oklahoma, and the acquisition of the Grimes gathering system in western Oklahoma, both in 2006.

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

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

    Southwest Business Unit

    East Texas.  We own the East Texas System, consisting of natural gas gathering system pipelines, centralized compressor stations, and a natural gas processing facility and NGL pipeline. The East Texas System is located in Panola, Harrison and Rusk Counties and services the Carthage Field, one of Texas' largest onshore natural gas fields. Producing formations in Panola County consist of the Cotton Valley, Pettit and Travis Peak formations, which together form one of the largest natural gas producing regions in the United States. The East Texas segment has one customer, Targa Resources Partners, L.P., which makes up a significant portion of its segment revenues as well as 13% of the Partnership's consolidated revenue in 2006.

    Oklahoma.  We own 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. We also own a gathering system in the Woodford Shale play in the Arkoma Basin of southeastern Oklahoma, and we own the Grimes gathering system, which is located in Roger Mills and Beckham counties in western Oklahoma. The Oklahoma segment has two customers which account for a significant portion of its segment revenue. Of the two significant customers to the segment, only ONEOK, which accounts for 11% of the segment's consolidated revenue in 2006, was material to the Partnership.

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    Other Southwest.  We own a number of natural gas-gathering systems located in Texas, Louisiana, Mississippi and New Mexico, including the Appleby gathering system in the City and County of Nacogdoches, Texas. In addition, we own four lateral pipelines in Texas and New Mexico. The Other Southwest segment does not have any customers which are considered to be significant to their segment.

    Northeast Business Unit

    Appalachia.  We are the largest processor of natural gas in the Appalachian Basin with fully integrated processing, fractionation, storage and marketing operations. Our Appalachian assets include the Kenova, Boldman, Maytown, Cobb and Kermit natural gas-processing plants, an NGL pipeline, an NGL fractionation plant and two caverns for storing propane. The Appalachia segment has one customer which accounts for a significant portion of its segment revenue but does not account for a significant portion of the Partnership's consolidated revenue.

    Michigan.  We own and operate a crude oil pipeline in Michigan, which we refer to as the Michigan Crude Pipeline. The Michigan Crude Pipeline is subject to regulation by the Federal Energy Regulatory Commission ("FERC"). We also own a natural gas-gathering system and the Fisk processing plant in Manistee County, Michigan. The Michigan segment does not have any customers which are considered to be significant to their segment revenue.

    Gulf Coast Business Unit

    Javelina.  We own and operate the Javelina Processing Facility, a natural gas processing facility in Corpus Christi, Texas, which processes off-gas from six local refineries. The facility processes approximately 125 to 130 MMcf/d of inlet gas, but is expected to process up to its capacity of 142 MMcf/d as refinery output continues to grow. The Javelina segment has five customers which account for a significant portion of its segment revenue but do not account for a significant portion of the Partnership's consolidated revenue.

    Starfish.  We own a 50% non-operating membership interest in Starfish, 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 (losses) from unconsolidated affiliates and are not included in the Gulf Coast Business Unit results.


Industry Overview, Competition

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

ART

        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

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network of small diameter pipelines and, if necessary, compression systems, that collect natural gas from points near producing wells, and transport it to larger pipelines for further transmission.

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

        Most natural gas produced at the wellhead is not suitable for long-haul pipeline transportation or commercial use. It must be gathered, compressed and transported via pipeline to a central facility, and then processed to remove the heavier hydrocarbon components and other contaminants that interfere with pipeline transportation or the end-use of the gas. Our business includes providing these services either for a fee or a percentage of the NGLs removed or gas units processed. The industry as a whole is characterized by regional competition, based on the proximity of gathering systems and processing plants to producing natural gas wells, or to facilities that produce natural gas as a byproduct of refining crude oil.

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

ART

        Natural gas processing and treating involves the separation of raw natural gas into pipeline-quality natural gas, principally methane, and NGLs, as well as the removal of contaminants. Raw natural gas from the wellhead is gathered at a processing plant, typically located near the production area, where it is dehydrated and treated, and then processed to recover a mixed NGL stream. In the case of our Javelina facilities, the natural gas delivered to our processing plant is a byproduct of the crude oil refining process.

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

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

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

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

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

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

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

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

        Our competitors include:

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

    major integrated oil companies;

    medium and large sized independent exploration and production companies;

    major interstate and intrastate pipelines; and

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

        Many of our competitors operate as master limited partnerships and enjoy a cost of capital comparable to and, in some cases, lower than ours. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours. Smaller local distributors may enjoy a marketing advantage in their immediate service areas.

        We believe our competitive strengths include:

    Strategic and growing position with high-quality assets in the Southwest and the Gulf Coast.  Our acquisitions and internal growth projects have allowed us to establish and expand our presence in several long-lived natural gas supply basins in the Southwest, particularly in Texas, Oklahoma and the Gulf Coast. In 2006, we expanded this strategy through our Newfield agreement by building the largest gathering system to date in the newly emerging Woodford Shale play in southeastern Oklahoma. All of our major acquisitions in these regions have been characterized by several common critical success factors that include:

    an existing strong competitive position;

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

      ample opportunities for long-term continued organic growth;

      ready access to markets; and

      close proximity to other acquisition or expansion opportunities.

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

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

    Stable cash flows.  We believe our numerous fee-based contracts and our active commodity risk management program provide us with stable cash flows. For the year ended December 31, 2006, we generated approximately 32% of our net operating margin (a non-GAAP financial measure, see Item 1. Business—Our Contracts) from fee-based services. Net operating margin depends on throughput volume, but is typically not affected by short-term changes in commodity prices. In addition, a portion of our fee-based business is generated by our four lateral pipelines in the Southwest, which typically provide fixed transportation fees independent of the volumes transported. We also believe that an active commodity risk management program is a significant component of providing stable cash flows as our commodity exposure grows with our expanding operations.

    Common carrier crude oil pipeline in Michigan.  We own a common carrier crude oil gathering pipeline in Michigan. Our pipeline receives oil directly from in-state well production and is connected to Enbridge pipeline for transportation to interstate destinations. We enjoy a competitive advantage over higher cost crude oil transportation alternatives such as trucking. Most of the crude oil we transport in the state is produced from the Niagaran Reef Trend, which is generally characterized by long-lived crude oil reserves.

    Long-term Contracts.  We believe our long-term contracts, which we define as contracts with remaining terms of four years or more, lend greater stability to our cash-flow profile. For the year ended December 31, 2006, approximately 67% of our inlet volumes were tied to long-term contracts. In East Texas, approximately 80% of our current gathering volumes as of December 31, 2006, are under contract for longer than five years. Two of our Pinnacle lateral pipelines operate under fixed-fee contracts for the transmission of natural gas that expire in approximately 16 and 24 years, respectively. Approximately 26% of our daily throughput in the Foss Lake gathering system and Arapaho processing plant in western Oklahoma is subject to

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      contracts with remaining terms of five years or more. In Appalachia, we have natural gas processing and NGL fractionation contracts with remaining terms from 5 to 11 years. In Michigan, our natural gas transportation, treating and processing agreements have remaining terms of 10 to 22 years.

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

    Financial strength and flexibility.  During 2006, we issued approximately $126.0 million of equity. Our goal is to maintain a capital structure with approximately equal amounts of debt and equity on a long-term basis.

        As of December 31, 2006, we have available borrowing capacity of approximately $218.4 million under our $250.0 million revolving credit facility. This amount is determined on a quarterly basis and is further adjusted to take into consideration the cash flow contribution of an acquisition at the time of its closing. The credit facility, together with our ability to issue additional partnership units for financing and acquisition purposes, should provide us with a flexible financial structure that will facilitate the execution of our business strategy.

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

    Increasing utilization of our facilities.  We hope to add to, or provide additional services to, our existing customers, and to provide services to other natural gas and crude oil producers in our areas of operation. Increased drilling activity in our core areas of operation, particularly within certain fields in the Southwest, should also produce increasing natural gas and crude oil supplies, and a corresponding increase in utilization of our transportation, gathering, processing and fractionation facilities. In the meantime, we continue to develop additional capacity at several of our facilities, which enables us to increase throughput with minimal incremental costs.

    Expanding operations through internal growth projects.  By expanding our existing infrastructure and customer relationships, we intend to continue growing in our primary areas of operation to meet the anticipated need for additional midstream services. During 2006, we spent approximately $75.1 million of growth capital to expand several of our gathering and processing operations. Projects included the initial construction of the Woodford gathering system in the Arkoma Basin in eastern Oklahoma, ongoing compressor expansions in East Texas, and well connection expansion projects in the Southwest Business Unit.

    Expanding operations through strategic acquisitions.  We intend to continue pursuing strategic acquisitions of assets and businesses in our existing areas of operation that leverage our current asset base, personnel and customer relationships. We will also seek to acquire assets in certain regions outside of our current areas of operation.

    Securing additional long-term, fee-based contracts.  We intend to continue to secure long-term, fee-based contracts in both our existing operations and strategic acquisitions, in order to further minimize our exposure to short-term changes in commodity prices.

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

        To better understand our business and the results of operations discussed in Item 6, "Selected Financial Data" and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operation," the following three factors are important to consider:

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

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

    the nature of our relationship with MarkWest Hydrocarbon, Inc.

Our Contracts

        We generate the majority of our revenues and net operating margin (a non-GAAP measure, see below for discussion and reconciliation of net operating margin) from natural gas gathering, processing and transmission; NGL transportation, fractionation and storage; and crude oil gathering and transportation. We enter into a variety of contract types. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described below. We provide services under the following different types of arrangements (all of which constitute midstream energy operations):

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

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

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

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    Keep-whole arrangements:  Under keep-whole arrangements, we gather natural gas from the producer, process the natural gas and sell 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, we 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 our revenues and net operating margins increase as the price of condensate and NGLs increases relative to the price of natural gas, and decrease as the price of natural gas increases relative to the price of condensate and NGLs.

    Settlement margin:  Typically, we are allowed to retain a fixed percentage of the volume gathered to cover the compression fuel charges and deemed-line losses. To the extent our gathering systems are operated more efficiently than specified per contract allowance, we are entitled to retain the difference for our own account.

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

        As of December 31, 2006, our primary exposure to keep-whole contracts was limited to our Arapaho (Oklahoma) processing plant and our East Texas processing contracts. At the Arapaho plant inlet, the Btu content of the natural gas meets the downstream pipeline specification; however, we have the option of extracting NGLs when the processing margin environment is favorable. In addition, approximately 25% (as measured in volumes) of the related gas gathering contracts include additional fees to cover plant operating costs, fuel costs and shrinkage costs in a low-processing margin environment. Due to our ability to operate the Arapaho plant in several recovery modes, our overall keep-whole contract exposure is limited to a small portion of the operating costs of the plant.

        Approximately 18% of the gas processed in East Texas for producers was processed under keep-whole terms. Our keep-whole exposure in this area was offset to a great extent because the East Texas agreements provide for the retention of natural gas as a part of the gathering and compression arrangements with all producers on the system. This excess gas helps offset the amount of replacement natural gas purchases required to keep our producers whole on an MMbtu basis, thereby creating a partial natural hedge. The net result is a significant reduction in volatility for these changes in natural gas prices. The remaining volatility for these contracts results from changes in NGL prices. The Partnership has an active commodity risk management program in place to reduce the impacts of changing NGL prices.

        Management evaluates contract performance on the basis of net operating margin (a non-GAAP financial measure), which is defined as income (loss) from operations, excluding facility expense, 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 in excluding certain charges is not necessarily an indication of the results of operations expected in the future, or that we will not, in fact, incur such charges in future periods.

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        The following is a reconciliation to the most comparable GAAP financial measure of this non-GAAP financial measure (in thousands):

 
  Year ended December 31,
 
  2006
  2005
  2004
Revenues   $ 629,911   $ 541,090   $ 319,119
Purchased product costs     376,237     408,884     229,339
   
 
 
Net operating margin     253,674     132,206     89,780
   
 
 
  Facility expenses     60,112     47,972     29,911
  Selling, general and administrative     44,185     21,573     16,133
  Depreciation     29,993     19,534     15,556
  Amortization of intangible     16,047     9,656     3,640
  Accretion of asset retirement obligation     102     159     13
  Impairments             130
   
 
 
Income from operations   $ 103,235   $ 33,312   $ 24,397
   
 
 

        For the year ended December 31, 2006, we calculated the following approximate percentages of our revenues and net operating margin from the following types of contracts:

 
  Fee-Based
  Percent-of-
Proceeds(1)

  Percent-of-
Index(2)

  Keep-Whole(3)
  Total
 
Revenues   13 % 31 % 39 % 17 % 100 %
Net operating margin   32 % 38 % 13 % 17 % 100 %

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

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

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

        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.

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Acquisitions

        Since our initial public offering, we have completed nine acquisitions for an aggregate purchase price of approximately $810 million, net of working capital. The following table sets forth information regarding each of these acquisitions:

Name

  Assets
  Location
  Consideration
  Closing Date
Santa Fe   Grimes gathering system   Oklahoma   $ 15.0   December 29, 2006

Javelina(1)

 

Gas processing and fractionation facility

 

Corpus Christi, TX

 

 

398.8

 

November 1, 2005

Starfish(2)

 

Natural gas pipeline, gathering system and dehydration facility

 

Gulf of Mexico/Southern Louisiana

 

 

41.7

 

March 31, 2005

East Texas

 

Gathering system and gas procession assets

 

East Texas

 

 

240.7

 

July 30, 2004

Hobbs

 

Natural gas pipeline

 

New Mexico

 

 

2.3

 

April 1, 2004

Michigan Crude Pipeline

 

Common carrier crude oil pipeline

 

Michigan

 

 

21.3

 

December 18, 2003

Western Oklahoma

 

Gathering system

 

Western Oklahoma

 

 

38.0

 

December 1, 2003

Lubbock Pipeline

 

Natural gas pipeline

 

West Texas

 

 

12.2

 

September 2, 2003

Pinnacle

 

Natural gas pipelines and gathering systems

 

East Texas

 

 

39.9

 

March 28, 2003

(1)
Consideration includes $35.5 million in cash.

(2)
Represents a 50% non-controlling interest.

        We were formed by MarkWest Hydrocarbon in 2002 to acquire most of its natural gas gathering and processing assets and NGL transportation, fractionation and storage assets. MarkWest Hydrocarbon remains one of our largest customers. We expect to continue deriving a portion of our revenues from the services we provide under our contracts with MarkWest Hydrocarbon; however, the percentage of our revenues and net operating margins will likely continue to decline as our other businesses grow. For the years ended December 31, 2006 and 2005, it accounted for 13% of our revenues. As of December 31, 2006, MarkWest Hydrocarbon and its subsidiaries, in the aggregate, owned a 17% interest in the Partnership, consisting of 1,200,000 subordinated units, 3,738,992 common units and a 2% general partner interest.

        Neither we nor our General Partner have any employees. However, under a Services Agreement entered into between our General Partner and MarkWest Hydrocarbon, Inc., MarkWest Hydrocarbon acts in a management capacity rendering day-to-day operational, business and asset management, accounting, information services, personnel and related administrative services to the Partnership. In return, the Partnership reimburses MarkWest Hydrocarbon for all documented expenses incurred on behalf of the Partnership and which are expressly designated as reasonably necessary for the performance of the prescribed duties and specified functions. General corporate expenses and costs that are not specifically linked to either MarkWest Hydrocarbon or us are allocated in accordance with an approved allocation methodology which is designed to ensure that neither entity bears a disproportionate or unfair burden of the other company's costs and expenses, and is reflective of

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respective income statements. Additionally, at the time of our IPO we entered into the following agreements with MarkWest Hydrocarbon:

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

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

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

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

    a Natural Gas Liquids Purchase Agreement which governs our obligations with respect to the sale and purchase of NGL products we acquire under the Gas-Processing (Maytown) Agreement between a third party producer and MarkWest Hydrocarbon, which were assigned to us, as well as any other NGL products we acquire.

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

Segment Reporting

        Segments.    As described below, we have six segments, based on geographic areas of operations. For further information, see "Management's Discussion and Analysis of Financial Condition and Results of Operations," included in Item 7 of this Form 10-K/A, and "Financial Statements and Supplementary Data," included in Item 8 of this report on Form 10-K/A.

    Southwest Business Unit

    East Texas.  We own the East Texas System, consisting of natural gas gathering system pipelines, centralized compressor stations, and a natural gas processing facility and NGL pipeline. The East Texas System is located in Panola, Harrison and Rusk Counties and services the Carthage Field, one of Texas' largest onshore natural gas fields. Producing formations in Panola County consist of the Cotton Valley, Pettit and Travis Peak formations, which together form one of the largest natural gas producing regions in the United States.

    Oklahoma.  We own 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. After processing, the residue gas is delivered to a third-party pipeline and natural gas liquids are sold to a single customer. We also own a gathering system in the Woodford Shale play in the Arkoma Basin of southeastern Oklahoma, and we own the Grimes gathering system, which is located in Roger Mills and Beckham counties in western Oklahoma.

    Other Southwest.  We own 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. We gather a significant portion of the gas produced from fields adjacent to our gathering systems. In many areas we are the primary gatherer, and in some of the areas served by our smaller systems we are the sole gatherer. We also own four lateral pipelines in Texas and New Mexico.

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    Northeast Business Unit

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

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

    Gulf Coast Business Unit

    Javelina.  On November 1, 2005, we acquired 100% of the equity interests in Javelina Company, Javelina Pipeline Company and Javelina Land Company, L.L.C., which were owned 40%, 40% and 20%, respectively, by subsidiaries of El Paso Corporation, Kerr-McGee Corporation, and Valero Energy Corporation. The Javelina entities own and operate a natural gas processing facility in Corpus Christi, Texas, which treats and processes off-gas from six local refineries. The facility was constructed to recover hydrogen and up to 28,000 barrels per day of NGLs, including olefins (ethylene and propylene), ethane, propane, mixed butane and pentanes. The facility processes approximately 125 to 130 MMcf/d of inlet gas and produces approximately 25,400 Bbl/d of NGLs.

        We own a 50% non-operating membership interest in Starfish, 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.

        The following summarizes the percentage of our revenue and net operating margin (a non-GAAP financial measure, see Item 1. Business—Our Contracts) generated by our assets, by geographic region, for the year ended December 31, 2006:

 
  East Texas
  Oklahoma
  Other
Southwest

  Appalachia
  Michigan
  Gulf Coast
  Total
 
Revenue   28 % 33 % 14 % 12 % 2 % 11 % 100 %
Net operating margin   33 % 15 % 7 % 13 % 4 % 28 % 100 %

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

        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

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crude oil pipeline facilities and related assets are subject to regulation by the FERC. Federal regulation extends to such matters as:

    rate structures;

    rates of return on equity;

    recovery of costs;

    the services that our regulated assets are permitted to perform;

    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 procompetitive 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 has 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 requirement and complaint-based rate regulation. 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.

        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

19


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.

        Our Appalachian pipeline carries NGLs across state lines. The primary shipper on the pipeline is MarkWest Hydrocarbon, which has entered into agreements with us providing for a fixed transportation charge for the term of the agreements. They expire on December 31, 2015. We are the only other shipper on the pipeline. We neither operate our Appalachian pipeline as a common carrier, nor hold it out for service to the public generally, there are currently no third-party shippers on this pipeline and the pipeline is, and will continue to be, operated as a proprietary facility. The likelihood of other entities seeking to utilize our Appalachian pipeline is remote, so it should not be subject to regulation by the FERC in the future. We cannot provide assurance, however, that FERC will not at some point determine that such transportation is within its jurisdiction, or that such an assertion would not adversely affect our results of operations. In such a case, we would be required to file a tariff with FERC and provide a cost justification for the transportation charge. Regardless of any FERC action, however, MarkWest Hydrocarbon has agreed to not challenge the status of our Appalachian pipeline or the transportation charge during the term of our agreements.

        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 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.

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Environmental Matters

        Our 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 our present and future operations, and generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals, with respect to air emissions, water quality, wastewater discharges, and solid and hazardous waste management. Failure to comply with these stringent and comprehensive requirements may expose us to fines, penalties and/or interruptions in our operations that could influence our results of operations.

        We believe that our 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 our results of operations or financial condition. We 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 us. 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 we currently anticipate. Revised or additional environmental requirements that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have material adverse effect on our business, financial condition, results of operations and cash flow.

        To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control environmental pollution of the environment. 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 we generate materials in the course of our operations that are regulated as hazardous substances, we have not received any notification that we may be potentially responsible for cleanup costs under CERCLA. We also may incur 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 nonhazardous solid wastes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes. However, it is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as "hazardous wastes," resulting in the wastes being subject to more rigorous and costly disposal requirements.

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        We currently own or lease, and have in the past owned or leased, properties that have been used over the years for natural gas gathering and processing, for NGL fractionation, transportation and storage and for the storage and gathering and transportation of crude oil. 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 us 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 our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination or to perform remedial operations to prevent future contamination. We do not believe that there presently exists significant surface and subsurface contamination of our properties by hydrocarbons or other solid wastes for which we are currently responsible.

        The previous owner/operator of our Boldman and Cobb facilities has been, or is currently involved in, investigatory or remedial activities with respect to the real property underlying these facilities. These arise out of a September 1994 "Administrative Order by Consent for Removal Actions" with EPA Regions II, III, IV, and V; and an "Agreed Order" entered into with the Kentucky Natural Resources and Environmental Protection Cabinet in October 1994. The previous owner/operator has accepted sole liability and responsibility for, and indemnifies MarkWest Hydrocarbon against, any environmental liabilities associated with the EPA Administrative Order, the Kentucky Agreed Order or any other environmental condition related to the real property prior to the effective dates of MarkWest Hydrocarbon's lease or purchase of the real property. In addition, the previous owner/operator has agreed to perform all the required response actions at its expense in a manner that minimizes interference with MarkWest Hydrocarbon's use of the properties. On May 24, 2002, MarkWest Hydrocarbon assigned to us the benefit of this indemnity from the previous owner/operator. To date, the previous owner/operator has been performing all actions required under these agreements and, accordingly, we do not believe that the remediation obligation of these properties will have a material adverse impact on our financial condition or results of operations.

        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 us 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 we 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, we do not believe that such requirements will have a material adverse affect on our operations.

        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. We believe that we are in substantial compliance with the Clean Water Act.

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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, and 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, 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.

        Our affiliate MarkWest Energy Appalachia, L.L.C. ("MEA") operates the Appalachia Liquids Pipeline System ("ALPS") pipeline to transport NGLs from our Maytown gas processing plant to our 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 appropriate 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.

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Employee Safety

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

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

Employees

        We do not have any employees. Our general partner, or its affiliates, employs approximately 318 individuals to operate our facilities and provide general and administrative services, as our agents. The Paper, Allied Industrial, Chemical and Energy Workers International Union Local 5-372 represents 14 employees at our Siloam fractionation facility in South Shore, Kentucky. The collective bargaining agreement with this union was renewed on July 11, 2005, for a term of three years. The agreement covers only hourly, non-supervisory employees. We consider labor relations to be satisfactory at this time.

Available Information

        Our principal executive office is located at 1515 Arapahoe Street, Tower 2, Suite 700, Denver, Colorado 80202-2126. Our telephone number is 303-925-9200. Our common units trade on the American Stock Exchange under the symbol "MWE." You can find more information about us at our Internet website, www.markwest.com. Our annual report on Form 10-K/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.

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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 Energy Partners.

Risks Inherent in Our Business

We may not have sufficient cash after the establishment of cash reserves and payment of our general partner's fees and expenses to enable us to pay distributions at the current level.

        The amount of cash we can distribute on our units depends principally on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

    the fees we charge and the margins we realize for our services and sales;

    the prices of, level of production of, and demand for natural gas and NGLs;

    the volumes of natural gas we gather, process and transport;

    the level of our operating costs, including reimbursement of fees and expenses of our general partner; and

    prevailing economic conditions.

        In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

    our debt service requirements;

    fluctuations in our working capital needs;

    our ability to borrow funds and access capital markets;

    restrictions contained in our debt agreements;

    the level of capital expenditures we make, including capital expenditures incurred in connection with our enhancement projects;

    the cost of acquisitions, if any; and

    the amount of cash reserves established by our general partner.

        Unitholders should be aware that the amount of cash we have available for distribution depends primarily on our cash flow and not solely on profitability, which is affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

If we do not make acquisitions on economically acceptable terms, our future growth will be limited.

        Our ability to grow depends in part on our ability to make acquisitions that result in an increase in the cash generated from operations per unit. If we are unable to make these accretive acquisitions because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms, or (3) outbid by competitors, then our future growth and ability to increase distributions will be limited.

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If we are unable to successfully integrate our future acquisitions, our future financial performance may suffer.

        Our future growth will depend in part on our ability to integrate our future acquisitions. We cannot guarantee that we will successfully integrate any acquisitions into our existing operations, or that we will achieve the desired profitability and anticipated results from such acquisitions. Failure to achieve such planned results could adversely affect our financial condition and results of operations.

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

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

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

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

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

    the failure to realize expected synergies and cost savings;

    coordinating geographically disparate organizations, systems and facilities;

    integrating personnel from diverse business backgrounds and organizational cultures; and

    consolidating corporate and administrative functions.

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

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

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

        One of the ways we intend to grow our business is through the construction of additions to our existing gathering systems and construction of new gathering, processing and treating facilities. The construction of gathering, processing and treating facilities requires the expenditure of significant amounts of capital, which may exceed our expectations, and involves numerous regulatory, environmental, political and legal uncertainties. If we undertake these projects, we may not be able to complete them on schedule or at all or at the budgeted cost. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until after completion of the project.

        Furthermore, we may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, we may construct facilities to capture anticipated future growth in

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production in a region in which anticipated production growth does not materialize. We may also rely on estimates of proved reserves in our decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new facilities may not be able to attract enough natural gas to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

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

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

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

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

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

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

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

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

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

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

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

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

        We have no control over the level of drilling activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental 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 our assets, producers may choose not to develop those reserves. If we are 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 our pipelines and the utilization rates of our treating and processing facilities would decline, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders.

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

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

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

        MarkWest Hydrocarbon accounts for a significant portion of our revenues and net operating margin. These revenues and margins are generated by the volumes of natural gas contractually committed to MarkWest Hydrocarbon by certain producers in the Appalachian region, as well as the fees generated from processing, transportation, fractionation and storage services provided to MarkWest Hydrocarbon. We expect to derive a significant portion of our revenues and net operating margin from the services we provide under our contracts with MarkWest Hydrocarbon for the foreseeable future. Any default or nonperformance by MarkWest Hydrocarbon could significantly

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reduce our revenues and cash flows. Thus, any factor or event adversely affecting MarkWest Hydrocarbon's business, creditworthiness or its ability to perform under its contracts with us, or its other contracts related to our business, could also adversely affect us.

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

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

We are exposed to the credit risks of our key customers, and any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders.

        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.

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

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

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

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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;

    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.

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. Please read "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—and Item 7A. Quantitative and Qualitative Disclosures about Market Risk" as set forth in this report. 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

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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. For further information about our risk management policies and procedures, please read "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation—and Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk and Our Risk Management Policy" as set forth in this report.

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.

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

        Some of our gas, liquids and crude oil transmission operations are subject to rate and service regulations under FERC or various state regulatory bodies, depending upon jurisdiction. FERC generally regulates the transportation of natural gas and oil in interstate commerce, and FERC's regulatory authority includes: facilities construction, acquisition, extension or abandonment of services or facilities; accounts and records; and depreciation and amortization policies. Intrastate natural gas pipeline operations 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 our rates and terms and conditions of service provide no more than a fair return on the aggregate value of the facilities used to render services. We cannot assure 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

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involve complex and expensive proceedings. For more information regarding regulatory matters that could affect our business, please read "Item 1. Business—Regulatory Matters" as set forth in this report.

If we are unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, then we may be unable to fully execute our growth strategy and our cash flows could be adversely affected.

        The construction of additions to our existing gathering assets may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of obtaining new rights-of-way or renewing existing rights-of-way increases, then our cash flows could be adversely affected.

We are indemnified for liabilities arising from an ongoing remediation of property on which our facilities are located and our results of operation and our ability to make payments of principal and interest on our debt and distributions to our 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 our Kenova, Boldman, Cobb and Kermit facilities are located and is the previous operator of our Boldman and Cobb facilities. Columbia Gas has been or is currently involved in investigatory or remedial activities with respect to the real property underlying the Boldman and Cobb facilities pursuant to an "Administrative Order by Consent for Removal Actions" entered into by Columbia Gas and the U.S. Environmental Protection Agency and, in the case of the Boldman facility, an "Agreed Order" with the Kentucky Natural Resources and Environmental Protection Cabinet.

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

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

        Numerous governmental agencies enforce comprehensive 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

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to comply with environmental or safety-related laws and regulations could result in administrative, civil and criminal penalties, the imposition of investigatory and remedial obligations and even injunctions that restrict or prohibit our operations. For more information regarding the environmental, safety and other regulatory matters that could affect our business, please read "Item 1. Business—Regulatory Matters," "Item 1. Business—Environmental Matters," and "Item 1. Business—Pipeline Safety Regulations" each as set forth in this report.

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

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

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

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

    unscheduled turnarounds or catastrophic events at our physical plants;

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

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

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

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

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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. We have renewed our insurance coverage relating to Starfish and mitigated a portion of the cost increase by reducing our coverage and broadening the self-insurance element of our overall coverage. 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.

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

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

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.

Risks Related to Our Partnership Structure

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

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

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

        MarkWest Hydrocarbon and its affiliates own and control our general partner. MarkWest Hydrocarbon and its affiliates also own a significant limited partner interest in us. A number of officers

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

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

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

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

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

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

    Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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

    Our Partnership Agreement gives our general partner broad discretion in establishing financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution.

    Our general partner may establish reserves for distribution on the subordinated units, but only if those reserves will not prevent us from distributing the full minimum quarterly distribution, plus any arrearages, on the common units for the following four quarters.

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

    Our general partner determines which costs incurred by MarkWest Hydrocarbon and its affiliates are reimbursable by us.

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

35


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

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

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

        Furthermore, if unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. First, our general partner generally may not be removed except upon the vote of the holders of at least 662/3% of the outstanding units voting together as a single class. Also, if our general partner is removed without cause during the subordination period, and units held by MarkWest Hydrocarbon and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units, and any existing arrearages on the common units will be extinguished. A removal under these circumstances would adversely affect the common unitholders by prematurely eliminating their contractual right to distributions over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

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

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

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

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

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

36



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

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

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

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

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

        During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 2,415,000 additional common units. Our general partner, without unitholder approval, may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, in several circumstances. These include:

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

    the conversion of subordinated units into common units;

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

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

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

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

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

    our unitholders' proportionate ownership interest in us will decrease;

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

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

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

    the market price of the common units may decline; and

37


    the ratio of taxable income to distributions may increase.

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

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

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

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

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

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

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

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by states. If the IRS were to treat us as a corporation or if we were to become subject to entity-level taxation for state tax purposes, then our cash flows would be substantially reduced.

        The anticipated after-tax benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

        If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash flows would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of the common units.

        Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the

38



imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, our cash flows would be reduced. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be reduced to reflect the impact of that law on us.


ITEM 1B.    Unresolved Staff Comments

        None.

39



ITEM 2.    Properties

Gas Processing Facilities:

        The locations, approximate capacity, and throughput of our gas-processing plants as of and for the year ended December 31, 2006, are as follows:

 
   
   
   
  Year ended December 31, 2006
Facility

  Location
  Year of
Initial
Construction

  Design
Throughput
Capacity

  Natural
Gas
Throughput

  Utilization
of Design
Capacity

  NGL
Throughput

 
   
   
  (Mcf/d)

  (Mcf/d)

   
  (Gal/d)

East Texas:                        
  East Texas processing plant   Panola County, TX   2005   200,000   161,300   81 % NA

Oklahoma:

 

 

 

 

 

 

 

 

 

 

 

 
  Arapaho processing plant   Custer County, OK   2000   90,000   87,500   97 % 217,000

Appalachia:

 

 

 

 

 

 

 

 

 

 

 

 
  Kenova processing plant(1)   Wayne County, WV   1996   160,000   133,000   83 % NA
  Boldman processing plant(1)   Pike County, KY   1991   70,000   41,000   59 % NA
  Maytown processing plant(1)   Floyd County, KY   2000   55,000   59,000   107 % NA
  Cobb processing plant   Kanawha County, WV   2005   25,000   28,000   112 % NA
  Kermit processing plant(1)(2)   Mingo County, WV   2001   32,000   NA   NA   NA

Michigan:

 

 

 

 

 

 

 

 

 

 

 

 
  Fisk processing plant   Manistee County, MI   1998   35,000   6,500   19 % 15,500

Gulf Coast:

 

 

 

 

 

 

 

 

 

 

 

 
  Javelina processing plant(3)   Corpus Christi, TX   1989   142,000   124,000   87 % 1,098,483

(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.

Fractionation Facility:

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

 
   
   
   
  Year ended December 31, 2006
 
Pipeline

  Location
  Year of
Initial
Construction

  Design
Throughput
Capacity (gal/d)

  NGL
Throughput
(gal/day)

  Utilization
of Design
Capacity

 
Appalachia:                      
  Siloam Fractionation Plant   South Shore, KY   1957   600,000   455,000   76 %

40


Natural Gas Pipelines:

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

 
   
   
   
   
  Year ended December 31, 2006
 
Facility

  Location
  Miles
  Year of
Initial
Construction

  Design
Throughput
Capacity

  Natural
Gas
Throughput

  Utilization
of Design
Capacity

 
 
   
   
   
  (Mcf/d)

  (Mcf/d)

   
 
East Texas:                          
  East Texas gathering system   Panola County, TX   311   1990   410,000   378,000   92 %

Oklahoma:

 

 

 

 

 

 

 

 

 

 

 

 

 
  Foss Lake gathering system   Roger Mills and Custer County, OK   240   1998   100,000   87,500   88 %
  Grimes gathering system(4)   Beckham, Roger Mills Counties, OK   25   2005   25,000   NA   NA  
  Woodford Shale gathering
system(5)
 
Hughes, Pittsburg and Coal Counties, OK
 
40
 
2006
 
45,000
 
34,000
 
76

%

Other Southwest:

 

 

 

 

 

 

 

 

 

 

 

 

 
  Appleby gathering system   Nacogdoches County, TX   139   1990   50,000   34,200   68 %
  Other gathering systems(6)   Various       Various   52,570   18,300   35 %

Michigan:

 

 

 

 

 

 

 

 

 

 

 

 

 
  90-mile gas gathering pipeline   Manistee, Mason and Oceana Counties, MI   90   1994-1998   35,000   6,500   19 %

(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.

41


NGL Pipelines:

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

 
   
   
   
   
  Year ended December 31, 2006
 
Pipeline

  Location
  Miles
  Year of
Initial
Construction

  Design
Throughput
Capacity

  NGL
Throughput

  Utilization
of Design
Capacity

 
 
   
   
   
  (Gal/d)

  (Gal/d)

   
 
Appalachia:                          
  Maytown to Institute(7)   Floyd County, KY to Kanawha County, WV   100   1956   250,000   132,000   53 %
  Ranger to Kenova(8)   Lincoln County, WV to Wayne County, WV   40   1976   831,000   132,000   16 %
  Kenova to Siloam   Wayne County, WV to South Shore, KY   40   1957   831,000   389,000   47 %

East Texas:

 

 

 

 

 

 

 

 

 

 

 

 

 
  East Texas liquidline   Panola County, Texas   37.5   2005   630,000   442,300   70 %

(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.

        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:

 
   
   
   
   
  Year ended December 31, 2006
 
Pipeline

  Location
  Miles
  Year of
Initial
Construction

  Design
Throughput
Capacity

  NGL
Throughput

  Utilization
of Design
Capacity

 
 
   
   
   
  (Gal/d)

  (Gal/d)

   
 
Michigan:                          
  Michigan crude pipeline   Manistee County, MI to Crawford County, MI   250   1973   60,000   14,500   24 %

Title to Properties

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

        Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that were transferred to us required the consent of the then-current landowner to transfer these rights, which in some instances was a governmental entity. We believe that we have obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our

42


business. We also believe we have satisfactory title or other right to all of our material land assets. Title to these properties is subject to encumbrances in some cases; however, we believe that none of these burdens will materially detract from the value of these properties or from our interest in these properties, or will materially interfere with their use in the operation of our business.

        We have pledged substantially all of our assets to secure the debt of our subsidiary, MarkWest Energy Operating Company, L.L.C. (the "Operating Company"), as discussed in Note 11 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K/A.


ITEM 3.    Legal Proceedings

        In the ordinary course of its business, MarkWest Energy Partners 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 Partnership; 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 Partnership 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.

        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 Partnership for certain expenses related to the pipeline incident. These include the Partnership'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 Partnership was granted leave of the Court to amend its complaint to add a bad faith claim, and a claim for punitive damages. The Partnership has not provided for a receivable for any of the claims in this action because of the uncertainty as to

43



whether and how much the Partnership will ultimately recover under the policies. Discovery in the action is continuing. The Partnership has also asserted that the cost of pipeline testing, replacement and repair are subject to an equitable sharing arrangement with the pipeline owner, pursuant to the terms of the pipeline lease agreement.

        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.

        The Partnership received notice from one of our 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.

        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, 214th 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, 214th 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, 28TH Judicial District, severed May 18, 2005, from the Gonzales case cited above); and Esmerejilda G. Valasquez, et al. v. Occidental Chemical Corp., et al., Case No. A-060352-C, 128thJudicial 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, 214th 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.

        In the ordinary course of business, the Partnership 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 Partnership's financial condition, liquidity or results of operations.


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

        No matter was submitted to a vote of the holders of our common units during the fourth quarter of the fiscal year ended December 31, 2006.

44



PART II

ITEM 5.    Market for Registrant's Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities

        Our common units have been listed on the American Stock Exchange ("AMEX"), under the symbol "MWE," since May 24, 2002. Prior to May 24, 2002, our equity securities were not listed on any exchange, or traded on any public trading market. The following table sets forth the high and low sales prices of the common units as reported by AMEX, as well as the amount of cash distributions paid per quarter for 2006 and 2005.

        On January 25, 2007, the board of directors of the general partner of the Partnership declared a two-for-one unit split, which became effective February 28, 2007. For all periods presented, all references to the number of units and per unit net income and distribution amounts included in this report have been adjusted to give the effect for the unit split.

Quarter Ended

  High
  Low
  Distributions
Per
Common
Unit

  Distributions
Per
Subordinated
Unit

  Record Date
  Payment Date
December 31, 2006   $ 29.95   $ 23.38   $ 0.500   $ 0.500   February 8, 2007   February 14, 2007
September 30, 2006   $ 24.75   $ 20.50   $ 0.485   $ 0.485   November 3, 2006   November 14, 2006
June 30, 2006   $ 23.33   $ 19.75   $ 0.460   $ 0.460   August 7, 2006   August 14, 2006
March 31, 2006   $ 24.00   $ 21.76   $ 0.435   $ 0.435   May 5, 2006   May 15, 2006

December 31, 2005

 

$

25.48

 

$

21.01

 

$

0.410

 

$

0.410

 

February 8, 2006

 

February 14, 2006
September 30, 2005   $ 26.75   $ 23.59   $ 0.410   $ 0.410   November 8, 2005   November 14, 2005
June 30, 2005   $ 25.77   $ 23.26   $ 0.400   $ 0.400   August 9, 2005   August 15, 2005
March 31, 2005   $ 26.25   $ 22.63   $ 0.400   $ 0.400   May 10, 2005   May 16, 2005

        As of March 1, 2007, there were 154 holders of record of our common units.

        The Partnership has also issued 6,000,000 subordinated units, for which there is no established public-trading market. Pursuant to the terms of the partnership agreement, 2,400,000 of these units were converted into common units in each of 2005 and 2006, and 1,200,000 subordinated units were outstanding as of December 31, 2006. There was 1 unit holder of record of our subordinated units as of March 1, 2007.

Distributions of Available Cash

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

45



Distributions of Available Cash During the Subordination Period

        During the subordination period (as defined in the Partnership Agreement and discussed further below), our quarterly distributions of available cash will be made in the following manner (reflects the two-for-one unit split on February 28, 2007):

    First, 98% to the common unitholders and 2% to our general partner, until each common unitholder has received a minimum quarterly distribution of $0.25, plus any arrearages from prior quarters.

    Second, 98% to the subordinated unitholders and 2% to our general partner, until each subordinated unitholder has received a minimum quarterly distribution of $0.25, plus any arrearages from prior quarters.

    Third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unitholder has received a distribution of $0.275 per quarter.

    Thereafter, in the manner described in "Incentive Distribution Rights" below.

Distributions of Available Cash After the Subordination Period

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

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

    Thereafter, in the manner described in "Incentive Distribution Rights" below.

Incentive Distribution Rights

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

        If for any quarter:

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

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

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

    First, 98% to all unitholders, pro rata, and 2% to our general partner until each unitholder receives a total of $0.275 per unit for that quarter (the "first target distribution");

    Second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives a total of $0.3125 per unit for that quarter (the "second target distribution");

    Third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives a total of $0.375 per unit for that quarter (the "third target distribution"); and

    Thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

46


        In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders, to eliminate any cumulative arrearages in payment of the minimum quarterly distribution. We are currently distributing in excess of $0.375 per unit per quarter.

        There is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter, and we are prohibited from making any distributions to unitholders if it would cause an event of default under our credit facility. The subordination period generally will not end earlier than June 30, 2007. A portion of the subordinated units, however, may be converted into common units at an earlier date on a one-for-one basis based upon the achievement of certain financial goals (defined in the Partnership Agreement). As a result of achieving those goals, 4,800,000 subordinated units converted into common units. The following table reflects the effects of the two-for-one unit split on February 28, 2007. The conversion of the subordinated units occurred as follows:

 
  Subordinated
Units

 
Subordinated units outstanding at December 31, 2004   6,000,000  
  Conversion—August 15, 2005   (1,200,000 )
  Conversion—November 15, 2005   (1,200,000 )
   
 
Subordinated units outstanding at December 31, 2005   3,600,000  
  Conversion—August 15, 2006   (1,200,000 )
  Conversion—November 15, 2006   (1,200,000 )
   
 
Subordinated units outstanding at December 31, 2006   1,200,000  
   
 

Securities Authorized for Issuance under Equity Compensation Plans

        The following table provides information, as of December 31, 2006, regarding our common units that may be issued upon conversion of outstanding restricted units granted under our Long-Term Incentive Plan to employees and directors of our general partner and employees of its affiliates who perform services for us. For more information about this plan, which did not require approval by the Partnership's limited partners, you should read Note 13 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K/A.

 
  Number of securities
to be issued upon
exercise of outstanding
options, warrants
and rights

  Weighted-average
exercise price of
outstanding options,
warrants and rights(1)

  Number of securities
remaining available
for future issuance
under equity
compensation plans

Equity compensation plans approved by security holders      
Equity compensation plans not approved by security holders:            
 
Long-Term Incentive Plan—(restricted units)

 

125,200

 


 

128,242
  Long-Term Incentive Plan—(unit options)       600,000
   
 
 
Total   125,200     728,242
   
 
 

(1)
Restricted units are granted with no exercise price.

47



ITEM 6.    Selected Financial Data

        The following table sets forth selected consolidated historical financial and operating data for MarkWest Energy Partners. 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 23 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 February 2007 two-for-one unit split. The selected financial data should be read in conjunction with the combined and consolidated financial statements, including the notes thereto, and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation.

 
  Year Ended December 31,
 
 
  2006(5)
  2005(1)(5)
  2004(2)(5)
  2003(3)
  2002
 
 
  (in thousands, except per share amounts)

 
 
  (As restated)

  (As restated)

   
   
   
 
Statement of Operations:                                
Revenues   $ 629,911   $ 541,090   $ 319,119   $ 117,430   $ 70,246  
  Operating expenses:                                
  Purchased product costs     376,237     408,884     229,339     70,832     38,906  
  Facility expenses     60,112     47,972     29,911     20,463     15,101  
  Selling, general and administrative expenses     44,185     21,573     16,133     8,598     5,411  
  Depreciation     29,993     19,534     15,556     7,548     4,980  
  Amortization of intangible assets     16,047     9,656     3,640          
  Accretion of asset retirement obligations     102     159     13          
  Impairments             130     1,148      
   
 
 
 
 
 
    Total operating expenses     526,676     507,778     294,722     108,589     64,398  
   
 
 
 
 
 
  Income from operations     103,235     33,312     24,397     8,841     5,848  
 
Earnings (losses) from unconsolidated affiliates

 

 

5,316

 

 

(2,153

)

 

(65

)

 


 

 


 
  Interest income     962     367     87     14     5  
  Interest expense     (40,666 )   (22,469 )   (9,236 )   (3,087 )   (1,128 )
  Amortization of deferred financing costs and original issue discount (a component of interest expense)     (9,094 )   (6,780 )   (5,236 )   (984 )   (291 )
  Miscellaneous income (expense)     11,100     78     15     (25 )   52  
   
 
 
 
 
 
  Income before income taxes     70,853     2,355     9,962     4,759     4,486  
 
Income tax benefit (expense)

 

 

(769

)

 


 

 


 

 


 

 

17,175

 
   
 
 
 
 
 
    Net income   $ 70,084   $ 2,355   $ 9,962   $ 4,759   $ 21,661  
   
 
 
 
 
 
 
Net income per limited partner unit (see Item 8.—Note 12):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Basic   $ 2.45   $ 0.01   $ 0.66   $ 0.47   $ 2.43  
  Diluted   $ 2.44   $ 0.01   $ 0.65   $ 0.47   $ 2.41  
  Cash distributions declared per limited partner unit   $ 1.79   $ 1.60   $ 1.43   $ 1.16   $ 0.36  

Balance Sheet Data (at December 31):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Working capital   $ 4,258   $ 11,944   $ 10,547   $ 2,457   $ 1,762  
  Property, plant and equipment, net     550,886     492,961     280,635     184,214     79,824  
  Total assets     1,114,780     1,046,093     529,422     212,871     87,709  
  Total long-term debt, including debt due to parent     526,865     601,262     225,000     126,200     21,400  
  Partners' capital     452,649     307,175     241,142     64,944     60,863  

Cash Flow Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Net cash flow provided by (used in):                                
    Operating activities   $ 150,977   $ 42,090   $ 42,275   $ 21,229   $ 33,502  
    Investing activities     (119,338 )   (469,308 )   (273,176 )   (112,893 )   (2,056 )
    Financing activities     (17,342 )   423,060     246,411     97,641     (28,670 )

Other Financial Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Sustaining capital expenditures(4)   $ 2,291   $ 2,181   $ 1,163   $ 1,041   $ 511  
  Expansion capital expenditures(4)     75,096     68,569     29,304     1,903     1,634  
   
 
 
 
 
 
    Total capital expenditures   $ 77,387   $ 70,750   $ 30,467   $ 2,944   $ 2,145  
   
 
 
 
 
 

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

48


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

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


We acquired our Arapaho processing plant in December 2003.


We acquired our Pinnacle gathering systems in late March 2003.


We acquired our Lubbock pipeline (a/K/A the Power-tex Lateral Pipeline) in September 2003 and our Hobbs lateral pipeline in April 2004. The Lubbock and Hobbs pipelines are the only laterals we own that produce revenue on a per-unit-of-throughput basis.


We acquired our Michigan Crude Pipeline in December 2003.

(4)
Sustaining capital includes expenditures to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Expansion capital includes expenditures made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition.

(5)
See Note 23 to consolidated financial statements included in Item 8 to this Form 10-K/A.

Operating Data

 
  Year ended December 31,
 
  2006
  2005
  2004
  2003
  2002
East Texas:(1)                    
  Gathering systems throughput (Mcf/d)   378,100   321,000   259,300   NA   NA
    NGL product sales (gallons)   161,437,000   126,476,000   41,478,000   NA   NA

Oklahoma:

 

 

 

 

 

 

 

 

 

 
  Foss Lake gathering systems throughput (Mcf/d)   87,500   75,800   60,900   57,000   NA
  Woodford Shale gathering systems throughput (Mcf/d)(2)   34,000   NA   NA   NA   NA
    Arapaho NGL product sales (gallons)   79,093,000   60,903,000   45,273,000   2,910,000   NA

Other Southwest:(3)

 

 

 

 

 

 

 

 

 

 
  Appleby gathering systems throughput (Mcf/d)   34,200   33,400   27,100   23,800   NA
    Other gathering systems throughput (Mcf/d)   18,300   16,500   17,000   20,500   NA
    Lateral throughput volumes (Mcf/d)(3)   84,200   81,000   75,500   32,100   NA

Appalachia:(4)

 

 

 

 

 

 

 

 

 

 
  Natural gas processed for a fee (Mcf/d)   203,000   197,000   203,000   202,000   202,000
  NGLs fractionated for a fee (Gal/d)   454,800   430,000   475,000   458,000   476,000
  NGL product sales (gallons)   43,271,000   41,700,000   42,105,000   40,305,000   38,813,000

Michigan:

 

 

 

 

 

 

 

 

 

 
  Natural gas processed for a fee (Mcf/d)   6,500   6,600   12,300   15,000   13,800
  NGL product sales (gallons)   5,643,000   5,697,000   9,818,000   11,800,000   11,100,000
  Crude oil transported for a fee (Bbl/d)   14,500   14,200   14,700   15,100   NA
                     

49



Gulf Coast:(5)

 

 

 

 

 

 

 

 

 

 
  Natural gas processed for a fee (Mcf/d)   124,300   115,000   NA   NA   NA
  NGLs fractionated for a fee (Bbl/d)   26,200   25,600   NA   NA   NA

(1)
We acquired the East Texas system in late July 2004.

(2)
In late 2006 we 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.

(3)
We acquired the Lubbock pipeline (a/k/a the Power-tex lateral pipeline) in September 2003 and the Hobbs lateral pipeline in April 2004. The Lubbock and Hobbs pipelines are the only laterals that we own that produce revenue on a per-unit-of-throughput basis. The Partnership receives a flat fee from its other lateral pipelines and, consequently, the throughput data from these lateral pipelines is excluded from this statistic.

(4)
Includes throughput from the Kenova, Cobb, and Boldman processing plants.

(5)
We acquired the Javelina system (Gulf Coast) on November 1, 2005.

50



ITEM 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations

        Management's Discussion and Analysis ("MD&A") contains statements that are forward-looking and should be read in conjunction with "Selected Consolidated Financial Data" and our consolidated financial statements and accompanying notes included elsewhere in this report. These statements are based on current expectations and assumptions that are subject to risks and uncertainties. Actual results could differ materially from those expressed or implied in the forward-looking statements as a result of a number of factors. Management's Discussion and Analysis gives effect to the restatement as discussed in Note 23 to the accompanying consolidated financial statements included in Item 8 of this Form 10-K/A.


Overview

        MarkWest Energy is a master limited partnership whose diverse portfolio of midstream assets serves many of the most prolific natural gas basins in the United States. The Partnership is primarily 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.

        Our corporate business strategy is to grow sustainable cash flow and cash distributions to our unitholders. The key elements of our strategy are to optimize existing assets and services, expand operations through new construction, and to target accretive and complementary acquisitions and expansion opportunities that provide attractive growth potential.

        The Partnership is required by its partnership agreement to distribute available cash from operating surplus each quarter to pay the minimum quarterly distribution. The amount of cash we can distribute on our units depends principally on the amount of cash generated from our operations.

        Distributions by the Partnership have increased from $0.25 per unit for the quarter ended September 30, 2002 (its first full quarter of operation after its initial public offering), to $0.50 per unit for the quarter ended December 31, 2006.

        A significant part of the Partnership's business strategy includes acquiring additional businesses that will allow it to increase distributions to its unitholders. The Partnership regularly considers and enters into discussions regarding potential acquisitions. These transactions can be effected quickly, may occur at any time and may be significant in size relative to the Partnership's existing assets and operations.

        In September 2006 the Partnership announced a strategic agreement with Newfield Exploration which involves the construction and operation of a new gathering and compression system to support all Newfield operated wells in a 200-square-mile project area situated in a four-county region in the Arkoma Basin in eastern Oklahoma. The Partnership expects its capital investment from 2006 through 2011 to range from $275 million to $350 million with between $150 million and $170 million of that investment occurring by the end of 2007.

        In November 2006 the Partnership completed a shelf offering registration on Form S-3 allowing it to raise up to $500 million in debt and equity securities for future internal growth projects and acquisitions.

Financial Statement Restatement

        Subsequent to the issuance of the Partnership's consolidated financial statements for the year ended December 31, 2006, the general partner of the Partnership and its Audit Committee, determined that previously issued consolidated financial statements for the years ended December 31, 2006 and 2005, including the quarters therein, should be restated to correct an error in accounting for certain revenue arrangements in the East Texas business segment. Accordingly, the Audit Committee of the Partnership concluded that the consolidated financial statements for such periods should not be relied

51



upon. Although the misstatement for the year ended December 31, 2004 was deemed immaterial, revenue and purchased product costs have both been increased by $17.8 million to correct the error. The restatement involves transactions in which the Partnership has determined it acted as a principal instead of an agent, thereby giving rise to accounting for revenue from such activities on a gross rather than net basis. The Partnership arrived at this decision after an extensive review of its accounting for revenue arrangements 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.

Impact of Acquisitions on Comparability of Financial Results

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

        Since our initial public offering, we have completed nine acquisitions for an aggregate purchase price of $810 million, net of working capital. Four of these acquisitions occurred in 2003 and their results are included in the results of operations from the acquisition date.

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

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

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

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

    The Starfish acquisition closed on March 31, 2005, for consideration of $41.7 million. Nine months of Starfish activity is reflected in results of operations for the year ended December 31, 2005.

    The Javelina acquisition closed on November 1, 2005, for consideration of $357.0 million, plus $41.8 million for net working capital. As a result, only two months of activity for Javelina is reflected in the results of operations for the year ended December 31, 2005.

        One acquisition occurred 2006 and it is included in the results of operations from the acquisition date.

    The Santa Fe acquisition closed on December 29, 2006 for consideration of $15.0 million. As a result, activity for Grimes gathering system will be reflected in the results of operations beginning in 2007.

Our Relationship with MarkWest Hydrocarbon, Inc.

        We were formed by MarkWest Hydrocarbon in 2002 to acquire most of its natural gas gathering and processing assets and NGL transportation, fractionation and storage assets. MarkWest Hydrocarbon remains one of our largest customers. We expect to continue deriving a portion of our revenues from the services we provide under our contracts with MarkWest Hydrocarbon for the foreseeable future; however, the percentage of our revenues and net operating margins (a non-GAAP financial measure, see Item 1. Business—Our Contracts) will likely continue to decline as our other businesses grow. For the year ended December 31, 2006 and 2005, it accounted for 12% of our

52



consolidated revenues. As of December 31, 2006, MarkWest Hydrocarbon and its subsidiaries, in the aggregate, owned a 17% interest in the Partnership, consisting of 1,200,000 subordinated units, 3,738,992 common units and a 2% general partner interest.

        Neither we nor our General Partner have any employees. However, under a Services Agreement entered into between our General Partner and MarkWest Hydrocarbon, Inc., MarkWest Hydrocarbon acts in a management capacity rendering day-to-day operational, business and asset management, accounting, information services, personnel and related administrative services to the Partnership. In return, the Partnership reimburses MarkWest Hydrocarbon for all documented expenses incurred on behalf of the Partnership and which are expressly designated as reasonably necessary for the performance of the prescribed duties and specified functions. General corporate expenses and costs that are not specifically linked to either MarkWest Hydrocarbon or us, are allocated in accordance with an approved allocation methodology which is designed to ensure that neither entity bears a disproportionate or unfair burden of the other company's costs and expenses, and is reflective of respective income statements.

Results of Operations

Segment Reporting

        Our six geographical segments are: East Texas, Oklahoma, Other Southwest, Gulf Coast, Appalachia and Michigan. We capture information in this MD&A by geographical segment, except that certain items below the "Operating Income" line are not allocated to our business segments because management does not consider them in its evaluation of business unit performance. In addition, selling, general and administrative expenses are not allocated to individual business segments because management evaluates each business segment based on operating income before selling, general and administrative expenses. The segment information appearing in Note 20 to the consolidated financial statements, Segment Information, is presented on a basis consistent with the Partnership's internal management reporting, in accordance with SFAS No. 131, Disclosure about Segments of an Enterprise and Related Information.

Year Ended December 31, 2006, Compared to Year Ended December 31, 2005

East Texas

 
  Year ended December 31,
   
   
 
 
   
  % Change
 
 
  2006
  2005
  $ Change
 
 
  (in thousands)

   
   
 
Revenues   $ 174,279   $ 128,267   $ 46,012   36 %
Operating expenses:                        
  Purchased product costs     91,637     81,030     10,607   13 %
  Facility expenses     15,683     10,463     5,220   50 %
  Depreciation     7,783     4,836     2,947   61 %
  Amortization of intangible assets     8,244     8,293     (49 ) (.6 )%
  Accretion of asset retirement obligations     44     33     11   33 %
   
 
 
     
    Total operating expenses before selling, general and administrative expenses     123,391     104,655     18,736   18 %
   
 
 
     
Operating income before selling, general and administrative expenses   $ 50,888   $ 23,612   $ 27,276   116 %
   
 
 
     

        Revenues:    Revenues increased $46.0 million, or 36%, during the year ended December 31, 2006, relative to 2005. The increase was due to our Carthage gas processing plant beginning operations on

53



January 1, 2006; the start-up of the Blocker gathering system on March 1, 2006; and increased condensate volumes over the same period a year ago.

        Purchased Product Costs:    Purchased product costs increased $10.6 million, or 13%, during the year ended December 31, 2006, relative to the comparable period in 2005, primarily due to the start-up of the Carthage gas processing plant.

        Facility Expenses:    Facility expenses increased $5.2 million, or 50%, during the year ended December 31, 2006, relative to the comparable period in 2005, primarily due to startup of the new Carthage gas processing plant and Blocker gathering system, including the related labor and property taxes.

        Depreciation:    Depreciation expense increased $2.9 million, or 61%, during the year ended December 31, 2006, relative to the comparable period in 2005, mainly due to the new Carthage gas processing plant and Blocker gathering system.

Oklahoma

 
  Year ended December 31,
   
   
 
 
   
  % Change
 
 
  2006
  2005
  $ Change
 
 
  (in thousands)

   
   
 
Revenues   $ 207,510   $ 214,043   $ (6,533 ) (3 )%
Operating expenses:                        
  Purchased product costs     170,168     193,787     (23,619 ) (12 )%
  Facility expenses     7,883     4,927     2,956   60 %
  Depreciation     3,007     2,385     622   26 %
  Accretion of asset retirement obligations     26     63     (37 ) (59 )%
   
 
 
     
    Total operating expenses before selling, general and administrative expenses     181,084     201,162     (20,078 ) (10 )%
   
 
 
     
Operating income before selling, general and administrative expenses   $ 26,426   $ 12,881   $ 13,545   105 %
   
 
 
     

        Revenues:    Revenues decreased $6.5 million, or 3% during the year ended December 31, 2006, relative to the comparable period in 2005. The decrease was due primarily due to lower natural gas prices that were partially offset by a 15% increase in gathering volumes from new well connects in 2006.

        Purchased Product Cost:    Purchased product costs decreased $23.6 million, or 12%, during the year ended December 31, 2006, relative to the comparable period in 2005, primarily as a result of lower natural gas prices.

        Facility Expenses:    Facility expenses increased $3.0 million, or 60%, during the year ended December 31, 2006, relative to the comparable period in 2005, primarily due to additional compression costs and higher operating taxes.

        Depreciation:    Depreciation expense increased $0.6 million, or 26%, during the year ended December 31, 2006, relative to the comparable period in 2005, related to additional capital placed in service to accommodate a growing gathering system and new well connects.

54



Other Southwest

 
  Year ended December 31,
   
   
 
 
   
  % Change
 
 
  2006
  2005
  $ Change
 
 
  (in thousands)

   
   
 
Revenues   $ 84,595   $ 107,712   $ (23,117 ) (21 )%
Operating expenses:                        
  Purchased product costs     67,349     92,602     (25,253 ) (27 )%
  Facility expenses     5,638     4,990     648   13 %
  Depreciation     4,100     3,383     717   21 %
  Amortization of intangible assets         68     (68 ) (100 )%
  Accretion of asset retirement obligations     20     22     (2 ) (9 )%
   
 
 
     
    Total operating expenses before selling, general and administrative expenses     77,107     101,065     (23,958 ) (24 )%
   
 
 
     
Operating income before selling, general and administrative expenses   $ 7,488   $ 6,647   $ 841   13 %
   
 
 
     

        Revenues:    Revenues decreased $23.1 million, or 21%, during the year ended December 31, 2006, relative to the comparable period in 2005. The decrease is mostly attributed to a decrease in natural gas prices, and is slightly offset by an increase in NGL volumes and prices.

        Purchased Product Costs:    Purchased product costs decreased $25.3 million, or 27%,during the year ended December 31, 2006, relative to the comparable period in 2005 primarily due to a decrease in natural gas prices.

        Facility Expenses:    Facility expenses increased $0.6 million, or 13%, during the year ended December 31, 2006, relative to the comparable period in 2005. The increase was primarily a result of additional compressor maintenance costs.

        Depreciation:    Depreciation expense increased $0.7 million, or 21%, during the year ended December 31, 2006, relative to the same period in 2005, due to the addition of new compressors in 2006 and late 2005.

55


Appalachia

 
  Year ended December 31,
   
   
 
 
   
  % Change
 
 
  2006
  2005
  $ Change
 
 
  (in thousands)

   
   
 
Revenue                        
  Unaffiliated   $ 2,027   $ 1,686   $ 341   20 %
  Affiliated     73,636     64,922     8,714   13 %
   
 
 
     
Total revenues     75,663     66,608     9,055   14 %
   
 
 
     
Operating expenses:                        
  Purchased product costs     43,648     38,435     5,213   14 %
  Facility expenses     13,997     19,360     (5,363 ) (28 )%
  Depreciation     3,573     3,187     386   12 %
  Accretion of asset retirement obligations     12     41     (29 ) (71 )%
   
 
 
     
    Total operating expenses before selling, general and administrative expenses     61,230     61,023     207   0 %
   
 
 
     
Operating income before selling, general and administrative expenses   $ 14,433   $ 5,585   $ 8,848   158 %
   
 
 
     

        Revenues:    Total revenues increased $9.1 million, or 14%, during the year ended December 31, 2006, relative to the comparable period in 2005. The increase was primarily a result of higher prices and volumes for our Maytown NGLs in 2006. Higher gas volumes at the Kenova and Cobb plants and higher liquid volumes at the Kenova, Cobb and Boldman plants also contributed to the increase; however, these results were offset slightly by lower gas volumes at Boldman.

        Purchased Product Costs:    Purchased product costs increased $5.2 million, or 14%, during the year ended December 31, 2006, relative to the comparable period in 2005. The rise in costs is primarily a result of higher product prices. The increase was partially offset by reduced trucking expenses amounting to $1.4 million associated with our continuing repair of the ALPS pipeline in 2005 versus the shutdown of the ALPS pipeline in late 2006. We expect the ALPS pipeline to be maintained in idle status for an indefinite period.

        Facility Expenses:    Facility expenses decreased $5.4 million, or 28%, during the year ended December 31, 2006, relative to the comparable period in 2005. These expenses were higher in 2005 due to costs incurred to repair the ALPS pipeline.

        Depreciation:    Depreciation expense increased $0.4 million, or 12%, during the year ended December 31, 2006, relative to the comparable period in 2005, due to increased capitalized leasehold improvements associated with the ALPS pipeline.

56



Michigan

 
  Year ended December 31,
   
   
 
 
  2006
  2005
  $ Change
  % Change
 
 
  (in thousands)

   
   
 
Revenues   $ 13,282   $ 12,479   $ 803   6 %
Operating expenses:                        
  Purchased product costs     3,435     3,030     405   13 %
  Facility expenses     5,721     6,080     (359 ) (6 )%
  Depreciation     5,015     4,665     350   8 %
   
 
 
     
    Total operating expenses before selling, general and administrative expenses     14,171     13,775     396   3 %
   
 
 
     
Operating loss before selling, general and administrative expenses   $ (889 ) $ (1,296 ) $ 407   (31 )%
   
 
 
     

        Revenues:    Revenues increased $0.8 million, or 6%, during the year ended December 31, 2006, relative to the comparable period in 2005, principally due to an increase in product prices at our processing facility and increased processing fees at the West Shore facility, slightly offset by decreased volumes.

        Purchased Product Costs:    Purchased product costs increased $0.4 million, or 13%, during the year ended December 31, 2006, relative to the comparable period in 2005, which was a result of higher product prices at our processing facility.

        Facility Expenses:    Facility expenses decreased $0.4 million, or 6%, during the year ended December 31, 2006, relative to the comparable period in 2005, primarily due to lower regulatory costs and repairs and maintenance.

        Depreciation:    Depreciation expense increased $0.4 million, or 8% during the year ended December 31, 2006, relative to the comparable period in 2005, mostly due to accelerated depreciation of certain assets.

        Given the continuing losses and moderately positive cash flows relating to the Michigan assets, management continues to consider alternatives, and we are evaluating potential impairments. Management determined there were no impairments as of December 31, 2006.

Gulf Coast

 
  Year ended December 31,
   
   
 
 
  2006
  2005
  $ Change
  % Change
 
 
  (in thousands)

   
   
 
Revenues   $ 68,950   $ 13,832     55,118   398 %
Operating expenses:                        
  Facility expenses     11,190     2,152     9,038   420 %
  Depreciation     6,500     1,078     5,422   503 %
  Amortization of intangible assets     7,803     1,295     6,508   503 %
   
 
 
     
    Total operating expenses before selling, general and administrative expenses     25,493     4,525     20,968   463 %
   
 
 
     
Operating income before selling, general and administrative expenses   $ 43,457   $ 9,307   $ 34,150   367 %
   
 
 
     

57


        The results of operations at Javelina are based on twelve months of activity for the year ended December 31, 2006, compared to two months of activity beginning in November of 2005, the date of the acquisition.

        Revenues:    Revenues increased $55.1 million, during the year ended December 31, 2006, compared to the two month period in 2005. Revenues in the Gulf Coast business unit are generated under percent-of-proceeds arrangements and are generally reported net of purchased product costs (see Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations"—Revenue Recognition in Critical Accounting Policies and Estimates). The Partnership gathers and processes natural gas on behalf of producers, sell the resulting residue gas, condensate and NGLs at market prices and remit to producers an agreed-upon percentage of the proceeds based on an index price. The Javelina plant has been able to grow revenue in 2006 despite reduced inlet gas from refineries.

        Facility Expenses:    Facility expenses increased $9.0 million during the year ended December 31, 2006, compared to the two month period in 2005, because the 2006 results include a full year of operations.

        Depreciation:    Depreciation expense increased $5.4 million during the year ended December 31, 2006, compared to the two month period in 2005, because the results include a full year of operations.

        Amortization of intangible assets:    Amortization expense increased $6.5 million during the year ended December 31, 2006, compared to the two month period in 2005, because the results include a full year of amortization compared to the stub period in 2005.

Consolidated Financial Information

 
  Year ended December 31,
   
   
 
 
  2006
  2005
  $ Change
  % Change
 
 
  (in thousands)

   
   
 
Total segment operating income   $ 141,803   $ 56,736   $ 85,067   150 %
  Derivative gain (loss) not allocated to segments     5,632     (1,851 )   7,483   (404 )%
  Depreciation not allocated to segments     (15 )       (15 ) NA  
  Selling, general and administrative     (44,185 )   (21,573 )   (22,612 ) 105 %
   
 
 
 
 
    Income from operations     103,235     33,312     69,923   210 %

Earnings (losses) from unconsolidated affiliates

 

 

5,316

 

 

(2,153

)

 

7,469

 

(347

)%
Interest income     962     367     595   162 %
Interest expense     (40,666 )   (22,469 )   (18,197 ) 81 %
Amortization of deferred finance costs     (9,094 )   (6,780 )   (2,314 ) 34 %
Miscellaneous income     11,100     78     11,022   14,131 %
   
 
 
     
    Income before Texas Margin Tax   $ 70,853   $ 2,355   $ 68,498   2,909 %
 
Texas Margin Tax

 

 

(769

)

 


 

 

(769

)

NA

 
   
 
 
     
Net income   $ 70,084   $ 2,355   $ 67,729   2,876 %
   
 
 
     

        Derivative gain (loss).    Derivative gain (loss) increased $7.5 million during the year ended December 31, 2006, compared to the corresponding period in 2005. This increase was due to the mark-to-market adjustments resulting from our electing not to adopt hedge accounting treatment on our derivative instruments. The mark-to-market adjustments resulted in a $6.9 million increase in unrealized gains, and a $0.6 million decrease in realized losses, when comparing 2006 to 2005 results.

58



        Selling, General and Administrative Expense:    Selling, general and administrative expenses increased $22.6 million, or 105%, during the year ended December 31, 2006, relative to the comparable period in 2005. The increase is primarily due to higher non-cash, equity-based compensation expense of $12.0 million, primarily due to the Partnership's increased market value; an increase in labor costs of $4.9 million related to increased costs for our existing employees plus the cost of additional personnel necessary to support our growth and strategic objectives; higher insurance expense and taxes of $2.4 million; and a one-time charge to terminate the old headquarters lease of $0.8 million.

        Earnings (losses) from Unconsolidated Affiliates:    Earnings (losses) from unconsolidated affiliates is primarily related to our investment in Starfish, a joint venture with Enbridge Offshore Pipelines LLC. The Partnership accounts for our 50% interest using the equity method, and the financial results for Starfish are included as earnings from unconsolidated affiliates. During the year ended December 31, 2006, our earnings from unconsolidated affiliates increased $7.5 million, or 347%, relative to the comparable period in 2005. The increase was primarily from resumed operations in 2006 following the shutdown and repairs from the hurricanes in 2005.

        Interest Income:    Interest income increased $0.6 million, or 162%, during the year ended December 31, 2006, relative to the comparable period in 2005, primarily due to an increase in interest rates earned on invested funds.

        Interest Expense:    Interest expense increased $18.2 million, or 81%, during the year ended December 31, 2006, relative to the comparable period in 2005, primarily due to increased debt levels resulting from the financing of our 2005 acquisitions and higher interest rates.

        Amortization of Deferred Financing Costs (a component of interest expense):    Amortization expense increased $2.3 million, or 34%, during the year ended December 31, 2006, relative to the comparable period in 2005, primarily due to costs associated with our debt refinancing completed in the fourth quarter of 2005 and our debt offering in July of 2006. Deferred financing costs are being amortized over the terms of the related obligations, which approximates the effective interest method.

        Miscellaneous Income (Expense):    The Partnership recognized $11.0 million of income from insurance recoveries, net of Starfish insurance premiums, recovered from damages that occurred as a result of Hurricane Rita.

        Texas Margin Tax:    The State of Texas passed a new tax law that subjects the Partnership to an entity-level tax on the portion of its income that is generated in Texas. We recorded a deferred tax liability of $0.8 million, related to the Partnership's temporary differences that are expected to reverse in future periods.

59



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

East Texas

 
  Year ended December 31,
   
   
 
 
  2005
  2004
  $ Change
  % Change
 
 
  (in thousands)

   
   
 
Revenues   $ 128,267   $ 39,737   $ 88,530   223 %
Operating expenses:                        
  Purchased product costs     81,030     21,474     59,556   277 %
  Facility expenses     10,463     3,229     7,234   224 %
  Depreciation     4,836     1,489     3,347   225 %
  Amortization of intangible assets     8,293     3,446     4,847   141 %
  Accretion of asset retirement obligations     33     13     20   154 %
   
 
 
     
    Total operating expenses before selling, general and administrative expenses     104,655     29,651     75,004   253 %
   
 
 
     
Operating income before selling, general and administrative expenses   $ 23,612   $ 10,086   $ 13,526   134 %
   
 
 
     

        Revenues.    Revenues increased 223% during the year ended December 31, 2005, relative to the comparable period in 2004. The Partnership acquired the East Texas System on July 30, 2004. As a result, the Partnership reflected only five months of activity during 2004. The remaining increase is attributed to price increases and growth in gathering volumes and associated liquid production.

        Purchased Product Costs.    Purchased product costs increased 277% during the year ended December 31, 2005, relative to the comparable period in 2004, primarily due to the fact that we acquired the East Texas System on July 30, 2004. The remaining increase is attributed to price increases.

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

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

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

60



Oklahoma

 
  Year ended December 31,
   
   
 
 
  2005
  2004
  $ Change
  % Change
 
 
  (in thousands)

   
   
 
Revenues   $ 214,043   $ 133,889   $ 80,154   60 %
Operating expenses:                        
  Purchased product costs     193,787     118,325     75,462   64 %
  Facility expenses     4,927     3,659     1,268   35 %
  Depreciation     2,385     2,059     326   16 %
  Accretion of asset retirement obligations     63         63   NA  
   
 
 
     
    Total operating expenses before selling, general and administrative expenses     201,162     124,043     77,119   62 %
   
 
 
     
Operating income before selling, general and administrative expenses   $ 12,881   $ 9,846   $ 3,035   31 %
   
 
 
     

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

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

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

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

Other Southwest

 
  Year ended December 31,
   
   
 
 
  2005
  2004
  $ Change
  % Change
 
 
  (in thousands)

   
   
 
Revenues   $ 107,712   $ 70,044   $ 37,668   54 %
Operating expenses:                        
  Purchased product costs     92,602     55,519     37,083   67 %
  Facility expenses     4,990     3,694     1,296   35 %
  Depreciation     3,383     3,099     284   9 %
  Amortization of intangible assets     68     194     (126 ) (65 )%
  Accretion of asset retirement obligations     22         22   NA  
   
 
 
     
    Total operating expenses before selling, general and administrative expenses     101,065     62,506     38,559   62 %
   
 
 
     
Operating income before selling, general and administrative expenses   $ 6,647   $ 7,538   $ (891 ) (12 )%
   
 
 
     

61


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

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

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

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

Appalachia

 
  Year ended December 31,
   
   
 
 
  2005
  2004
  $ Change
  % Change
 
 
  (in thousands)

   
   
 
Revenues:                        
  Unaffiliated   $ 1,763   $ 1,610   $ 153   10 %
  Affiliated     64,845     59,026     5,819   10 %
   
 
 
     
Total revenues     66,608     60,636     5,972   10 %
   
 
 
     

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

 
  Purchased product costs     38,435     30,031     8,404   28 %
  Facility expenses     19,360     13,444     5,916   44 %
  Depreciation     3,187     4,329     (1,142 ) (26 )%
  Impairment         130     (130 ) (100 )%
  Accretion of asset retirement obligations     41         41   NA  
   
 
 
     
    Total operating expenses before selling, general and administrative expenses     61,023     47,934     13,089   27 %
   
 
 
     
Operating income before selling, general and administrative expenses   $ 5,585   $ 12,702   $ (7,117 ) (56 )%
   
 
 
     

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

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

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

62


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

Michigan

 
  Year ended December 31,
   
   
 
 
  2005
  2004
  $ Change
  % Change
 
 
  (in thousands)

   
   
 
Revenues   $ 12,479   $ 15,633   $ (3,154 ) (20 )%
Operating expenses:                        
  Purchased product costs     3,030     3,990     (960 ) (24 )%
  Facility expenses     6,080     5,885     195   3 %
  Depreciation     4,665     4,580     85   2 %
   
 
 
     
    Total operating expenses before selling, general and administrative expenses     13,775     14,455     (680 ) (5 )%
   
 
 
     
Operating income (loss) before selling, general and administrative expenses   $ (1,296 ) $ 1,178   $ (2,474 ) (210 )%
   
 
 
     

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

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

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

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

Gulf Coast

 
  Year ended December 31,
   
   
 
   
  % Change
 
  2005
  2004
  $ Change
 
  (in thousands)

   
   
Revenues   $ 13,832   $   13,832   NA
Operating expenses:                    
  Facility expenses     2,152       2,152   NA
  Depreciation     1,078       1,078   NA
  Amortization of intangible assets     1,295       1,295   NA
   
 
 
   
    Total operating expenses before selling, general and administrative expenses     4,525       4,525   NA
   
 
 
   
Operating income before selling, general and administrative expenses   $ 9,307   $   9,307   NA
   
 
 
   

63


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

Consolidated Financial Information

 
  Year ended December 31,
   
   
 
 
   
  % Change
 
 
  2005
  2004
  $ Change
 
 
  (in thousands)

   
   
 
Total segment operating income   $ 56,736   $ 41,350   $ 15,386   37 %
  Derivative losses not allocated to segments     (1,851 )   (820 )   (1,031 ) 126 %
  Selling, general and administrative     (21,573 )   (16,133 )   (5,440 ) 34 %
   
 
 
     
    Income from operations     33,312     24,397     8,915   37 %
Losses from unconsolidated affiliates     (2,153 )   (65 )   (2,088 ) 3,212 %
Interest income     367     87     280   322 %
Interest expense     (22,469 )   (9,236 )   (13,233 ) 143 %
Amortization of deferred finance costs     (6,780 )   (5,236 )   (1,544 ) 29 %
Miscellaneous income     78     15     63   420 %
   
 
 
     
    Income before Texas Margin Tax   $ 2,355   $ 9,962   $ (7,607 ) (76 )%
Texas Margin Tax (Note 14)               NA  
   
 
 
     
Net income   $ 2,355   $ 9,962   $ (7,607 ) (76 )%
   
 
 
     

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

        Derivative Losses.    Losses from derivative instruments increased $1.0 million during the year ended December 31, 2006, compared to the corresponding period in 2005. This increase was due to the mark-to-market adjustments resulting from our electing not to adopt hedge accounting treatment on our derivative instruments. The mark-to-market adjustments resulted in a $0.4 million increase in unrealized losses, and a $0.6 million increase in realized losses, when comparing 2005 to 2004 results.

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

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

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

        Amortization of Deferred Financing Costs.    During the year ended December 31, 2005, the Partnership amortized approximately $6.8 million of deferred financing costs related to debt issuance costs it incurred to finance its acquisitions. The increase in the amortization of deferred financing costs in 2005 relative to the comparable period in 2004 is attributable to the write-off of deferred financings costs associated with our debt refinancing completed in the fourth quarter of 2005. Deferred financing costs are being amortized over the terms of the related obligations.

64



Liquidity and Capital Resources

        Our primary sources of liquidity to meet operating expenses and fund capital expenditures (other than for certain acquisitions), are cash flows generated by our operations and our access to equity and debt markets. The equity and debt markets, public and private, retail and institutional, have been our principal source of capital used to finance a significant amount of our growth, including acquisitions.

        On December 29, 2005, MarkWest Energy Operating Company, L.L.C., a wholly owned subsidiary of MarkWest Energy Partners L.P., entered into the fifth amended and restated credit agreement ("Partnership Credit Facility"). It provides for a maximum lending limit of $615.0 million for a five-year term. The credit facility included a revolving facility of $250.0 million and a $365.0 million term loan. The term loan portion of the Partnership Credit Facility was repaid without penalty in October 2006 using a portion of the proceeds from the debt and equity offerings in 2006 leaving the revolving facility intact. Under certain circumstances, the Partnership Credit Facility can be increased from $250.0 million up to $450.0 million. The credit facility is guaranteed by the Partnership and all of the Partnership's subsidiaries and is collateralized by substantially all of the Partnership's assets and those of its subsidiaries. The borrowings under the credit facility bear interest at a variable interest rate, plus basis points. The variable interest rate typically is based on the London Inter Bank Offering Rate ("LIBOR"); however, in certain borrowing circumstances the rate would be based on the higher of a) the Federal Funds Rate plus 0.5-1%, and b) a rate set by the Partnership Credit Facility's administrative agent, based on the U.S. prime rate. The basis points correspond to the ratio of the Partnership's Consolidated Senior Debt (as defined in the Partnership Credit Facility) to Consolidated EBITDA (as defined in the Partnership Credit Facility), ranging from 0.50% to 1.50% for Base Rate loans, and 1.50% to 2.50% for Eurodollar Rate loans. The basis points will increase by 0.50% during any period (not to exceed 270 days) where the Partnership makes an acquisition for a purchase price in excess of $50.0 million ("Acquisition Adjustment Period"). Borrowings under the Partnership Credit Facility were used to finance, in part, the Javelina acquisition discussed above. On December 31, 2006, the available borrowing capacity under the Partnership Credit Facility was $218.4 million.

        Cash generated from operations, borrowings under the Partnership Credit Facility and funds from our private and public equity and debt offerings are our primary sources of liquidity. The timing of our efforts to raise equity in 2006 was influenced by our failure to file in a timely manner our Annual Report on Form 10-K for the year ended December 31, 2004, and our quarterly report on Form 10-Q for the quarter ending March 31, 2005. However, as of October 11, 2006, we have the ability to incorporate by reference information from our future SEC filings into new registration statements in order to raise capital through a public offering. To raise additional capital through public debt or equity offerings, we are eligible to file a Form S-3, which is a short-form type of registration statement. On November 15, 2006, the Partnership filed a shelf registration statement on Form S-3, which became effective immediately and allows us to raise up to $500 million in debt and equity securities in the future.

        At December 31, 2006, the Partnership and its subsidiary, MarkWest Energy Finance Corporation, also have two series of senior notes outstanding, $225.0 million, at a fixed rate of 6.875% which will mature in November, 2014 (the "2014 Notes") and $271.9 million, net of unamortized discount of $3.1 million at a fixed rate of 8.5% due in July 15, 2016 (the "2016 Notes"). The proceeds from these notes were used to reduce outstanding debt under our credit facility. Subject to compliance with certain covenants, we may issue additional notes from time to time under the indenture pursuant to Rule 144A and Regulation S under the Securities Act of 1933. The estimated fair value of the 2014 notes was approximately $216.5 million and $207.0 million at December 31, 2006 and 2005, respectively.

        The 2016 Notes will mature on July 15, 2016, and interest is payable each July 15 and January 15, commencing January 15, 2007. The Partnership closed the private placement of $200 million on July 6, 2006 and it completed the private placement of an additional $75.0 million under the indenture on

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October 20, 2006. The net proceeds from the July and October 2006 private placements were approximately $191.2 million, and $74.5 million, respectively, after deducting the initial purchasers' discounts and legal, accounting and other transaction expenses. The Partnership used the net proceeds from the offering to repay the term debt under the Partnership Credit Facility, and used the remaining net proceeds to fund capital expenditures and for general corporate purposes. Affiliates of several of the initial purchasers, including RBC Capital Markets Corporation, J.P. Morgan Securities Inc., and Wachovia Capital Markets, LLC, are lenders under the Partnership Credit Facility. The estimated fair value of the 2016 notes was $283.3 at December 31, 2006.

        The indenture governing the 2014 Notes and the 2016 Notes limits the activity of the Partnership and its restricted subsidiaries. The indenture place limits on the ability of the Partnership and its restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of the Partnership's restricted subsidiaries to pay dividends, make loans or transfer property to the Partnership; engage in transactions with the Partnership's affiliates; sell assets, including equity interests of the Partnership's subsidiaries; make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets.

        On July 6, 2006, the Partnership completed its underwritten public offering of 6.0 million common units (the "Common Unit Offering") at a public offering price of $19.875 per common unit. In addition, on July 12, 2006, the Partnership completed the sale of an additional 600,000 common units to cover over-allotments in connection with the Common Unit Offering. The sale of units resulted in total gross proceeds of $131.2 million, and net proceeds of $125.9 million after the underwriters' commission and legal, accounting and other transaction expenses. The Partnership used the net proceeds from the offering and the proceeds from the capital contribution from its general partner to maintain its 2% general partner interest in the Partnership, to repay a portion of the term debt under the Partnership Credit Facility.

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

        The Partnership used $77.4 million for capital expenditures in 2006, exclusive of any acquisitions, consisting of $75.1 million for expansion capital and $2.3 million for sustaining capital. Expansion capital includes expenditures made to expand or increase the efficiency of the existing operating capacity of our assets, or facilitate an increase in volumes within our operations, whether through construction or acquisition. The Partnership has budgeted from $230 to $240 million for expenditures in 2007 consisting of $235.4 million for expansion capital and $5.0 million of sustaining capital. The Partnership plans to use from $150 to $170 million of its expansion capital budget to fund the construction of the Woodford gathering system. Sustaining capital includes expenditures to replace partially or fully depreciated assets in order to extend their useful lives.

Cash Flow

 
  December 31,
 
 
  2006
  2005
 
 
  (in thousands)

 
Net cash provided by operating activities   $ 150,977   $ 42,090  
Net cash used in investing activities     (119,338 )   (469,308 )
Net cash provided by (used in) financing activities     (17,342 )   423,060  

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        Net cash provided by operating activities increased by $108.9 million during the year ended December 31, 2006, compared to the year ended December 31, 2005. The increase was impacted by an increase in net income of $67.7 million, an increase in certain non-cash operating expenses, primarily depreciation and amortization for a full year from our Javelina acquisition, and a full year of amortization on the Carthage gas processing plant. We expect that, overall, our 2007 volumes will be higher than in 2006, and that cash provided by operating activities in 2007 will exceed 2006 levels. A precipitous decline in natural gas, NGL or crude oil prices or volumes, however, could significantly affect the amount of cash flow that would be generated from operations.

        Net cash used in investing activities was $350.0 million lower for the year ended December 31, 2006 compared to the year ended December 31, 2005, primarily due to our $356.9 million acquisition of Javelina in November 2005. In December 2006 the Partnership completed its acquisition of the Grimes gathering system using cash of $15.0 million. The Partnership used cash of $77.5 million for capital expenditures in 2006, including $21.6 million for the initial construction of the Woodford gathering system. In 2005, the Partnership used cash of $70.8 million for capital expenditures, primarily for the construction of a new processing plant and gathering systems in East Texas to handle our future contractual commitments and construction of the new replacement Cobb processing facility in Appalachia.

        Net cash used in financing activities increased $440.4 million during the year ended December 31, 2006, compared to the year ended December 31, 2005. The increase was due primarily to net proceeds from additional long-term debt and private placements in 2005 to fund our 2005 acquisitions. Distributions to unitholders increased to $64.9 million in 2006 from $39.0 million in 2005.

Total Contractual Cash Obligations

        A summary of our total contractual cash obligations as of December 31, 2006, is as follows (in thousands):

 
  Payment Due by Period
Type of obligation

  Total Obligation
  Due in 2007
  Due in 2008-2009
  Due in 2010-2011
  Thereafter
Long-term debt   $ 530,000   $   $   $ 30,000   $ 500,000
Interest expense on long-term debt(1)     344,624     41,469     82,937     80,312     139,906
Operating leases     24,689     8,896     7,476     3,178     5,139
Purchase obligations     31,997     31,997            
Other long-term liabilities     1,360                 1,360
   
 
 
 
 
Total contractual cash obligations   $ 932,670   $ 82,362   $ 90,413   $ 113,490   $ 646,405
   
 
 
 
 

(1)
Assumes that our outstanding borrowings at December 31, 2006 remain outstanding until their respective maturity dates and we incur interest expense at 8.75% on the Partnership Credit Facility revolver, 6.875% on the 2014 Senior Notes and 8.25% on the 2016 Senior Notes.

Off-Balance Sheet Arrangements

        The Partnership does not engage in off-balance sheet financing activities.

Matters Influencing Future Results

        During August and September 2005, Hurricanes Katrina and Rita caused severe and widespread damage to oil and gas assets in the Gulf of Mexico and Gulf Coast regions. Operations of our

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unconsolidated affiliate, Starfish Pipeline Company were nominally impacted by Hurricane Katrina but were significantly impacted by Hurricane Rita. We are continuing to submit insurance claims on an on-going basis relating to both business interruption and property damage and have submitted $14.5 million through January 31, 2007. We have recorded $11.0 million in insurance recoveries with respect to our property loss claims, and we anticipate additional recoveries for expenses and losses incurred as repairs proceed. We have not recorded any insurance recovery related to business interruption due to uncertainty around collection but have filed a claim for $3.5 million.

        The loss to both offshore and onshore assets resulting from Hurricane Rita has led to substantial insurance claims within the oil and gas industry. Along with other industry participants, we have seen our insurance costs increase substantially within this region as a result of these developments. We have renewed our insurance coverage relating to Starfish during the second quarter and mitigated a portion of the cost increase by reducing our coverage and adding a broader self-insurance element to our overall coverage.

        Our affiliate MarkWest Energy Appalachia, L.L.C. ("MEA") operates the Appalachia Liquids Pipeline System ("ALPS") pipeline to transport natural gas liquids ("NGLs") from our Maytown gas processing plant to our Siloam fractionator. This pipeline is owned by Equitable Production Company ("Equitable"), 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 appropriate 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, as well as exploring various arrangements and options for continuing pipeline transportation of the NGLs. 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.

Seasonality

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

Effects of Inflation

        Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2006, 2005 or 2004. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the costs of labor and supplies. To the extent permitted by competition, regulation and our

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existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.

Critical Accounting Policies and Estimates

        The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates are used in accounting for, among other items, valuing identified intangible assets, determining the fair value of derivative instruments, evaluating impairments of long lived assets, establishing estimated useful lives for long-lived assets, valuing asset retirement obligations, and in determining liabilities, if any, for legal contingencies.

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

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

        The Partnership evaluates its long-lived assets, including intangibles, for impairment when events or changes in circumstances warrant such a review. A long-lived asset group is considered impaired when the estimated undiscounted cash flows from such asset group are less than the asset group's carrying value. In that event, a loss is recognized to the extent that the carrying value exceeds the fair value of the long-lived asset group. Fair value is determined primarily using estimated discounted cash flows. Management considers the volume of reserves behind the asset and future NGL product and natural gas prices to estimate cash flows. The amount of additional reserves developed by future drilling activity depends, in part, on expected natural gas prices. Projections of reserves, drilling activity and future commodity prices are inherently subjective and contingent upon a number of variable factors, many of which are difficult to forecast. Any significant variance in any of these assumptions or factors could materially affect future cash flows, which could result in the impairment of an asset.

        For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value, less the cost to sell, to determine if impairment is required. Until the assets

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are disposed of, an estimate of the fair value is re-determined when related events or circumstances change.

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

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

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

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

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

        SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, established accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception. To the extent derivative instruments designated as cash flow hedges are effective, changes in fair value are recognized in other comprehensive income until the underlying hedged item is recognized in earnings. Effectiveness is evaluated by the derivative instrument's ability to offset changes in fair value or cash flows of the underlying hedged item. Any change in the fair value resulting from ineffectiveness is recognized immediately in earnings. Changes in the fair value of derivative instruments designated as fair value hedges, as well as the changes in the fair value of the underlying hedged item, are recognized currently in earnings. Any differences between the changes in the fair values of the hedged item and the derivative instrument represent gains or losses from ineffectiveness. To the extent the Partnership elects hedge accounting treatment for specific derivatives, the Partnership formally documents, designates and assesses the effectiveness of transactions receiving hedge accounting treatment. As of December 31, 2006 and 2005, no transactions had been designated for hedge accounting treatment. In general, the Partnership exempts those contracts that qualify as normal purchase and sale contacts from the mark-to-market requirements of SFAS 133. All other derivative instruments are marked-to-market through revenue.

        In the course of normal operations, we routinely enter into contracts such as forward physical contracts for the purchase and sale of crude oil natural gas, propane, and other NGLs, that under SFAS 133, qualify for and are designated as a normal purchase and sales contracts. Such contracts are exempted from the fair value accounting requirements of SFAS 133 and are accounted for using accrual accounting. For contracts that are not designated as normal purchase and sales contracts, the change in market value of the contracts is recorded as a component of revenue in the consolidated statements of operations.

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        The Partnership generates the majority of its revenues from natural gas gathering, processing and transmission; NGL transportation, fractionation and storage; and crude oil gathering and transportation. It enters into a variety of contract types. In many cases, the Partnership provides services under contracts that contain a combination of more than one of the arrangements described below. We provide services under the following different types of arrangements (all of which constitute midstream energy operations):

    Fee-based arrangements—Under fee-based arrangements, the Partnership receives a fee or fees for one or more of the following services: gathering, processing and transmission of natural gas; transportation, fractionation and storage of NGLs; and gathering and transportation of crude oil. The revenue the Partnership earns from these 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.

    Percent-of-proceeds arrangements—Under percent-of-proceeds arrangements, the Partnership gathers and processes natural gas on behalf of producers, sell the resulting residue gas, condensate and NGLs at market prices and remit to producers an agreed-upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, the Partnership will deliver an agreed-upon percentage of the residue gas and NGLs to the producer and sell the volumes we keep to third parties at market prices.

    Percent-of-index arrangements—Under percent-of-index arrangements, the Partnership will purchase natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount. The Partnership will then gather and deliver the natural gas to pipelines where we resell the natural gas at the index price, or at a different percentage discount to the index price.

    Keep-whole arrangements—Under 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.

    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 Partnership's gathering systems are operated more efficiently than specified per contract allowance, the Partnership is entitled to retain the difference for its own account.

        In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements. Under all of the arrangements, revenue is recognized at the time the product is delivered and title is transferred. It is upon delivery and title transfer that the Partnership meets all four revenue recognition criteria, and it is at such time that the Partnership recognizes revenue.

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

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

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

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

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

        The Partnership enters into revenue arrangements where it sells customer's gas and/or NGLs and depending on the nature of the arrangement acts as the principal or agent. Revenue from such sales is recognized gross where the Partnership acts as the Principal, under EITF 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, as the Partnership takes title to the gas and/or NGLs, has physical inventory risk and does not earn a fixed amount. Revenue is recognized net when the Partnership earns a fixed amount and does not take ownership of the gas and/or NGLs.

        Gas volumes received may be different from gas volumes delivered, resulting in gas imbalances. The Partnership records a receivable or payable for such imbalances based upon the contractual terms of the purchase agreements. The Partnership had an imbalance payable of $0.9 million and $2.6 million and an imbalance receivable of $0.7 million and $2.7 million at December 31, 2006 and 2005, respectively. Revenues for the transportation of crude are based upon regulated tariff rates and the related transportation volumes and are recognized when delivery of crude is made to the purchaser or other common carrier pipeline. As described above, changes in the fair value of commodity derivative instruments are recognized currently in revenue.

        We routinely make accruals based on estimates for both revenues and expenses due to the timing of compiling billing information, receiving certain third party information and reconciling our records with those of third parties. The delayed information from third parties includes, among other things, actual volumes purchased, transported or sold, adjustments to inventory and invoices for purchases, actual natural gas and NGL deliveries and other operating expenses. We make accruals to reflect estimates for these items based on our internal records and information from third parties. Most of the estimated accruals are reversed in the following month when actual information is received from third parties and our internal records have been reconciled.

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

        Emerging Issues Task Force Issue No. 03-06 ("EITF 03-06") "Participating Securities and the Two-Class Method under FASB Statement No. 128" addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to

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participate in dividends and earnings of the entity. EITF 03-06 provides that the general partner's interest in net income is to be calculated based on the amount that would be allocated to the general partner if all the net income for the period were distributed, and not on the basis of actual cash distributions for the period. The application of EITF 03-06 may have an impact on earnings per limited partner unit in future periods if there are material differences between net income and actual cash distributions or if other participating securities are issued.

        The following table sets forth the computation of basic and diluted earnings per limited partner unit. The net income available to limited partners and the weighted average limited partner units outstanding have been adjusted for instruments considered common unit equivalents in 2006, 2005 and 2004:

 
  Year ended December 31,
 
 
  2006
  2005
  2004
 
 
  (in thousands, except per unit data)

 
Numerator for basic and diluted earnings per limited partner unit:                    
Net income   $ 70,084   $ 2,355   $ 9,962  
Less:                    
  General partner's incentive distribution paid     (11,301 )   (4,163 )   (1,355 )
   
 
 
 
Sub-total     58,783     (1,808 )   8,607  
Plus:                    
  Allocated depreciation expense attributable to the general partners contribution for construction of the Cobb Gas Extraction Plant     106          
  Participation plan allocation     13,485     2,055     2,296  
   
 
 
 
Net income before GP interest     72,374     247     10,903  
Less:              
  General Partner's 2% interest     (1,447 )   (5 )   (218 )
  Additional earnings allocated to general partners              
   
 
 
 
Net income available to limited partners under EITF 03-6   $ 70,927   $ 242   $ 10,685  
   
 
 
 
Denominator:                    
  Denominator for basic earnings per limited partner unit-weighted average number of limited partner units     28,966     21,790     16,302  
Effect of dilutive securities:              
  Weighted-average of restricted units outstanding     132     68     52  
   
 
 
 
  Denominator for diluted earnings per limited partner unit-weighted average number of limited partner units     29,098     21,858     16,354  
   
 
 
 
               
Basic net income per limited partner unit   $ 2.45   $ 0.01   $ 0.66  
   
 
 
 
Diluted net income per limited partner unit   $ 2.44   $ 0.01   $ 0.65  
   
 
 
 

        The Partnership adopted Statement of Financial Accounting Standards ("SFAS") No. 123R, Share-Based Payment on January 1, 2006, using the modified prospective method. Prior to adopting SFAS No. 123R, the Partnership elected to measure compensation expense for equity-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25 ("APB 25"), Accounting for Stock Issued to Employees.

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

        MarkWest Hydrocarbon has also entered into arrangements with certain directors and employees of the Company referred to as the Participation Plan. Under this plan, MarkWest Hydrocarbon sells subordinated units of the Partnership or interests in the Partnership's general partner, under a purchase and sale agreement. Both the subordinated unit and general partner interest transactions are considered compensatory arrangements due to the put-and-call provisions and the associated valuation being based on a formula instead of an independent third party valuation. The subordinated units convert to common units after a holding period. Historically, MarkWest Hydrocarbon has settled the subordinated units for cash when individuals leave the Company. The general partner interests have no definite term, but historically have been settled for cash when the employee leaves the Company. Under SFAS 123R, the subordinated units and general partner interests are classified as liability awards. As a result, MarkWest Hydrocarbon is required to mark to market the subordinated unit and general partner interest valuations at the end of each period.

        Under Topic 1-B of the codification of the Staff Accounting Bulletins, Allocation of Expenses And Related Disclosure In Financial Statements of Subsidiaries, Divisions Or Lesser Business Components of Another Entity, compensation expense related to services provided by MarkWest Hydrocarbon's employees and directors recognized under the Participation Plan should be allocated to the Partnership. The allocation is based on the percent of time that each employee devotes to the Partnership. Compensation attributable to interests that were sold to individuals who serve on both the Partnership's board of directors of the Partnership's General Partner and on the board of directors of MarkWest Hydrocarbon is allocated equally.

        These charges are included in selling, general and administrative expenses and are allocated to the general partner pursuant to the Partnership Agreement. Assuming the compensation cost for the Long-Term Incentive Plan and the Participation Plan had been determined based on the fair-value methodology of SFAS No. 123R, the net income and earnings per share would have been the same as reported on the financial statements for the year ended December 31, 2005, and 2004, respectively.

        The Partnership is not a taxable entity for federal income tax purposes. As such, the Partnership does not directly pay federal income tax. The Partnership's taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of income, is

74


includable in the federal income tax returns of each partner. The aggregate difference in the basis of the Partnership's net assets for financial and income tax purposes cannot be readily determined as the Partnership does not have access to information about each partner's tax attributes related to the Partnership.

        The Texas legislature passed House Bill 3, 79th Leg., 3d C.S. (2006) ("H.B.3") that was signed into law on May 18, 2006. H.B. 3 significantly reforms the Texas franchise tax system and replaces it with a new Texas margin tax system. The margin tax expands the type of entities subject to tax to generally include all active business entities. The new margin tax also will apply to common entity types that are not currently subject to tax, including general and limited partnerships. The margin tax is effective for all reports due on or after January 1, 2008. The 2008 report would be completed on the new margin tax base reflecting 2007 activity.

        The Texas margin tax law causes the Partnership to be subject to an entity-level tax on the portion of its income that is generated in Texas beginning with tax year ending in 2007. The Texas margin tax will be imposed at a maximum effective rate of 1.0%. Imposition of such a tax on the Partnership by Texas reduces the cash available for distribution to unitholders. Consistent with the principles of accounting for income taxes, the Partnership recorded a deferred tax liability and expense of $0.8 million in 2006, related to the Partnership's temporary differences that are expected to reverse in future periods when the tax will apply.

Recent Accounting Pronouncements

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

        In June 2006 the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes ("FIN 48"). The interpretation clarifies the accounting for uncertainty in income taxes recognized in a company's financial statements in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes. Specifically, the pronouncement prescribes a "more likely than not" recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. The interpretation is effective for

75



fiscal years beginning after December 15, 2006. The Partnership is currently evaluating the potential impact of FIN 48 on the consolidated financial statements.

        In September 2006 the FASB issued SFAS No. 157, Fair Value Measurements ("SFAS No. 157"). SFAS No. 157 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years, with early adoption permitted. The Partnership has not yet determined the impact, if any, the implementation of SFAS No. 157 may have on the consolidated financial statements of the Partnership.

        In September 2006 the Securities and Exchange Commission ("SEC") issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements ("SAB 108"). SAB 108 provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. The SEC staff believes that registrants should quantify errors using both a balance sheet and an income statement approach and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. The Partnership adopted SAB 108 on January 1, 2006 and it did not have a material effect on the Partnership's consolidated financial statements.

        The Financial Accounting Standards Board ("FASB") has issued Statement No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, which permits an entity to measure certain financial assets and financial liabilities at fair value. The Statement's objective is to improve financial reporting by allowing entities to mitigate volatility in reported earnings caused by the measurement of related assets and liabilities using different attributes, without having to apply complex hedge accounting provisions. Under Statement No. 159, entities that elect the fair value option will report unrealized gains and losses in earnings at each subsequent reporting date. The fair value option may be elected on an instrument-by-instrument basis, with a few exceptions, as long as it is applied to the instrument in its entirety. The fair value option election is irrevocable, unless a new election date occurs. The new Statement establishes presentation and disclosure requirements to help financial statement users understand the effect of the entity's election on its earnings, but does not eliminate disclosure requirements of other accounting standards. Assets and liabilities that are measured at fair value must be displayed on the face of the balance sheet. Statement No. 159 is effective as of the beginning of an entity's first fiscal year beginning after November 15, 2007. Early adoption is permitted as of the beginning of the previous fiscal year provided that the entity (1) makes that choice in the first 120 days of that fiscal year, (2) has not yet issued financial statements, and (3) elects to apply the provisions of SFAS No. 157, Fair Value Measurements. The Partnership has not yet determined the impact, if any, the implementation of SFAS No. 159 may have on the consolidated financial statements of the Partnership.


ITEM 7A.    Quantitative and Qualitative Disclosures About Market Risk

        Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity price changes and, to a lesser extent, interest rate changes.

        The Partnership's primary risk management objective is to reduce volatility in its cash flows arising from changes in commodity prices related to future sales of natural gas, NGLs and crude oil. Swaps and futures contracts may allow the Partnership to reduce volatility in its realized margins as realized losses or gains on the derivative instruments generally are offset by corresponding gains or losses in the

76


Partnership's sales of physical product. While we largely expect our realized derivative gains and losses to be offset by increases or decreases in the value of our physical sales, we will experience volatility in reported earnings due to the recording of unrealized gains and losses on our derivative positions that will have no offset. The volatility in any given period related to unrealized gains or losses can be significant to the overall results of the Partnership, however, we ultimately expect those gains and losses to be offset when they become realized. A committee, comprised of the senior management team of our general partner, oversees all of our derivative activity.

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

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

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

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

77



        The following table includes information on MarkWest Energy's specific derivative positions at December 31, 2006:

Current asset (liability) mark-to-market positions (in thousands, except fixed price):

Fixed Swaps(1)

  Contract Period
  Fixed Price(4)
  Fair Value
 
Crude—390 Bbl/d   Jan-Dec 2007   $ 68.46   $ 473  
Crude—600 Bbl/d   Jan-Dec 2007     64.77     (58 )

Ethane—50,000 Gal/d

 

Jan-Mar 2007

 

 

0.78

 

 

736

 
             
 
              $ 1,151  
             
 

Basis Swaps


 

Contract Period


 

Fair Value


 
Natural Gas—14,000 MMBtu/d   Jan-Oct 2007   $ (33 )
       
 

Options (puts)(2)


 

Contract Period


 

Floor


 

Fair Value

Ethane—50,000 Gal/d   Apr-Jun 2007   $ 0.65   $ 7
Ethane—50,000 Gal/d   July-Sep 2007     0.65    
Ethane—50,000 Gal/d   Oct-Dec 2007     0.65    
              $ 7
             

Collars(3)


 

Contract Period


 

Floor(4)


 

Cap(4)


 

Fair Value

Crude—1,105 Bbl/d   Jan-Dec 2007   $ 69.08   $ 82.43   $ 2,469

Propane—23,000 Gal/d

 

Jan-Mar 2007

 

 

1.05

 

 

1.28

 

 

286
Propane—30,000 Gal/d   Apr-Jun 2007     0.96     1.16     240
Propane—30,000 Gal/d   Jul-Sep 2007     0.97     1.16    
Propane—30,000 Gal/d   Oct-Dec 2007     0.98     1.18    
                   
                    $ 2,995
                   
 
Total current asset (liability) mark-to-market positions

 

$

4,120
                   

78


Non-current asset (liability) mark-to-market positions (in thousands except Floor and Cap):

Collars(3)

  Contract Period
  Floor(4)
  Cap(4)
  Fair Value
 
Crude—1,476 Bbl/d   Jan-Mar 2008   $ 69.76   $ 79.01   $ 688  
Crude—550 Bbl/d   Jan-Dec 2008     64.48     73.98     236  
Crude—1,473 Bbl/d   Apr-Jun 2008     69.48     78.66     627  
Crude—1,437 Bbl/d   Jul-Sep 2008     68.90     78.32     566  
Crude—1,473 Bbl/d   Oct-Dec 2008     68.41     77.85     550  
Crude—925 Bbl/d   Jan-Dec 2008     65.00     68.78     (172 )
Crude—550 Bbl/d   Jan-Dec 2009     63.13     72.58     92  
Crude—450 Bbl/d   Jan-Mar 2009     63.00     70.00     (72 )
Crude—1,925 Bbl/d   Jan-Dec 2009     63.96     68.90     (844 )
Crude—450 Bbl/d   Apr-Jun 2009     63.00     70.00     (82 )
Crude—450 Bbl/d   Jul-Sep 2009     63.00     70.00     (91 )
Crude—450 Bbl/d   Oct-Dec 2009     63.00     70.00     (101 )
                   
 
                    $ 1,397  
                   
 
 
Total non-current asset (liability) mark-to-market positions

 

$

1,397

 
                   
 

      (1)
      Forward sales to hedge our production.

      (2)
      Purchase of puts to hedge our Ethane production.

      (3)
      Forward producer collars to hedge our production.

      (4)
      A weighted average is used for grouped positions.

        A summary of MarkWest Energy's commodity derivative instruments is provided below (in thousands):

 
  December 31,
 
  2006
  2005
Fair value of derivative instruments:            
Current asset   $ 4,211   $
Current liability     91     728
Noncurrent asset     2,759    
Noncurrent liability     1,362    

        The Partnership entered into the following derivative positions subsequent to December 31, 2006:

Fixed Swaps(1)

  Contract Period
  Price(2)
Crude—325 bbl/d (sale)   Jan-Dec 2007   $ 62.11
Crude—550 bbl/d (sale)   Jan-Mar 2010     64.03
Crude—150 bbl/d (sale)   Mar-Dec 2007     62.40
Crude—2,000 bbl/d (sale)   Jan-Mar 2010     64.45

      (1)
      Forward sales to hedge our production.

      (2)
      A weighted average is used for grouped positions.

79


        Our primary interest rate risk exposure results from the revolving portion of the partnership credit facility that has a borrowing capacity of $250.0 million and was entered into on December 29, 2005. The debt related to this agreement bears interest at variable rates that are tied to either the U.S. prime rate or LIBOR at the time of borrowing. We may make use of interest rate swap agreements in the future, to adjust the ratio of fixed and floating rates in our debt portfolio.

Long-term Debt

  Interest Rate
  Lending Limit
  Due Date
  Outstanding at December 31, 2006
Partnership Credit Facility   Variable   $ 250.0 million   December 29, 2010   $ 30.0 million
2014 Senior Notes   Fixed   $ 225.0 million   November, 2014   $ 225.0 million
2016 Senior Notes   Fixed   $ 275.0 million   July, 2016   $ 275.0 million

        Based on our overall interest rate exposure at December 31, 2006, a hypothetical instantaneous increase or decrease of one percentage point in interest rates applied to borrowings under our credit facility would change earnings by approximately $0.3 million over a 12-month period.

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ITEM 8.    Financial Statements and Supplementary Data

Index to Consolidated Financial Statements

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

Report of KPMG LLP, Independent Registered Public Accounting Firm

Consolidated Balance Sheets at December 31, 2006 and 2005

Consolidated Statements of Operations for the years ended December 31, 2006 (As restated), 2005 (As restated) and 2004

Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2006, 2005 and 2004

Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 2006, 2005 and 2004

Consolidated Statements of Cash Flows for the years in the period ended December 31, 2006, 2005 and 2004

Notes to Consolidated Financial Statements for the years ended December 31, 2006, 2005 and 2004

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

81



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

        We have audited the accompanying consolidated balance sheets of MarkWest Energy Partners, L.P. and subsidiaries (the "Partnership") as of December 31, 2006 and 2005, and the related consolidated statements of operations, comprehensive income, changes in capital, and cash flows for each of the two years in the period ended December 31, 2006. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of MarkWest Energy Partners, L.P. and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

        As discussed in Note 23, the accompanying 2006 and 2005 consolidated financial statements have been restated.

        We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Partnership's internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 6, 2007 (November 2, 2007 as to the effects of the material weakness discussed in Management's Report on Internal Control Over Financial Reporting, as revised) expressed an unqualified opinion on management's assessment of the effectiveness of the Partnership's internal control over financial reporting and an adverse opinion on the effectiveness of the Partnership's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado
March 6, 2007
(November 2, 2007 as to the effects of the restatement)

82



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors
MarkWest Energy GP, L.L.C.:

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

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

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

/s/ KPMG LLP

Denver, Colorado
June 17, 2005

83



MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands)

 
  December 31,
 
 
  2006
  2005
 
ASSETS              
Current assets:              
  Cash and cash equivalents   $ 34,402   $ 20,105  
  Receivables, net of allowances of $118 and $151, respectively     86,126     110,038  
  Receivables from affiliate     4,654     7,940  
  Inventories     3,593     3,554  
  Fair value of derivative instruments     4,211      
  Other assets     3,047     6,861  
   
 
 
    Total current assets     136,033     148,498  
   
 
 
Property, plant and equipment     655,749     567,094  
Less: Accumulated depreciation     (104,863 )   (74,133 )
   
 
 
    Total property, plant and equipment, net     550,886     492,961  
   
 
 
Other assets:              
  Investment in Starfish     64,240     39,167  
  Investment in and advances to equity investee         182  
  Intangibles and other assets, net of accumulated amortization of $29,080 and $13,321 respectively     344,066     346,496  
  Deferred financing costs, net of accumulated amortization of $5,326 and $4,424, respectively     15,753     18,463  
  Fair value of derivative instruments     2,759      
  Other     1,043     326  
   
 
 
    Total other assets     427,861     404,634  
   
 
 
    Total assets   $ 1,114,780   $ 1,046,093  
   
 
 

LIABILITIES AND CAPITAL

 

 

 

 
Current liabilities:              
  Accounts payable   $ 86,479   $ 102,175  
  Payables to affiliate     1,950     3,421  
  Accrued liabilities     43,255     27,492  
  Fair value of derivative instruments     91     728  
  Current portion of long-term debt         2,738  
   
 
 
    Total current liabilities     131,775     136,554  

Long-term debt, net of current portion and original issue discount of $3,135 and $0, respectively

 

 

526,865

 

 

601,262

 
Deferred taxes     769      
Fair value of derivative instruments     1,362      
Other liabilities     1,360     1,102  
   
 
 
    Total liabilities     662,131     738,918  
   
 
 
Commitments and contingencies (Note 17)              

Capital:

 

 

 

 

 

 

 
  General partner     9,631     6,788  
  Limited partners:              
  Common unitholders (31,166 and 22,139 units issued and outstanding at December 31, 2006 and 2005, respectively)     442,447     300,882  
  Subordinated unitholders (2,400 and 3,600 units issued and outstanding at December 31, 2006 and 2005, respectively)     571     (495 )
   
 
 
    Total capital     452,649     307,175  
   
 
 
    Total liabilities and capital   $ 1,114,780   $ 1,046,093  
   
 
 

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

84



MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

 
  Year ended December 31,
 
 
  2006
  2005
  2004
 
 
  (As restated,
see Note 23)

  (As restated,
see Note 23)

  (See Note 23)

 
Revenues:                    
Unaffiliated parties   $ 550,643   $ 478,019   $ 260,913  
Affiliates     73,636     64,922     59,026  
Derivative gain (loss)     5,632     (1,851 )   (820 )
   
 
 
 
Total revenues     629,911     541,090     319,119  
   
 
 
 
Operating expenses:                    
Purchased product costs     376,237     408,884     229,339  
Facility expenses     60,112     47,972     29,911  
Selling, general and administrative expenses     44,185     21,573     16,133  
Depreciation     29,993     19,534     15,556  
Amortization of intangible assets     16,047     9,656     3,640  
Accretion of asset retirement obligations     102     159     13  
Impairments             130  
   
 
 
 
Total operating expenses     526,676     507,778     294,722  
   
 
 
 
Income from operations     103,235     33,312     24,397  
Other income (expense):                    
Earnings (losses) from unconsolidated affiliates     5,316     (2,153 )   (65 )
Interest income     962     367     87  
Interest expense     (40,666 )   (22,469 )   (9,236 )
Amortization of deferred financing costs and original issue discount (a component of interest expense)     (9,094 )   (6,780 )   (5,236 )
Miscellaneous income, net     11,100     78     15  
   
 
 
 
Income before Texas Margin Tax     70,853     2,355     9,962  
Texas Margin Tax (Note 14)     (769 )        
   
 
 
 
Net income   $ 70,084   $ 2,355   $ 9,962  
   
 
 
 
Interest in net income:                    
General partner   $ (843 ) $ 2,113   $ (723 )
   
 
 
 
Limited partners   $ 70,927   $ 242   $ 10,685  
   
 
 
 
Net income per limited partner unit (see Note 2):                    
Basic   $ 2.45   $ 0.01   $ 0.66  
   
 
 
 
Diluted   $ 2.44   $ 0.01   $ 0.65  
   
 
 
 
Weighted average units outstanding:                    
Basic     28,966     21,790     16,302  
   
 
 
 
Diluted     29,098     21,858     16,354  
   
 
 
 
Distributions declared per common unit   $ 1.79   $ 1.60   $ 1.43  
   
 
 
 

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

85



MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

 
  Year ended December 31,
 
  2006
  2005
  2004
Net income   $ 70,084   $ 2,355   $ 9,962
  Other comprehensive income—unrealized gains on commodity derivative instruments accounted for as hedges         314     184
   
 
 
Comprehensive income   $ 70,084   $ 2,669   $ 10,146
   
 
 

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

86



MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL

(in thousands)

 
  PARTNERS' CAPITAL
   
   
 
 
  Limited Partners
   
   
   
 
 
  Common
  Subordinated
   
  Accumulated
Other
Comprehensive
Income (Loss)

   
 
 
  General
Partner

   
 
 
  Units
  Amount
  Units
  Amount
  Total
 
Balance at December 31, 2003   5,628   $ 50,992   6,000   $ 13,315   $ 1,135   $ (498 ) $ 64,944  
  Issuance of units in secondary offerings, net of offering costs   6,993     138,859           2,828         141,687  
  Issuance of units in private placement, net of offering costs   2,608     44,063           899         44,962  
  Common units issued for vested restricted units, including contribution by MarkWest Energy GP, LLC   54     1,154           25         1,179  
  Contributions by MarkWest Energy GP, LLC                 567         567  
  Participation Plan compensation expense allocated from MarkWest Hydrocarbon                 2,277         2,277  
  Distributions to partners       (14,192 )     (8,580 )   (1,848 )       (24,620 )
  Net income (loss)       6,607       4,078     (723 )       9,962  
  Other comprehensive income                     184     184  
   
 
 
 
 
 
 
 
Balance at December 31, 2004   15,283   $ 227,483   6,000   $ 8,813   $ 5,160   $ (314 ) $ 241,142  
  Issuance of units in private placement, net of offering costs   4,438     97,518           1,990         99,508  
  Common units issued for vested restricted units, including contribution by MarkWest Energy GP, LLC   18     432           9         441  
  Contributions by MarkWest Energy GP, LLC                 404         404  
  Common unit registration costs       (45 )                 (45 )
  Subordinated units converted to common units   2,400     496   (2,400 )   (496 )            
  Participation Plan compensation expense allocated from MarkWest Hydrocarbon                 2,055         2,055  
  Distributions to partners       (24,866 )     (9,190 )   (4,943 )       (38,999 )
  Net income (loss)       (136 )     378     2,113         2,355  
  Other comprehensive income                     314     314  
   
 
 
 
 
 
 
 
Balance at December 31, 2005   22,139   $ 300,882   3,600   $ (495 ) $ 6,788       $