Use these links to rapidly review the documentTable of Contents Item 8. Financial Statements and Supplemental Data



UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

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

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

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

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

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

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

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

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days.    Yes ý No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of
"accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one)

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

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

The aggregate market value of voting common stock held by non-affiliates of the registrant on June 30, 2006 was approximately $155,351,000.

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

DOCUMENTS INCORPORATED BY REFERENCE: None



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Explanatory Note

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

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

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

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

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

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

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MarkWest Hydrocarbon, Inc.
Form 10-K/A

Table of Contents



|PART I    
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|PART II   
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|PART III  
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|PART IV   
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|SIGNATURES

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

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Glossary of Terms

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

|Bbl/d                                               |  | barrels per day                                                     
|--------------------------------------------------- |  | --------------------------------------------------------------------
|Btu                                                 |  | one British thermal unit, an energy measurement                     
|Gal                                                 |  | gallons                                                             
|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            
|MMBtu/d                                             |  | one million British thermal units, an energy measurement, per day   
|MMcf/d                                              |  | one million cubic feet of natural gas per day                       
|MTBE                                                |  | methyl tertiary butyl ether                                         
|NA                                                  |  | not applicable                                                      
|Net operating margin (a non-GAAP financial measure) |  | revenues less purchased product costs                               
|NGL(s)                                              |  | natural gas liquid(s), such as propane, butanes and natural gasoline

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Forward-Looking Statements

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

Management
bases these statements on its expectations, estimates, assumptions and beliefs concerning future events affecting us and therefore they involve a number of risks and
uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied. Forward-looking statements include
statements relating to, among other things:



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



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

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PART I

Item 1. Business

General

MarkWest Hydrocarbon was founded in 1988 as a partnership and later incorporated in Delaware. We completed our initial public offering of common shares in 1996.

MarkWest
Hydrocarbon is an energy company primarily focused on marketing natural gas liquids (NGLs) and increasing shareholder value by growing MarkWest Energy Partners, L.P. ("MarkWest
Energy" or "MarkWest Energy Partners" or the "Partnership"), our consolidated subsidiary and a publicly-traded master limited partnership. MarkWest Energy Partners is engaged in the gathering,
processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids; and the gathering and transportation of crude oil.

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



Industry Overview

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

GRAPHIC

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

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

Most
natural gas produced at the wellhead is not suitable for long-haul pipeline transportation or commercial use. It must be gathered, compressed and transported via
pipeline to a central facility, and

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

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

GRAPHIC

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

The
removal and separation of individual hydrocarbons by processing is possible because of differences in physical properties. Each component has a distinctive weight, boiling point,
vapor pressure and other physical characteristics. Natural gas may also be diluted or contaminated by water, sulfur compounds, carbon dioxide, nitrogen, helium or other components. At the Javelina
facility, the Partnership also produces a high quality hydrogen stream that is delivered back to certain refinery customers.

After
being separated from natural gas at the processing plant, the mixed NGL stream is typically transported to a centralized facility for fractionation. Fractionation is the process by
which NGLs are further separated into individual, more marketable components, primarily ethane, propane, normal butane, isobutane and natural gasoline. Fractionation systems typically exist either as
an integral part of a gas processing plant or as a "central fractionator," often located many miles from the primary production and processing facility. A central fractionator may receive mixed
streams of NGLs from many processing plants.

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



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Competition

MarkWest Hydrocarbon faces competition for marketing NGL products and purchasing natural gas supplies. Competition for customers and purchases of natural gas are
based primarily on price, delivery capabilities, flexibility and maintenance of quality customer relationships.

The
Partnership faces competition for natural gas and crude oil transportation; in obtaining natural gas supplies for our processing and related services operations; in obtaining
unprocessed NGLs for fractionation; and in marketing our products and services. Competition for natural gas supplies is based primarily on the location of gas-gathering facilities and
gas-processing plants, operating efficiency and reliability, and the ability to obtain a satisfactory price for products recovered. Competitive factors affecting the Partnership's
fractionation services include availability of capacity, proximity to supply and industry marketing centers, cost efficiency and reliability of service, and, in the case of Javelina, the value of the
recovered products compared to their equivalent value when consumed at the refineries as fuel. Competition for customers is based primarily on price, delivery capabilities, flexibility, and
maintenance of high-quality customer relationships.

The
Partnership's competitors include:



We
believe the Partnership's competitive strengths include:



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To
better understand our business and results of operations discussed inItem 6. Selected Financial DataandItem
7. Management's Discussion and Analysis of Financial Condition and Results of Operation, it is important to have an understanding of three factors:



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Our Relationship with MarkWest Energy Partners

We spun off the majority of our then-existing natural gas gathering and processing and NGL transportation, fractionation and storage assets into
MarkWest Energy Partners in May 2002, just before the Partnership completed its initial public offering. At the time of its formation and initial public offering, we entered into four contracts
with MarkWest Energy Partners whereby MarkWest Energy Partners provides midstream services in Appalachia to us for a fee. Additionally, MarkWest Energy Partners receives 100% of all fee and
percent-of-proceeds consideration for the first 10 MMcf/d that it gathers and processes in Michigan. MarkWest Hydrocarbon retains a 70% net profit interest in the gathering and
processing income earned on quarterly pipeline throughput in excess of 10 MMcf/d. In accordance with accounting principles generally accepted in the United States ("GAAP"), MarkWest Energy Partners'
financial results are included in our consolidated financial statements. All intercompany accounts and transactions are eliminated during consolidation.

As
a result of the contracts mentioned above, the Company is one of the Partnership's largest customers. For the year ended December 31, 2006, we accounted for 13% of the
Partnership's revenues and 12% of its net operating margin (a non-GAAP financial measure, seeItem 1. BusinessContracts),
compared to 13% of revenues and 20% of net operating margin for the year ending December 31, 2005. We expect we will account for less of the Partnership's business in the future as it continues
to acquire assets and increase its customer base and diversify its business.

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

Contracts



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

In
Appalachia, we have entered into various operating agreements with one customer related to the delivery of natural gas into its transmission facilities, located upstream of MarkWest
Energy's Kenova, Boldman and Cobb facilities. Under the terms of these operating agreements, the customer has agreed to use reasonable, diligent efforts to supply these facilities with consistent
volumes of natural gas it ships on behalf of the Appalachian producers. The initial terms of our agreements with this customer run through February 9, 2015, with annual renewals thereafter.

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

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we
deem likely, will allow us to significantly reduce our exposure to commodity price risk, for approximately 25% of our keep-whole gas volumes. Under these agreements, the Company's
exposure to the keep-whole natural gas is limited in the event natural gas becomes more expensive than the NGL product sales price, thereby mitigating the risk of incurring operating
losses.

At
the closing of MarkWest Energy Partners' initial public offering on May 24, 2002, we outsourced our midstream services to the Partnership. Pursuant to the terms of the
operating agreements, we retained all the benefits and associated risks of the keep-whole contracts. We also retained our NGL marketing and natural gas supply operations and did not
contribute them to MarkWest Energy Partners.

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



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



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

Management evaluates performance on the basis of net operating margin (a non-GAAP financial measure), which is defined as income (loss) from operations, excluding facility
cost, selling, general and administrative expense, depreciation, amortization, impairments and accretion of asset retirement obligations. These charges have been excluded for the purpose of enhancing
the understanding by both management and investors of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance for



purposes of planning and forecasting. Net operating margin does not have any standardized definition and therefore is unlikely to be comparable to similar measures presented by other reporting
companies. Net operating margin results should not be evaluated in isolation of, or as a substitute for our financial results prepared in accordance with United States GAAP. Our usage of net operating
margin and the underlying methodology of excluding certain charges is not necessarily an indication of the results of operations expected in the future. The following table represents reconciliation
to the most comparable GAAP financial measure of this non-GAAP financial measure (in thousands):

|                                         |                        | Year ended December 31,
|---------------------------------------- | ---------------------- | -----------------------
|
|Revenues                                 |                        | $                      
|Purchased product costs                  |                        |                        
|                                         |                        |                        
|                                         | Net operating margin   |                        
|Facility expenses                        |                        |                        
|Selling, general and administrative      |                        |                        
|Depreciation                             |                        |                        
|Amortization of intangible               |                        |                        
|Accretion of asset retirement obligation |                        |                        
|Impairments                              |                        |                        
|                                         |                        |                        
|                                         | Income from operations |                        
|                                         |                        |                        

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

|                     |  | Fee-Based |   | Percent-of-
Proceeds(1) |   | Percent-of-
Index(2) |   | Keep-Whole(3) |   | Total |  
|-------------------- |  | --------- | - | ----------------------- | - | -------------------- | - | ------------- | - | ----- | -
|Revenue              |  | 13        | % | 31                      | % | 39                   | % | 17            | % | 100   | %
|Net operating margin |  | 32        | % | 38                      | % | 13                   | % | 17            | % | 100   | %

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

Impact of Recent Acquisitions on Comparability of Financial Results



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

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

|Name                    |  | Assets                                                          |  | Location                          |  | Consideration |       | Closing Date
|----------------------- |  | --------------------------------------------------------------- |  | --------------------------------- |  | ------------- | ----- | ------------
|Santa Fe                |  | Grimes gathering system                                         |  | Oklahoma                          |  | $             | 15.0  |             
|Javelina(1)             |  | Gas processing and fractionation facility                       |  | Corpus Christi, TX                |  |               | 398.8 |             
|Starfish(2)             |  | Natural gas pipeline, gathering system and dehydration facility |  | Gulf of Mexico/Southern Louisiana |  |               | 41.7  |             
|East Texas              |  | Gathering system and gas procession assets                      |  | East Texas                        |  |               | 240.7 |             
|Hobbs                   |  | Natural gas pipeline                                            |  | New Mexico                        |  |               | 2.3   |             
|Michigan Crude Pipeline |  | Common carrier crude oil pipeline                               |  | Michigan                          |  |               | 21.3  |             
|Western Oklahoma        |  | Gathering system                                                |  | Western Oklahoma                  |  |               | 38.0  |             
|Lubbock Pipeline        |  | Natural gas pipeline                                            |  | West Texas                        |  |               | 12.2  |             
|Pinnacle                |  | Natural gas pipelines and gathering systems                     |  | East Texas                        |  |               | 39.9  |             

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Segment Reporting

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

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



Our marketing group markets NGL production in Appalachia. In 2006, we sold approximately 162 million gallons of NGLs extracted at the Partnership's Siloam
facility. This includes approximately 43 million gallons sold on behalf of the Partnership at no mark-up in the standalone segment. We ship NGL products from Siloam by truck, rail
and barge. Our marketing customers include propane retailers, refineries, petrochemical plants and NGL product resellers. Most marketing sales contracts have terms of one year or less, are made on
best-efforts basis and are priced in reference to Mt.

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

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

In
Appalachia, we have entered into various operating agreements with one customer related to the delivery of natural gas into its transmission facilities, located upstream of MarkWest
Energy's Kenova, Boldman and Cobb facilities. Under the terms of these operating agreements, the customer has agreed to use reasonable, diligent efforts to supply these facilities with consistent
volumes of natural gas it ships on behalf of the Appalachian producers. The initial terms of our agreements with this customer run through February 9, 2015, with annual renewals thereafter.

Consistent
with the Partnership's operating agreements with this same customer, the Partnership enters into contracts with natural gas producers for production to occur in the
Partnership's Kenova, Boldman and Cobb facilities, before delivery of the producer's natural gas to the customer's transmission facilities. We have contractual commitments with over 250 such producers
in Appalachia. Under the provisions of our contracts with the Appalachian producers, the producers have committed all of the natural gas they deliver into the customer's transmission facilities
upstream of MarkWest Energy's Kenova, Boldman and Cobb facilities for processing.

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

In
September 2004 we entered into several new and amended agreements with one of the largest producers in the Appalachia region. These agreements, which expire in 2015 assuming
renewals we deem likely, will allow us to significantly reduce our exposure to commodity price risk, for approximately 25% of our keep-whole gas volumes. Under these agreements, the
Company's exposure to the keep-whole natural gas is limited in the event natural gas becomes more expensive than the NGL product sales price, thereby mitigating the risk of incurring
operating losses.

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



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



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

Regulatory Matters

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

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



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



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

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

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

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

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

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

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

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

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

Environmental Matters



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

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

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



The Partnership's processing and fractionation plants, pipelines, and associated facilities are subject to multiple environmental obligations and potential
liabilities under a variety of stringent and comprehensive federal, state and local laws and regulations. Such laws and regulations affect many aspects of the Partnership's present and future
operations, and generally require it to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals, with respect to air emissions, water
quality, wastewater discharges, and solid and hazardous waste management. Failure to comply with these stringent and comprehensive requirements may expose the Partnership to fines, penalties and/or
interruptions in its operations that could influence future results of operations.

The
Partnership believes that its operations and facilities are in substantial compliance with applicable environmental laws and regulations, and that the cost of continued compliance
with such laws and regulations will not have a material adverse effect on its results of operations or financial condition. The Partnership cannot ensure, however, that existing environmental laws and
regulations will not be revised or that new laws and regulations will not be adopted or become applicable to it. The clear trend in environmental law is to place more restrictions and limitations on
activities that may be perceived to affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental-regulation compliance or remediation,
and actual future expenditures may be different from the amounts the Partnership currently anticipates. Revised or additional environmental requirements that result in increased compliance costs or
additional operating

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restrictions,
particularly if those costs are not fully recoverable from the Partnership's customers, could have material adverse effect on its business, financial condition, results of operations and
cash flow.



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

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



The previous owner/operator of the Partnership's Boldman and Cobb facilities has been, or is currently involved in, investigatory or remedial activities with
respect to the real property underlying these facilities. These arise out of a September 1994 "Administrative Order by Consent for Removal Actions" with EPA Regions II, III, IV, and V; and an
"Agreed Order" entered into with the Kentucky Natural Resources and Environmental Protection Cabinet in October 1994. The previous owner/

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



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



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

Pipeline Safety Regulations

Our pipelines are subject to regulation by the U.S. Department of Transportation ("DOT") under the Pipeline Safety Act of 1992, as amended the newly enacted
Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, (collectively the "Pipeline Safety Acts"), and the Hazardous Liquid Pipeline Safety Act of 1979 ("HLPSA"), as amended; and the
Pipeline Integrity Management ("PIM") in High Consequence Areas (Gas Transmission Pipelines) amendment to 49 CFR Part 192, effective February 14, 2004, relating to the design,
installation, testing, construction, operation, replacement and management of pipeline facilities. The Pipeline Safety Act of 1992 required the Research and Special Programs Administration of the DOT
to consider environmental impacts, as well as its traditional public safety mandate, when developing pipeline safety regulations. The DOT's pipeline operator qualification rules require minimum
qualification requirements for personnel performing operations and maintenance activities on hazardous liquid pipelines. HLPSA covers crude oil, carbon dioxide, NGL and petroleum products pipelines
and requires any entity which owns or operates pipeline facilities to comply with the regulations under HLPSA, to permit access to and allow copying of records and to make certain reports and provide
information as required by the Secretary of Transportation. The Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) amendment to 49 CFR Part 192 (PIM) requires
operators of gas transmission pipelines to ensure the integrity of their pipelines through hydrostatic pressure testing, the use of in-line inspection tools or through
risk-based direct assessment techniques. The Pipeline Inspection, Protection,

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Enforcement,
and Safety Act of 2006 expands the DOT's authority and calls for additional studies and additional regulations to be promulgated in many areas, including integrity management, corrosion
control, incident reporting, inspection and enforcement orders. While we believe that our pipeline operations are in substantial compliance with applicable requirements, due to the possibility of new
or amended laws and regulations, or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with the requirements will not have a material adverse effect on
our results of operations or financial position.

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

Employee Safety

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

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

Employees

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

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was
renewed on July 11, 2005, for a term of three years. The agreement covers only hourly, non-supervisory employees. We consider labor relations to be satisfactory at this time.

Available Information

Our principal executive office is located at 1515 Arapahoe Street, Tower 2, Suite 700, Denver, Colorado, 80202-2126. Our telephone number is
303-925-9200. Our common stock trades on the American Stock Exchange under the symbol "MWP." You can find more information about us at our Internet website, www.markwest.com.
Our Annual Report on Form 10-K/A, our Quarterly Reports on Form 10-Q, our current reports on Form 8-K and any amendments to those reports are
available free of charge through our internet website as soon as reasonably practicable after we electronically file or furnish such material with the Securities & Exchange Commission.

Item 1A. Risk Factors

In addition to the other information set forth elsewhere in this Form 10-K/A, you should carefully consider the following factors when
evaluating MarkWest Hydrocarbon.

Risks Inherent in Our Business



A significant decline in MarkWest Energy Partners' earnings and/or cash distributions would have a corresponding negative impact on us. For more information on
these earnings and cash distributions, please see MarkWest Energy Partners' 2006 Annual Report on Form 10-K/A.



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

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



Further,
unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the
benefits of an acquisition. Following an acquisition, the Partnership may discover previously unknown liabilities

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subject
to the same stringent environmental laws and regulations relating to releases of pollutants into the environment and environmental protection as the Partnership's existing plants, pipelines
and facilities. If so, the Partnership's operation of these new assets could cause us to incur increased costs to attain or maintain compliance with such requirements. If the Partnership consummates
any future acquisition, its capitalization and results of operation may change significantly, and shareholders will not have the opportunity to evaluate the economic, financial and other relevant
information that we will consider in determining the application of these funds and other resources.

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



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

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



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

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



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



The Partnership has substantial indebtedness and other financial obligations. Subject to the restrictions governing the Partnership's indebtedness and other
financial obligations, and the indenture governing their outstanding notes, the Partnership may incur significant additional indebtedness and other financial obligations.

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



Furthermore,
these consequences could limit the Partnership's ability, and the ability of the its subsidiaries, to obtain future financings, make needed capital expenditures, withstand a
future downturn in the its business or the economy in general, conduct operations or otherwise take advantage of business opportunities that may arise. The Partnership's existing credit facility
contains covenants requiring us to maintain specified financial ratios and satisfy other financial conditions, which may limit our ability to grant liens on its assets, make or own certain
investments, enter into any swap contracts other than in the ordinary course of business, merge, consolidate, or sell assets, incur indebtedness senior to the credit facility, make distributions on
equity investments, and declare or make, directly or indirectly, any distribution on the Partnership common units. The Partnership obligations under the credit facility are secured by substantially
all of its assets and guaranteed by them and all of their

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subsidiaries,
other than the Partnership's operating company, which is the borrower under the credit facility. In particular, the Partnership may be unable to meet those ratios and conditions. Any
future breach of any of these covenants or the Partnership's failure to meet any of these ratios or conditions could result in a default under the terms of their credit facility, which could result in
acceleration of the Partnership's debt and other financial obligations. If the Partnership were unable to repay those amounts, the lenders could initiate a bankruptcy or liquidation proceeding, or
proceed against the collateral.



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

The
Partnership has no control over the level of drilling activity in the areas of its operations, the amount of reserves associated with the wells or the rate at which production from a
well will decline. In addition, they have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for
hydrocarbons, the level of
reserves, geological considerations, governmental regulations and the availability and cost of capital. Fluctuations in energy prices can greatly affect production rates and investments by third
parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. Natural gas prices reached historic highs in 2005 and
early 2006 but have declined in the second half of 2006. These recent declines in natural gas prices are beginning to have a negative impact on production activity, and if sustained, could lead to a
material decrease in such production activity and ultimately to exploration activity.

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



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



The renewal or replacement of existing contracts with the Partnership's customers at rates sufficient to maintain current revenues and cash flows depends on a
number of factors beyond its control, including competition from other gatherers, processors, pipelines, fractionators, and the price

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of,
and demand for, natural gas, NGLs and crude oil in the markets we serve. The Partnership's competitors include large oil, natural gas, refining and petrochemical companies, some of which have
greater financial resources, more numerous or greater capacity pipelines, processing and other facilities, and greater access to natural gas and NGL supplies than the Partnership does. Additionally,
the Partnership's customers that gather gas through facilities that are not otherwise dedicated to the Partnership may develop their own processing and fractionation facilities in lieu of using the
Partnership's services. Certain of the Partnership's competitors may also have advantages in competing for acquisitions, or other new business opportunities, because of their financial resources and
synergies in operations.

As
a consequence of the increase in competition in the industry, and the volatility of natural gas prices, end-users and utilities are reluctant to enter into
long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these
end-users also have the ability to switch between gas and alternative fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly
varying size and financial capacity that compete with the Partnership in the marketing of natural gas, the Partnership often competes in the end-user and utilities markets primarily on the
basis of price. The inability of the Partnership's management to renew or replace its current contracts as they expire and to respond appropriately to changing market conditions could affect its
profitability.



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

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



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:



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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.



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.

29

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



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



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



Columbia Gas is the previous or current owner of the property on which the Partnership's Kenova, Boldman, Cobb and Kermit facilities are located, and is the
previous operator of its Boldman and Cobb facilities. Columbia Gas has been, or is currently, involved in investigatory or remedial activities with respect to the real property underlying the Boldman
and Cobb facilities, pursuant to an "Administrative Order by Consent for Removal Actions" entered into by Columbia Gas and the U.S.

30

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Environmental
Protection Agency and, in the case of the Boldman facility, an "Agreed Order" with the Kentucky Natural Resources and Environmental Protection Cabinet.

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



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



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



The Partnership's operations depend upon the infrastructure that it has developed, including processing and fractionation plants, storage facilities, and various
means of transportation. Any

31

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significant
interruption at these facilities or pipelines, or the Partnership's inability to transmit natural gas or NGLs, or transport crude oil to or from these facilities or pipelines for any
reason, would adversely affect our results of operations and cash flows. Operations at the Partnership's facilities could be partially or completely shut down, temporarily or permanently, as the
result of circumstances not within its control, such as:





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



We own limited partner units representing approximately 15% of the limited partnership interests in MarkWest Energy Partners, in addition to a 2% general
partnership interest. The anticipated after-tax benefit of an investment in the limited partner units of MarkWest Energy Partners depends largely on MarkWest Energy Partners being treated
as a partnership for federal income tax purposes.

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



The Partnership's operations require skilled and experienced laborers with proficiency in multiple tasks. In recent years, a shortage of workers trained in
various skills associated with the midstream energy business has caused us to conduct certain operations without full staff, which decreases our productivity and increases our costs. This shortage of
trained workers is the result of the previous generation's experienced workers reaching the age for retirement, combined with the difficulty of

32

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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 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.



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

Item 1B. Unresolved Staff Comments

None.

33

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Item 2. Properties



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



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

|            |                                |  |                     |  |      |  |         | Year ended December 31, 2006
|----------- | ------------------------------ |  | ------------------- |  | ---- |  | ------- | ----------------------------
|
|
|East Texas: |                                |  |                     |  |      |  |         |                             
|            | East Texas processing plant    |  | Panola County, TX   |  | 2005 |  | 200,000 |                             
|Oklahoma:   |                                |  |                     |  |      |  |         |                             
|            | Arapaho processing plant       |  | Custer County, OK   |  | 2000 |  | 90,000  |                             
|Appalachia: |                                |  |                     |  |      |  |         |                             
|            | Kenova processing plant(1)     |  | Wayne County, WV    |  | 1996 |  | 160,000 |                             
|            | Boldman processing plant(1)    |  | Pike County, KY     |  | 1991 |  | 70,000  |                             
|            | Maytown processing plant(1)    |  | Floyd County, KY    |  | 2000 |  | 55,000  |                             
|            | Cobb processing plant          |  | Kanawha County, WV  |  | 2005 |  | 25,000  |                             
|            | Kermit processing plant(1) (2) |  | Mingo County, WV    |  | 2001 |  | 32,000  |                             
|Michigan:   |                                |  |                     |  |      |  |         |                             
|            | Fisk processing plant          |  | Manistee County, MI |  | 1998 |  | 35,000  |                             
|Gulf Coast: |                                |  |                     |  |      |  |         |                             
|            | Javelina processing plant(3)   |  | Corpus Christi, TX  |  | 1989 |  | 142,000 |                             

---

34

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

|            |                            |  |                 |  |      |  |         | Year ended December 31, 2006 |        
|----------- | -------------------------- |  | --------------- |  | ---- |  | ------- | ---------------------------- | -------
|
|
|Appalachia: |                            |  |                 |  |      |  |         |                              |        
|            | Siloam fractionation plant |  | South Shore, KY |  | 1957 |  | 600,000 |                              | 455,000



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

|                 |                                    |  |                                          |  |     |  |           |  |         | Year ended December 31, 2006 |        
|---------------- | ---------------------------------- |  | ---------------------------------------- |  | --- |  | --------- |  | ------- | ---------------------------- | -------
|
|
|East Texas:      |                                    |  |                                          |  |     |  |           |  |         |                              |        
|                 | East Texas gathering system        |  | Panola County, TX                        |  | 311 |  | 1990      |  | 410,000 |                              | 378,000
|Oklahoma:        |                                    |  |                                          |  |     |  |           |  |         |                              |        
|                 | Foss Lake gathering system         |  | Roger Mills, Ellis and Custer County, OK |  | 240 |  | 1998      |  | 100,000 |                              | 87,500 
|                 | Grimes gathering system(4)         |  | Beckham, Roger Mills Counties, OK        |  | 25  |  | 2005      |  | 25,000  |                              | NA     
|                 | Woodford Shale gathering system(5) |  | Hughes, Pittsburg and Coal Counties, OK  |  | 40  |  | 2006      |  | 45,000  |                              | 34,000 
|Other Southwest: |                                    |  |                                          |  |     |  |           |  |         |                              |        
|                 | Appleby gathering system           |  | Nacogdoches County, TX                   |  | 139 |  | 1990      |  | 50,000  |                              | 34,200 
|                 | Other gathering systems(6)         |  | Various                                  |  |     |  | Various   |  | 52,570  |                              | 18,300 
|Michigan:        |                                    |  |                                          |  |     |  |           |  |         |                              |        
|                 | 90-mile gas gathering pipeline     |  | Manistee, Mason and Oceana Counties, MI  |  | 90  |  | 1994-1998 |  | 35,000  |                              | 6,500  

---

35

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

|            |                         |  |                                        |  |      |  |      |  |         | Year ended December 31, 2006 |        
|----------- | ----------------------- |  | -------------------------------------- |  | ---- |  | ---- |  | ------- | ---------------------------- | -------
|
|
|Appalachia: |                         |  |                                        |  |      |  |      |  |         |                              |        
|            | Maytown to Institute(7) |  | Floyd County, KY to Kanawha County, WV |  | 100  |  | 1956 |  | 250,000 |                              | 132,000
|            | Ranger to Kenova(8)     |  | Lincoln County, WV to Wayne County, WV |  | 40   |  | 1976 |  | 831,000 |                              | 132,000
|            | Kenova to Siloam        |  | Wayne County, WV to South Shore, KY    |  | 40   |  | 1957 |  | 831,000 |                              | 389,000
|East Texas: |                         |  |                                        |  |      |  |      |  |         |                              |        
|            | East Texas liquid line  |  | Panola County, Texas                   |  | 37.5 |  | 2005 |  | 630,000 |                              | 442,300

---



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:

|          |                         |  |                                            |  |     |  |      | Design |        | Year ended
December 31, 2006 |       
|--------- | ----------------------- |  | ------------------------------------------ |  | --- |  | ---- | ------ | ------ | ---------------------------- | ------
|
|
|Michigan: |                         |  |                                            |  |     |  |      |        |        |                              |       
|          | Michigan crude pipeline |  | Manistee County, MI to Crawford County, MI |  | 250 |  | 1973 |        | 60,000 |                              | 14,500

Title to Properties



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



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

36

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

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

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

Item 3. Legal Proceedings

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

In
2005 MarkWest Hydrocarbon, the Partnership, several of its affiliates, and an unrelated co-defendant, were served with three lawsuits, which in 2006 were consolidated into
a single action captionedRicky J. Conn, et al. v. MarkWest Hydrocarbon, Inc. et al.,Floyd Circuit Court, Commonwealth of Kentucky, and Civil
Action No. 05-CI-00137 (consolidated March 27, 2006 of three cases originally filed February, 2005). These actions involved third-party claims of property and
personal injury damages sustained as a consequence of an NGL pipeline leak and an ensuing explosion and fire that occurred on November 8, 2004 in Ivel Kentucky. The pipeline was owned by an
unrelated business entity, Equitable Production Company, and leased and operated by the Partnership's subsidiary, MEA. MEA transports NGLs from the Maytown gas processing plant to MEA's Siloam
fractionator. The explosion and fire from the leaked vapors resulted in property damage to several residential structures and injuries to some of the residents.

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

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

37

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

The
Company just recently learned that a default judgment had been entered against it in May of 2006, in an action entitledRunyan v. Eclipse Realty LLC et
al, (Arapahoe County District Court, Colorado, Case No. 06CV1054, filed February 2006). The Company was not aware of having ever received a summons and was not
given any notification of a motion for default judgment. The Company is still investigating whether there ever was proper service of process. The action involves a personal injury claim by an
individual who allegedly slipped and fell due to snowy conditions while approaching the office building in which the Company was one of several tenants. Eclipse Realty, the landlord of the building,
was responsible for the maintenance and upkeep of the common areas of the office building. The Company is seeking to have the default judgment vacated, and then having the Company dismissed as an
improper party to the action. The Company also has a contractual indemnification from Eclipse Realty, the landlord of the building, and we have demanded that Eclipse Realty defend and indemnify the
Company. We are unable to predict the outcome of our motion to vacate the default judgment or our indemnification claim, but the Company does not expect at this time that the matter should have a
material adverse effect on our financial position.

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

With
regard to the Partnership's Javelina facility, MarkWest Javelina is a party with numerous other defendants to several lawsuits brought by various plaintiffs who had residences or
businesses located near the Corpus Christi industrial area, an area which included the Javelina gas processing plant, and several petroleum, petrochemical and metal processing and refining operations.
These suits,Victor Huff v. ASARCO Incorporated, et al. (Cause No. 98-01057-F, 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 theGonzalescase cited above); andEsmerejilda G. Valasquez, et al. v. Occidental Chemical Corp., et
al.,

38

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Case
No. A-060352-C, 128thJudicial District, Orange County, Texas, original petition filed July 10, 2006; as refiled from previously dismissed petition
captionedJesus 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 Gonzalesaction was settled in early 2006 pursuant to a mediation held December 9, 2005. The other actions have been and are being vigorously
defended and, based on initial evaluation and consultations; it appears at this time that these actions should not have a material adverse impact on the Partnership or us.

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

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

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

39

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PART II

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

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

|Quarter ended      |  | High |       | Low |   | Dividend |  | Record Date |       | Payment Date
|------------------ |  | ---- | ----- | --- | - | -------- |  | ----------- | ----- | ------------
|December 31, 2006  |  | $    | 49.34 |     | $ | 27.10    |  | $           | 0.300 |             
|September 30, 2006 |  |      | 28.11 |     |   | 24.49    |  |             | 0.280 |             
|June 30, 2006      |  |      | 22.95 |     |   | 18.54    |  |             | 0.240 |             
|March 31, 2006     |  |      | 22.64 |     |   | 19.92    |  |             | 0.159 |             
|December 31, 2005  |  | $    | 23.17 |     | $ | 19.14    |  | $           | 0.114 |             
|September 30, 2005 |  |      | 24.50 |     |   | 20.05    |  |             | 0.114 |             
|June 30, 2005      |  |      | 22.72 |     |   | 18.05    |  |             | 0.091 |             
|March 31, 2005     |  |      | 22.04 |     |   | 15.61    |  |             | 0.091 |             

Dividend Policy

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

Stock Dividend

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

Securities Authorized for Issuance under Equity Compensation Plans

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

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

40

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

|                                                            |                                              | 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:     |                                              |                                                                                             |         |                                                                                |   |                                                                                             
|MarkWest Hydrocarbon                                        |                                              |                                                                                             |         |                                                                                |   |                                                                                             
|                                                            | 1996 Stock Incentive Plan(stock options)    |                                                                                             | 65,635  |                                                                                | $ | 7.48                                                                                        
|                                                            | 1996 Stock Incentive Plan(restricted stock) |                                                                                             | 30,793  |                                                                                |   |                                                                                            
|                                                            | 2006 Stock Incentive Plan(restricted stock) |                                                                                             | 10,900  |                                                                                |   |                                                                                            
|                                                            |                                              |                                                                                             |         |                                                                                |   |                                                                                             
|Total                                                       |                                              | 107,328                                                                                     |         |                                                                                |  |                                                                                             
|                                                            |                                              |                                                                                             |         |                                                                                |   |                                                                                             
|Equity compensation plans not approved by security holders: |                                              |                                                                                             |         |                                                                                |   |                                                                                             
|MarkWest Energy Partners                                    |                                              |                                                                                             |         |                                                                                |   |                                                                                             
|                                                            | Long-Term Incentive Plan(restricted units)  |                                                                                             | 125,200 |                                                                                |   |                                                                                            
|                                                            | Long-Term Incentive Plan(unit options)      |                                                                                             |        |                                                                                |   |                                                                                            
|                                                            |                                              |                                                                                             |         |                                                                                |   |                                                                                             
|Total                                                       |                                              | 125,200                                                                                     |         |                                                                                |  |                                                                                             
|                                                            |                                              |                                                                                             |         |                                                                                |   |                                                                                             

---

Item 6. Selected Financial Data

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

41

---



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

|                                                                                                             |                                                                                                        | Year ended December 31,                                     |       
|------------------------------------------------------------------------------------------------------------ | ------------------------------------------------------------------------------------------------------ | ----------------------------------------------------------- | ------
|
|
|Statement of Operations:                                                                                     |                                                                                                        |                                                             |       
|Revenues:                                                                                                    |                                                                                                        |                                                             |       
|                                                                                                             | Revenue                                                                                                |                                                             | $     
|                                                                                                             | Derivative gain (loss)                                                                                 |                                                             |       
|                                                                                                             |                                                                                                        |                                                             |       
|                                                                                                             |                                                                                                        | Total revenue                                               |       
|                                                                                                             |                                                                                                        |                                                             |       
|Operating expenses:                                                                                          |                                                                                                        |                                                             |       
|                                                                                                             | Purchased product costs                                                                                |                                                             |       
|                                                                                                             | Facility expenses                                                                                      |                                                             |       
|                                                                                                             | Selling, general and administrative expenses                                                           |                                                             |       
|                                                                                                             | Depreciation                                                                                           |                                                             |       
|                                                                                                             | Amortization of intangible assets                                                                      |                                                             |       
|                                                                                                             | Accretion of asset retirement obligations                                                              |                                                             |       
|                                                                                                             | Impairments                                                                                            |                                                             |       
|                                                                                                             |                                                                                                        |                                                             |       
|                                                                                                             |                                                                                                        | Total operating expenses                                    |       
|                                                                                                             |                                                                                                        |                                                             |       
|                                                                                                             |                                                                                                        | Income (loss) from operations                               |       
|                                                                                                             | Earnings (losses) from unconsolidated affiliates                                                       |                                                             |       
|                                                                                                             | Interest income                                                                                        |                                                             |       
|                                                                                                             | Interest expense                                                                                       |                                                             |       
|                                                                                                             | Amortization of deferred financing costs and original issue discount (a component of interest expense) |                                                             |       
|                                                                                                             | Gain on sale of non-operating assets                                                                   |                                                             |       
|                                                                                                             | Dividend income                                                                                        |                                                             |       
|                                                                                                             | Miscellaneous income (expense)                                                                         |                                                             |       
|                                                                                                             |                                                                                                        |                                                             |       
|                                                                                                             |                                                                                                        | Income (loss) before income taxes                           |       
|Income tax (expense) benefit:                                                                                |                                                                                                        |                                                             |       
|                                                                                                             | Current                                                                                                |                                                             |       
|                                                                                                             | Deferred                                                                                               |                                                             |       
|                                                                                                             |                                                                                                        |                                                             |       
|Income tax (expense) benefit                                                                                 |                                                                                                        |                                                             | (5,252
|                                                                                                             | Non-controlling interest in net income of consolidated subsidiary                                      |                                                             |       
|                                                                                                             |                                                                                                        |                                                             |       
|                                                                                                             |                                                                                                        | Income (loss) from continuing operations                    |       
|                                                                                                             | Income from discontinued operations                                                                    |                                                             |       
|                                                                                                             |                                                                                                        |                                                             |       
|                                                                                                             |                                                                                                        | Income (loss) before cumulative effect of accounting change |       
|                                                                                                             | Cumulative effect of change in accounting for asset retirement obligations, net of income taxes        |                                                             |       
|                                                                                                             |                                                                                                        |                                                             |       
|                                                                                                             |                                                                                                        | Net income (loss)                                           |       
|                                                                                                             |                                                                                                        |                                                             |       
|Net income (loss) from continuing operations per share:                                                      |                                                                                                        |                                                             |       
|                                                                                                             | Basic                                                                                                  |                                                             | $     
|                                                                                                             |                                                                                                        |                                                             |       
|                                                                                                             | Diluted                                                                                                |                                                             | $     
|                                                                                                             |                                                                                                        |                                                             |       
|Net income (loss) per share:                                                                                 |                                                                                                        |                                                             |       
|                                                                                                             | Basic                                                                                                  |                                                             | $     
|                                                                                                             |                                                                                                        |                                                             |       
|                                                                                                             | Diluted                                                                                                |                                                             | $     
|                                                                                                             |                                                                                                        |                                                             |       
|Weighted average number of outstanding shares of common stock (numbers adjusted to reflect stock dividends): |                                                                                                        |                                                             |       
|                                                                                                             | Basic                                                                                                  |                                                             |       
|                                                                                                             |                                                                                                        |                                                             |       
|                                                                                                             | Diluted                                                                                                |                                                             |       
|                                                                                                             |                                                                                                        |                                                             |       
|Cash dividend declared per common share                                                                      |                                                                                                        | $                                                           | 0.793 
|                                                                                                             |                                                                                                        |                                                             |       
|                                                                                                             |                                                                                                        |                                                             |       

42

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|Balance Sheet Data (at December 31): |                                    |  |   |           |   |   |           |   |   |          |   |   |         |   |   |        
|------------------------------------ | ---------------------------------- |  | - | --------- | - | - | --------- | - | - | -------- | - | - | ------- | - | - | -------
|                                     | Working capital                    |  | $ | 66,030    |   | $ | 61,156    |   | $ | 53,907   |   | $ | 44,747  |   | $ | (4,331 
|                                     | Property, plant and equipment, net |  |   | 554,335   |   |   | 494,698   |   |   | 283,193  |   |   | 232,257 |   |   | 211,518
|                                     | Total assets                       |  |   | 1,203,241 |   |   | 1,132,304 |   |   | 593,574  |   |   | 280,495 |   |   | 257,503
|                                     | Total long-term debt               |  |   | 526,865   |   |   | 608,762   |   |   | 225,000  |   |   | 126,200 |   |   | 64,223 
|                                     | Stockholder's equity               |  |   | 41,489    |   |   | 39,982    |   |   | 49,761   |   |   | 50,914  |   |   | 53,139 
|Cash Flow Data:                      |                                    |  |   |           |   |   |           |   |   |          |   |   |         |   |   |        
|Net cash flow provided by (used in): |                                    |  |   |           |   |   |           |   |   |          |   |   |         |   |   |        
|                                     | Operating activities               |  | $ | 165,969   |   | $ | 16,874    |   | $ | 26,616   |   | $ | (6,411  | ) | $ | 36,301 
|                                     | Investing activities               |  |   | (122,046  | ) |   | (445,848  | ) |   | (303,017 | ) |   | (36,887 | ) |   | (22,719
|                                     | Financing activities               |  |   | (16,047   | ) |   | 437,098   |   |   | 247,101  |   |   | 78,956  |   |   | (9,520 

---

43

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|                                 |                  | Year ended December 31,                               
|-------------------------------- | ---------------- | ------------------------------------------------------
|
|MarkWest Hydrocarbon Standalone: |                  |                                                       
|                                 | Marketing        |                                                       
|                                 |                  | Hydrocarbon frac spread sales (gallons)               
|                                 |                  | Maytown sales (gallons)                               
|                                 |                  |                                                       
|                                 |                  |                                                       
|                                 | Wholesale        |                                                       
|                                 |                  | NGL product sales (gallons)(2)                        
|MarkWest Energy Partners:        |                  |                                                       
|                                 | East Texas:(3)   |                                                       
|                                 |                  | Gathering systems throughput (Mcf/d)                  
|                                 |                  | NGL product sales (gallons)                           
|                                 | Oklahoma:        |                                                       
|                                 |                  | Foss Lake gathering systems throughput (Mcf/d)        
|                                 |                  | Woodford Shale gathering systems throughput (Mcf/d)(4)
|                                 |                  | Arapaho NGL product sales (gallons)                   
|                                 | Other Southwest: |                                                       
|                                 |                  | Appleby gathering systems throughput (Mcf/d)          
|                                 |                  | Other gathering systems throughput (Mcf/d)            
|                                 |                  | Lateral throughput volumes (Mcf/d)(5)                 
|                                 | Appalachia:(6)   |                                                       
|                                 |                  | Natural gas processed for a fee (Mcf/d)               
|                                 |                  | NGLs fractionated for a fee (Gal/d)                   
|                                 |                  | NGL product sales (gallons)                           
|                                 | Michigan:        |                                                       
|                                 |                  | Natural gas processed for a fee (Mcf/d)               
|                                 |                  | NGL product sales (gallons)                           
|                                 |                  | Crude oil transported for a fee (Bbl/d)               
|                                 | Gulf Coast:(7)   |                                                       
|                                 |                  | Natural gas processed for a fee (Mcf/d)               
|                                 |                  | NGLs fractionated for a fee (Bbl/d)                   

---

44

---





Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation

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

Overview

MarkWest Hydrocarbon, Inc. is an energy company primarily focused on marketing natural gas liquids and increasing shareholder value by growing MarkWest
Energy Partners, L.P., its consolidated subsidiary and a publicly-traded master limited partnership. The Partnership is engaged in the gathering, processing and transmission of natural gas; the
transportation, fractionation and storage of natural gas liquids; and the gathering and transportation of crude oil.

Our
assets consist primarily of partnership interests in the Partnership and certain processing agreements in Appalachia. As of December 31, 2006, the Company owned a 17% interest
in the Partnership. This ownership consisted of 3,738,992 common units and 1,200,000 subordinated units, representing a combined 15% limited partner interest in the Partnership, and an 89.7% ownership
interest in MarkWest Energy GP, L.L.C., the general partner of the Partnership, which in turn owns a 2% general partner interest and all of the incentive distribution rights in the Partnership. Since
the formation of the Partnership in 2002, it has grown significantly as a result of construction and acquisition of gathering and transmission pipelines and treating and processing plants. Since its
initial public offering, the Partnership has completed nine acquisitions for an aggregate purchase price of $810 million, net of working capital.

A
large portion of our cash flows consist of the distributions we receive from the Partnership on the partnership interests we own. 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 the Partnership can distribute on its units depends principally on the amount of cash generated from its operations.

Incentive
distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they
entitle us to receive 13% of all cash distributed in a quarter after each unit has received $0.275 for that quarter; 23% of all cash distributed after each unit has received $0.3125 for that quarter;
and 48% of all cash distributed after each unit has received $0.375 for that quarter.

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. As a result, our distributions from the Partnership pursuant to our ownership of common and subordinated units have
increased from $1.2 million for the quarter ended September 30, 2002 to $2.4 million for the quarter ended December 31, 2006; our distributions pursuant to our 2% general
partner interest have increased from less than $0.1 million to approximately $0.4 million; and our distributions pursuant to our incentive distribution rights have increased from zero to
$3.8 million. In total, our total distributions from our investment in the Partnership have increased from $1.3 million for the quarter ended September 30, 2002 to
$6.6 million for the quarter ended December 31, 2006. As a result, we have increased our dividend from $0.02 per share for the quarter ended March 31, 2004 (our first dividend
payout) to $0.30 per share for the quarter ended December 31, 2006.

45

---



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 may be effectuated quickly, may occur at any time and may be significant in size relative to the
Partnership's existing assets and operations. The following is a brief summary of the Partnership's acquisitions through December 31, 2006.

The
Partnership completed the Santa Fe acquisition closed on December 29, 2006 for consideration of $15.0 million. Due to the timing of the acquisition, there is no
associated activity reflected in the statement of operations in 2006.

The
Partnership completed the following two acquisitions in 2005 which are included in the results of operations from their dates of acquisition:



The
Partnership completed the following two acquisitions in 2004 which are included in the results of operations from their dates of acquisition:



Prior
to 2004 the Partnership completed four additional acquisitions which are reflected in the results of operations from their respective acquisition dates.



Subsequent to the issuance of the Company's consolidated financial statements for the year ended December 31, 2006, the Company 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 of MarkWest Energy Partners, a wholly-owned subsidiary of the Company. Accordingly, the Audit Committee of the Company
concluded that the consolidated financial statements for such periods should not be relied 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 reflect the correction of this error. The restatement involves transactions in which the Company 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 Company 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.

Results of Operations

Management evaluates performance on the basis of net operating margin (a non-GAAP financial measure), which is defined as income (loss) from
operations, excluding facility cost, selling, general and administrative expense, depreciation, amortization, impairments and accretion of asset retirement obligations. These charges have been
excluded for the purpose of enhancing the understanding by both management and investors of the underlying baseline operating performance of our contractual arrangements, which management uses to
evaluate our financial performance for purposes of planning and forecasting. Net operating margin does not have any standardized definition and therefore is unlikely to be comparable to similar
measures presented by other reporting companies. Net operating

46

---



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 our expected future results of operations, or that we will not, in fact, incur such charges in future periods.

Year ended December 31, 2006, compared to the year ended December 31, 2005

The following reconciles this non-GAAP financial measure to the most comparable GAAP financial measure for the years ended December 31, 2006
and 2005 (in thousands):

|                              |                                                                                                        | MarkWest
Hydrocarbon
Standalone                                                                  |   | MarkWest
Energy Partners |         | Consolidating
Entries |         | Total   |  
|----------------------------- | ------------------------------------------------------------------------------------------------------ | ------------------------------------------------------------------------------------------------ | - | ------------------------ | ------- | --------------------- | ------- | ------- | -
|Year ended December 31, 2006: |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  
|Revenues:                     |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  
|                              | Revenue                                                                                                |                                                                                                  | $ | 278,655                  |         | $                     | 624,279 |         | $
|                              | Derivative gain                                                                                        |                                                                                                  |   | 4,751                    |         |                       | 5,632   |         |  
|                              |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Total revenue                                                                                    |   |                          | 283,406 |                       |         | 629,911 |  
|                              | Purchased product costs                                                                                |                                                                                                  |   | 239,359                  |         |                       | 376,237 |         |  
|                              |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Net operating margin                                                                             |   |                          | 44,047  |                       |         | 253,674 |  
|                              |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  
|Operating expenses:           |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  
|                              | Facility expenses                                                                                      |                                                                                                  |   | 21,617                   |         |                       | 60,112  |         |  
|                              | Selling, general and administrative expenses                                                           |                                                                                                  |   | 18,853                   |         |                       | 44,185  |         |  
|                              | Depreciation                                                                                           |                                                                                                  |   | 1,017                    |         |                       | 29,993  |         |  
|                              | Amortization of intangible assets                                                                      |                                                                                                  |   |                         |         |                       | 16,047  |         |  
|                              | Accretion of asset retirement and lease obligations                                                    |                                                                                                  |   |                         |         |                       | 102     |         |  
|                              |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Income from operations                                                                           |   |                          | 2,560   |                       |         | 103,235 |  
|Other income (expense):       |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  
|                              | Earnings from unconsolidated affiliates                                                                |                                                                                                  |   |                         |         |                       | 5,316   |         |  
|                              | Interest income                                                                                        |                                                                                                  |   | 612                      |         |                       | 962     |         |  
|                              | Interest expense                                                                                       |                                                                                                  |   | (276                     | )       |                       | (40,666 | )       |  
|                              | Amortization of deferred financing costs and original issue discount (a component of interest expense) |                                                                                                  |   | (135                     | )       |                       | (9,094  | )       |  
|                              | Dividend income                                                                                        |                                                                                                  |   | 447                      |         |                       |        |         |  
|                              | Miscellaneous income                                                                                   |                                                                                                  |   | 437                      |         |                       | 11,100  |         |  
|                              |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Income before non-controlling interest in net income of consolidated subsidiary and income taxes |   |                          | 3,645   |                       |         | 70,853  |  
|                              | Income tax expense                                                                                     |                                                                                                  |   | (5,124                   | )       |                       | (769    | )       |  
|                              | Non-controlling interest in net income of consolidated subsidiary                                      |                                                                                                  |   |                         |         |                       |        |         |  
|                              | Interest in net income of consolidated subsidiary                                                      |                                                                                                  |   | 11,016                   |         |                       |        |         |  
|                              |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Net income                                                                                       |   | $                        | 9,537   |                       | $       | 70,084  |  
|                              |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  

47

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|                              |                                                                                                        | MarkWest
Hydrocarbon
Standalone                                                                         |   | MarkWest
Energy Partners |         | Consolidating
Entries |         | Total   |  
|----------------------------- | ------------------------------------------------------------------------------------------------------ | ------------------------------------------------------------------------------------------------------- | - | ------------------------ | ------- | --------------------- | ------- | ------- | -
|Year ended December 31, 2005: |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|Revenues:                     |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              | Revenue                                                                                                |                                                                                                         | $ | 281,362                  |         | $                     | 542,941 |         | $
|                              | Derivative loss                                                                                        |                                                                                                         |   | (1,347                   | )       |                       | (1,851  | )       |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Total revenue                                                                                           |   |                          | 280,015 |                       |         | 541,090 |  
|                              | Purchased product costs                                                                                |                                                                                                         |   | 258,188                  |         |                       | 408,884 |         |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Net operating margin                                                                                    |   |                          | 21,827  |                       |         | 132,206 |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|Operating expenses:           |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              | Facility expenses                                                                                      |                                                                                                         |   | 20,545                   |         |                       | 47,972  |         |  
|                              | Selling, general and administrative expenses                                                           |                                                                                                         |   | 11,777                   |         |                       | 21,573  |         |  
|                              | Depreciation                                                                                           |                                                                                                         |   | 1,295                    |         |                       | 19,534  |         |  
|                              | Amortization of intangible assets                                                                      |                                                                                                         |   |                         |         |                       | 9,656   |         |  
|                              | Accretion of asset retirement and lease obligations                                                    |                                                                                                         |   | 1                        |         |                       | 159     |         |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Income (loss) from operations                                                                           |   |                          | (11,791 | )                     |         | 33,312  |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|Other income (expense):       |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              | Losses from unconsolidated affiliates                                                                  |                                                                                                         |   |                         |         |                       | (2,153  | )       |  
|                              | Interest income                                                                                        |                                                                                                         |   | 693                      |         |                       | 367     |         |  
|                              | Interest expense                                                                                       |                                                                                                         |   | (153                     | )       |                       | (22,469 | )       |  
|                              | Amortization of deferred financing costs and original issue discount (a component of interest expense) |                                                                                                         |   | (199                     | )       |                       | (6,780  | )       |  
|                              | Dividend income                                                                                        |                                                                                                         |   | 392                      |         |                       |        |         |  
|                              | Miscellaneous income                                                                                   |                                                                                                         |   | 215                      |         |                       | 51      |         |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes |   |                          | (10,843 | )                     |         | 2,328   |  
|                              | Income tax benefit                                                                                     |                                                                                                         |   | 1,804                    |         |                       |        |         |  
|                              | Non-controlling interest in net income of consolidated subsidiary                                      |                                                                                                         |   |                         |         |                       | 27      |         |  
|                              | Interest in net income of consolidated subsidiary                                                      |                                                                                                         |   | 2,237                    |         |                       |        |         |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Net income (loss)                                                                                       |   | $                        | (6,802  | )                     | $       | 2,355   |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  



Revenue.Revenue decreased $2.7 million, or 1%, for the year ended December 31, 2006, compared to the
corresponding period in 2005. We realized a $14.5 million decrease in our gas marketing business due primarily to lower prices and volumes of $0.38/MMBtu ($2.0 million) and 4,200 MMBtu/d
($12.5 million), respectively. The $19.1 million decrease in revenues in our wholesale business can be attributed primarily to the expiration of a marketing arrangement that resulted in
lower volumes of 61,000 Gal/d. This decrease was partially offset by a price increase of approximately $0.05/Gal. These decreases were partially offset by an increase in our frac spread NGL revenues
of $19.8 million, an increase primarily the result of increases in prices ($0.13/Gal), offset slightly by a decrease in volumes (1,500/Gal/d). Additionally, the revaluation of our
long-term shrink obligation increased revenue by $5.8 million in the year ended December 31, 2006, compared to a $5.3 million decrease in 2005, resulting in an
$11.1 million increase for the period-over-period comparison.

Derivative gain (loss).Gains from derivative instruments increased $6.1 million during the year ended
December 31, 2006, compared to the corresponding period in 2005. This increase in gains was primarily due to the mark-to-market adjustments resulting from our election
not to adopt hedge accounting treatment on our derivative instruments. The mark-to-market adjustments resulted in a $4.1 million increase in unrealized gains, which are
non-cash items, and a $2.0 million decrease in realized losses, when comparing 2006 to 2005 results.

48

---



Purchased product costs.Purchased product costs decreased $18.8 million, or 7%, for the year
ended
December 31, 2006, compared to the corresponding period in 2005. The decrease was primarily due to our natural gas marketing business which reflected a decrease of $14.3 million. This
was primarily due to a decrease in prices and volumes of $0.41/MMBtu ($2.1 million) and 4,200 MMBtu/d ($12.2 million), respectively. Additionally, our wholesale business revenues
decreased $18.6 million which was driven by decreased volumes of nearly 61,000 Gal/d, partially offset by increased prices of $0.06/Gal. These decreases were partially offset by increases in
our frac spread purchase product costs of $8.3 million, resulting primarily from increased prices and an increase in our unrealized losses on our derivative
mark-to-market adjustments of $5.8 million.

Facility expenses.Facility expenses increased $1.1 million, or 5%, during the year ended December 31, 2006,
compared to the corresponding period of 2005. The primary reason for the increase was due to higher Siloam storage fees ($0.7 million), higher Kenova, Boldman and Cobb plant processing fees
($0.8 million), and higher ALPS transportation fees ($0.2 million). These increases were partially offset by reduced inventory losses ($0.6 million).

Selling, general and administrative expenses.Selling, general and administrative expenses increased by $7.1 million,
or 60%, during the year ended December 31, 2006, compared to the corresponding period in 2005. This increase was primarily due to a $6.1 million non-cash increase to the
participation plan compensation expense as a result of the Partnership's increased market value and increased labor and benefit costs of $0.9 million.

Income taxes.Income tax expense increased by $6.9 million due to higher pre-tax book income for the year
ended December 31, 2006, compared to the corresponding period of 2005. The 2006 estimated annual effective income tax rate varies from the statutory rate mostly due to a change in the valuation
allowance associated with the state net operating losses.



Revenue.Revenue increased $81.3 million, or 15%, for the year ended December 31, 2006, compared to the corresponding
period of 2005, mostly due to the Partnership's Javelina acquisition in





November 2005, which contributed $55.1 million. Additionally, the start-up of several new gathering system expansions in East Texas resulted in a $45.8 million increase in
revenue. These increases were partially offset by a decrease in Other Southwest of $23.1 million, which is mostly attributable to lower natural gas sales.

Derivative gain (loss).Gains from derivative instruments increased $7.5 million during the year ended
December 31, 2006, compared to the corresponding period in 2005. This increase in gains was primarily 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 $0.6 million decrease in unrealized losses, which are
non-cash items, and a $6.9 million increase in realized gains, when comparing 2006 to 2005 results.

Purchased product costs.Purchased product costs decreased $32.6 million, or 8%, during the year ended December 31,
2006, compared to the corresponding period of 2005. This decrease was primarily due to a $23.6 million decrease in Oklahoma driven by an 18% decrease in purchase prices ($1.28/MMBtu); and a
$25.3 million decrease in Other Southwest driven by lower natural gas sales. These decreases were partially offset by a $10.4 million increase in East Texas due to increases in volume
and a $5.2 million increase in Appalachia due to increases in both prices ($0.10/Gal) and volumes (5,000 Gal/d).

Facility expenses.Facility expenses increased approximately $12.1 million, or 25%, during the year ended
December 31, 2006, compared to the corresponding period of 2005. This increase was primarily

49

---



due
to the Partnership's November 2005 Javelina Acquisition, which contributed $9.0 million; a $5.2 million increase related to the new Carthage gas processing plant in East
Texas, which started operations on January 1, 2006, and a $3.0 million increase in Oklahoma due primarily to increases in compression and sales. These increases were partially offset by
a $5.4 million decrease in Appalachia due to costs incurred to repair the ALPS pipeline in 2005.

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; increases 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.

Depreciation.Depreciation expenses increased $10.5 million, or 54%, during the year ended December 31, 2006,
compared to the corresponding quarter of 2005, primarily due to the Partnership's November 2005
Javelina Acquisition, which contributed $5.4 million; and $2.9 million in East Texas primarily related to the to the new Carthage gas processing plant and Blocker gathering system.

Earnings (losses) from unconsolidated affiliates.Earnings (losses) from unconsolidated affiliates are primarily related to
the Partnership's investment in Starfish, a joint venture with Enbridge Offshore Pipelines LLC. The Partnership accounts for its 50% interest using the equity method, and the financial results for
Starfish are included as earnings (losses) from unconsolidated affiliates. During the year ended December 31, 2006, the Partnership's earnings from unconsolidated affiliates increased
$7.5 million due to the restoration of operations resulting from the completion of the majority of repairs necessary after the 2005 hurricane season.

Interest expense and amortization of deferred financing costs (a component of interest expense).Interest and amortization expense
increased $20.5 million 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
November 2005 Javelina acquisition and higher interest rates. The increase in the amortization relative to the comparable period in 2005 is attributable to deferred financing costs associated
with our debt refinancing completed in 2006. Deferred financing costs are being amortized over the terms of the related obligations, which approximate the effective interest method.

Miscellaneous income.Miscellaneous income increased by $11.0 million during the year ended December 31, 2006,
relative to the comparable period in 2005, due almost entirely to the Partnership recognizing $11.0 million of income from insurance claims, net of Starfish insurance premiums, recovered as a
result from damages from 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 for the year ended December 31, 2006, related to the Partnership's temporary differences
that are expected to reverse in future periods.

50

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Year ended December 31, 2005, compared to the year ended December 31, 2004

The following includes reconciliation to the most comparable GAAP financial measure of this non-GAAP financial measure for the years ended
December 31, 2005 and 2004 (in thousands):

|                              |                                                                                                        | MarkWest
Hydrocarbon
Standalone                                                                         |   | MarkWest
Energy Partners |         | Consolidating
Entries |         | Total   |  
|----------------------------- | ------------------------------------------------------------------------------------------------------ | ------------------------------------------------------------------------------------------------------- | - | ------------------------ | ------- | --------------------- | ------- | ------- | -
|Year ended December 31, 2005: |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|Revenues:                     |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              | Revenue                                                                                                |                                                                                                         | $ | 281,362                  |         | $                     | 542,941 |         | $
|                              | Derivative loss                                                                                        |                                                                                                         |   | (1,347                   | )       |                       | (1,851  | )       |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Total revenue                                                                                           |   |                          | 280,015 |                       |         | 541,090 |  
|                              | Purchased product costs                                                                                |                                                                                                         |   | 258,188                  |         |                       | 408,884 |         |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Net operating margin                                                                                    |   |                          | 21,827  |                       |         | 132,206 |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|Operating expenses:           |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              | Facility expenses                                                                                      |                                                                                                         |   | 20,545                   |         |                       | 47,972  |         |  
|                              | Selling, general and administrative expenses                                                           |                                                                                                         |   | 11,777                   |         |                       | 21,573  |         |  
|                              | Depreciation                                                                                           |                                                                                                         |   | 1,295                    |         |                       | 19,534  |         |  
|                              | Amortization of intangible assets                                                                      |                                                                                                         |   |                         |         |                       | 9,656   |         |  
|                              | Accretion of asset retirement and lease obligations                                                    |                                                                                                         |   | 1                        |         |                       | 159     |         |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Income (loss) from operations                                                                           |   |                          | (11,791 | )                     |         | 33,312  |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|Other income (expense):       |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              | Losses from unconsolidated affiliates                                                                  |                                                                                                         |   |                         |         |                       | (2,153  | )       |  
|                              | Interest income                                                                                        |                                                                                                         |   | 693                      |         |                       | 367     |         |  
|                              | Interest expense                                                                                       |                                                                                                         |   | (153                     | )       |                       | (22,469 | )       |  
|                              | Amortization of deferred financing costs and original issue discount (a component of interest expense) |                                                                                                         |   | (199                     | )       |                       | (6,780  | )       |  
|                              | Dividend income                                                                                        |                                                                                                         |   | 392                      |         |                       |        |         |  
|                              | Miscellaneous income                                                                                   |                                                                                                         |   | 215                      |         |                       | 51      |         |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes |   |                          | (10,843 | )                     |         | 2,328   |  
|                              | Income tax benefit                                                                                     |                                                                                                         |   | 1,804                    |         |                       |        |         |  
|                              | Non-controlling interest in net income of consolidated subsidiary                                      |                                                                                                         |   |                         |         |                       | 27      |         |  
|                              | Interest in net income of consolidated subsidiary                                                      |                                                                                                         |   | 2,237                    |         |                       |        |         |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Net income (loss)                                                                                       |   | $                        | (6,802  | )                     | $       | 2,355   |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  

51

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|                              |                                                                                                        | MarkWest
Hydrocarbon
Standalone                                                                         |   | MarkWest
Energy Partners |         | Consolidating
Entries |         | Total   |  
|----------------------------- | ------------------------------------------------------------------------------------------------------ | ------------------------------------------------------------------------------------------------------- | - | ------------------------ | ------- | --------------------- | ------- | ------- | -
|Year ended December 31, 2004: |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|Revenues:                     |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              | Revenue                                                                                                |                                                                                                         | $ | 222,082                  |         | $                     | 319,939 |         | $
|                              | Derivative loss                                                                                        |                                                                                                         |   | (3,745                   | )       |                       | (820    | )       |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Total revenue                                                                                           |   |                          | 218,337 |                       |         | 319,119 |  
|                              | Purchased product costs                                                                                |                                                                                                         |   | 185,951                  |         |                       | 229,339 |         |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Net operating margin                                                                                    |   |                          | 32,386  |                       |         | 89,780  |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|Operating expenses:           |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              | Facility expenses                                                                                      |                                                                                                         |   | 23,983                   |         |                       | 29,911  |         |  
|                              | Selling, general and administrative expenses                                                           |                                                                                                         |   | 11,999                   |         |                       | 16,133  |         |  
|                              | Depreciation                                                                                           |                                                                                                         |   | 1,339                    |         |                       | 15,556  |         |  
|                              | Amortization of intangible assets                                                                      |                                                                                                         |   |                         |         |                       | 3,640   |         |  
|                              | Accretion of asset retirement and lease obligations                                                    |                                                                                                         |   | 2                        |         |                       | 13      |         |  
|                              | Impairments                                                                                            |                                                                                                         |   |                         |         |                       | 130     |         |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Income (loss) from operations                                                                           |   |                          | (4,937  | )                     |         | 24,397  |  
|Other income (expense):       |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              | Interest income                                                                                        |                                                                                                         |   | 560                      |         |                       | 87      |         |  
|                              | Interest expense                                                                                       |                                                                                                         |   | (147                     | )       |                       | (9,236  | )       |  
|                              | Amortization of deferred financing costs and original issue discount (a component of interest expense) |                                                                                                         |   | (45                      | )       |                       | (5,236  | )       |  
|                              | Dividend income                                                                                        |                                                                                                         |   | 259                      |         |                       |        |         |  
|                              | Miscellaneous income (expense)                                                                         |                                                                                                         |   | 838                      |         |                       | (50     | )       |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes |   |                          | (3,472  | )                     |         | 9,962   |  
|                              | Income tax expense                                                                                     |                                                                                                         |   | (78                      | )       |                       |        |         |  
|                              | Non-controlling interest in net income of consolidated subsidiary                                      |                                                                                                         |   | 511                      |         |                       |        |         |  
|                              | Interest in net income of consolidated subsidiary                                                      |                                                                                                         |   | 2,136                    |         |                       |        |         |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Net income (loss)                                                                                       |   | $                        | (903    | )                     | $       | 9,962   |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  



Revenues.Revenues increased $59.3 million, or 27%, for the year ended December 31, 2005, compared to the
corresponding period of 2004. Higher volumes and better pricing drove revenue in our wholesale propane marketing business, representing a $30.9 million increase in revenue, and our gas
marketing business, representing an $18.8 million increase. NGL product revenues increased $18.5 million due to favorable pricing, offset by a decrease in volumes. Increases to revenues
were offset by a $5.2 million unfavorable mark-to-market adjustment to replacement gas that resulted from an increase in natural gas prices, and a $1.0 million
decrease in Michigan operations, primarily from a reduction in volumes.

Derivative gain (loss).Losses from derivative instruments decreased $2.4 million for the year ended
December 31, 2005, compared to the corresponding period in 2004. This decrease in losses was primarily due to the mark-to-market adjustments resulting from our election
not to adopt hedge accounting treatment on our derivative instruments. The mark-to-market adjustments resulted in a $0.1 million decrease in unrealized losses, which are
non-cash items, and a $2.3 million decrease in realized losses, when comparing 2005 to 2004 results.

Purchased product costs.Purchased product costs increased $72.2 million, or 39%, for the year ended
December 31, 2005, compared to the corresponding period of 2004. The increase was primarily due to volumes from our wholesale propane marketing business, a $30.7 million increase and our
gas

52

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marketing
business, an $18.1 million increase. NGL product costs raised $23.2 million because of higher pricing, offset by reduced volumes.

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

Selling, general and administrative expenses.Selling, general and administrative expenses decreased by $0.2 million,
or 2%, during the year ended December 31, 2005, compared to the corresponding period of 2004 as a result of a decrease in compensation expense attributed to the Participation Plan and the 1996
Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan, and an increase to allocations of selling, general and administrative expenses to the Partnership.

Income taxes.Income tax benefit increased by $1.9 million due to lower pre-tax book income for the year
ended December 31, 2005, compared to the corresponding period of 2004. The 2005 estimated annual effective income tax rate varies from the statutory rate mostly due to a change in the valuation
allowance associated with state net operating losses.



Revenues.Revenues for the year ended December 31, 2005, were higher by $223.0 million, or 70%, compared to 2004. The
increase was primarily due to higher volumes and natural gas prices in the Partnership's Oklahoma operations, $80.3 million, and Other Southwest operations, $37.2 million, as well as
operating the East Texas system for a full year, $88.5 million. Revenues reflected twelve months of activity during 2005 compared to five months of activity during 2004. Revenue also increased in
Oklahoma during the year ended December 31, 2005 relative to the corresponding period of 2004 due to increased well volumes contracted to the gathering system, higher crude oil prices enhancing
condensate sales and higher liquids revenue that resulted from ethane recovery during 2005 versus





ethane rejection during 2004 that contributed to incremental revenue of $42.0 million. In addition, Other Southwest revenues increased $21.3 million due to a 27% increase in natural gas
volumes, primarily on the Appleby and Edwards gathering systems.

Derivative gain (loss).Losses from derivative instruments increased $1.0 million for the year ended
December 31, 2005, compared to the corresponding period in 2004. This increase in losses was primarily 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 $0.6 million increase in unrealized losses, which are
non-cash items, and a $0.4 million increase in realized losses, when comparing 2005 to 2004 results.

Purchased product costs.Purchased product costs were higher during the year ended December 31, 2005, by $179.5
million, or 78%, compared to 2004. The combination of an increase in purchased volumes and price contributed to increases in Oklahoma and Other Southwest, primarily Appleby and Edwards, of
$75.5 million and $37.1 million, respectively. In addition, the Partnership's July 30, 2004, East Texas system acquisition had incremental purchased product costs of $59.6 million
due, in part, to being operational for a full year, but also higher prices.

Facility expenses.Facility expenses increased approximately $18.1 million, or 60%, during the year ended
December 31, 2005, relative to 2004. East Texas accounted for $7.2 million of the increase, related to operating the facility for a full year, as well as performing repairs and a global
overhaul of

53

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our
compressors. Appalachia increased $5.9 million due, in part, to repairs to the ALPS pipeline. Gulf Coast, acquired November 1, 2005, contributed $2.2 million to the increase.
Oklahoma, $1.3 million, and Other Southwest, $1.3 million, increased due to repairs and an overhaul of compressors.

Selling, general and administrative expenses.Selling, general and administrative expenses, which are not allocated to
segments by the Partnership, increased by $5.4 million, or 34%, during the year ended December 31, 2005, compared to 2004 as a result of the increase in incentive compensation expense of
$1.9 million, and audit and external Sarbanes-Oxley related costs of $2.1 million.

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

Earnings (losses) from unconsolidated affiliates.Earnings (losses) from unconsolidated affiliates are primarily related to
the Partnership's investment in Starfish, a joint venture with Enbridge Offshore Pipelines LLC. The Partnership accounts for its 50% interest using the equity method, and the financial results for
Starfish are included as earnings (losses) from unconsolidated affiliates. The Partnership completed their acquisition of Starfish on March 31, 2005. During the year ended December 31,
2005, the Partnership's losses from unconsolidated affiliates were by $2.2 million.

Interest expense and amortization of deferred financing costs (a component of interest expense). Interest and amortization expense
increased $14.8 million 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
2005 and 2004 acquisitions and to higher interest rates in 2005. The Partnership also incurred approximately $1.0 million in 2005 from penalty interest expense on the senior debt. The increase
in the amortization of deferred financing costs in 2005, relative to the comparable period in 2004, is attributable to costs associated with our debt refinancing completed in the fourth quarter of
2005.

Critical Accounting Policies and Estimates

Our discussion and analysis of financial condition and results of operations are based on our consolidated financial statements, prepared in accordance with
accounting principles generally accepted in the United States of America and contained within this report. The preparation of these statements requires us to make certain assumptions and estimates
that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our
assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather,
politics, global economics, mechanical problems, general business conditions and other factors. Our significant accounting policies are detailed in Note 2 to our consolidated financial
statements. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of
significant judgment by our management.



The Company generates the majority of its revenues from natural gas gathering and processing, NGL fractionation, transportation and storage, and crude oil
gathering and transportation. While all of these services constitute midstream energy operations, the Partnership provides its services pursuant to six different types of arrangements. In many cases,
the Partnership provides services under contracts that contain a combination of more than one of the arrangements. The terms of the Partnership's contracts vary based on gas quality conditions, the
competitive environment when the contracts are

54

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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.



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.



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

In
the course of normal operations, the Company routinely enters into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs, that
under SFAS 133, qualify for and are designated as a normal purchase and sales contracts. In general, the Company exempts these types of contracts from the mark-to-market
requirements of SFAS 133 and instead accounts for them 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 or purchase product costs.
The following

55

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table
summarizes our handling of derivative instruments as presented in our accompanying consolidated statements of operations:

Transaction Type

Realized gain (loss)

Unrealized gain (loss)Sales:Fixed Physical Forwards

Revenue

Derivative gain (loss)All other derivative instruments

Derivative gain (loss)

Derivative gain (loss)Purchases:Fixed Physical Forwards

Purchase product costs

Purchase product costsAll other derivative instruments

Purchase product costs

Purchase product costs


Derivative
gain (loss) in the table above are included in total revenues in the accompanying consolidated statements of operations.



The Company accounts for income taxes under the asset and liability method pursuant to the SFAS No. 109,Accounting for Income
Taxes("SFAS 109"). Under SFAS 109, deferred income taxes are recognized for the future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is
recognized in the period that includes the enactment date of the tax rate change. Realizability of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded
to write down the deferred tax assets to their net realizable value.



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



The Company evaluates its long-lived assets, including intangibles, for impairment when events or changes in circumstances warrant such a review. A
long-lived asset group is considered impaired when the estimated undiscounted cash flows from such asset group 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

56

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activity
depends, in part, on expected natural gas prices. Projections of reserves, drilling activity and future commodity prices are inherently subjective and contingent upon a number of variable
factors, many of which are difficult to forecast. Any significant variance in any of these assumptions or factors could materially affect future cash flows, which could result in the impairment of an
asset.

For
assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value, less the cost to sell, to determine if impairment is
required. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change.



The Company adopted SFAS No. 123 (revised 2004),Share-Based Payment("SFAS 123R") on
January 1, 2006, using the modified prospective method. Prior to adopting SFAS 123R, the Company 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.

Under
SFAS 123R, compensation expense is based on the fair value of the award. SFAS 123R classifies stock-based compensation as either equity or liability awards. The fair
value on the date of grant for an award classified as equity is recognized over the requisite service period, with a corresponding credit to
equity (generally, paid-in capital). The requisite service period is the period during which an individual is required to provide a service in exchange for the award. The requisite service
period is estimated based on an analysis of the terms of the share-based payment award. Compensation expense for a liability award is based on the award's fair value, remeasured at each reporting date
until the date of settlement. Additionally, compensation expense is reduced for an estimate of expected award forfeitures.



Historically, stock options were issued under the Company's 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan, (together the
"1996 Plans"). In June 2006 shareholders approved the 2006 Stock Incentive Plan (the "2006 Plan") to replace the 1996 Plans. Under SFAS 123R, our stock options are categorized as equity
awards. Compensation expense for stock options is measured based on the grant date fair value and is amortized into earnings over the service period as the options vest. While it was determined in
2005 that the Company does not intend to issue stock options in the future, they are available for issuance under the 2006 Plan. On December 1, 2006 a board resolution provided for the
accelerated vesting of 14,950 unvested stock option grants. Consequently, as of December 31, 2006 the Company had no remaining unvested options or any unrecognized compensation expense
pertaining to options.



The Company issued restricted stock under the 1996 Plans until the adoption of the 2006 Plan at which point all new shares are, and will be, issued pursuant to
the rules of the 2006 Plan. Under SFAS 123R, our restricted stock qualifies as an equity award. Accordingly, it is measured at the grant date fair value and the associated compensation expense
is recognized over the requisite service period. The restricted stock vests equally over a three year period.

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The Company has also entered into arrangements with certain directors and employees of the Company referred to as the Participation Plan. Under this plan, the
Company 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, the Company 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, the Company 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, some portion of 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 each employee devotes to the Company. Compensation attributable to interests sold to individuals who serve
on both the board of MarkWest Hydrocarbon and the Board of Directors of the Partnership's general partner is allocated equally.



The Partnership issues restricted units under the MarkWest Energy Partners, L.P. Long-Term Incentive Plan. A restricted unit is a "phantom" unit that
entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the Compensation Committee, cash equivalent to the value of a common unit. The restricted
units are treated as liability awards under SFAS 123R. As a result, the Partnership is required to mark to market the awards at the end of each reporting period. Compensation expense is
remeasured for the phantom unit grants using the market price of MarkWest Energy Partners' common units at each reporting date. The fair value of the units awarded is amortized into earnings over the
period of service and is adjusted monthly for the change in the fair value of the unvested units granted. The phantom units vest equally over a three year 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 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.

To
satisfy common unit awards, the Partnership will issue new common units, acquire common units in the open market, or use common units already owned by the general partner.

Liquidity and Capital Resources

MarkWest Hydrocarbon Standalone

Our primary source of liquidity to meet operating expenses and fund capital expenditures is cash flow from operations, principally from the marketing of NGL and
quarterly distributions received from MarkWest Energy Partners. We believe that cash flow from operations and distributions from the

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Partnership
will be sufficient to fund capital expenditures and other working capital expenditures for the foreseeable future.

On
October 13, 2006, the Company completed the repurchase of a 0.5% interest in the general partner. This purchase resulted in an increase in our ownership level in the general
partner to 89.7%. As of December 31, 2006, we still owned 89.7% of the general partner of MarkWest Energy Partners, excluding interests held by certain employees and directors but deemed owned
by the Company through the Participation Plan. The general partner of MarkWest Energy Partners owns the 2% general partner interest and all of the incentive distribution rights. The incentive
distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they entitle us to receive
13% of all cash distributed in a quarter after each unit has received $0.275 for that quarter; 23% of all cash distributed after each unit has received $0.3125 for that quarter; and 48% of all cash
distributed after each unit has received $0.375 for that quarter. For the year ended December 31, 2006, we received $8.8 million in distributions from our limited units and
$11.3 million from our general partner interest, of which $10.1 million represented payments on incentive distribution rights.

Cash
flows generated from our NGL marketing and natural gas supply operations are subject to volatility in energy prices, especially prices for NGLs and natural gas. Our cash flows are
enhanced in periods when NGL prices are high relative to the price of the natural gas we purchase to satisfy our "keep-whole" contractual arrangements in Appalachia. Conversely, they are
reduced in periods when the NGL prices are low relative to the price of natural gas we purchase to satisfy such contractual arrangements. Under "keep-whole" contracts, we retain and sell
the NGLs produced in our processing operations for third-party producers, and then reimburse or "keep-whole" the producers for the energy content of the NGLs removed through the
re-delivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas. Generally, the value of the NGLs extracted is greater than the cost of replacing those Btus with
dry gas, resulting in positive operating margins under these contracts. Periodically, natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, and the cost of keeping the
producer "whole" can result in operating losses.



In October 2004 the Company entered into a $25.0 million senior credit facility with a term of one year. The $25.0 million revolving facility
has a variable interest rate based on the base rate or the London Inter Bank Offering Rate ("LIBOR"), as discussed below. In October, November and December 2005, the Company entered into the
first, second and third amendments to the credit agreement. The first amendment to the credit facility extended the term of the original agreement to November 15, 2005. The second amendment
reduced the lending amount from $25.0 million to $16.0 million, of which $6.0 million is committed to a letter of credit, leaving $10.0 million available for revolving
loans. The second amendment also extended the term of the revolving credit to December 30, 2005. The third amendment extended the term of the revolving credit to January 31, 2006, and
reduced the lending amount from $16.0 million to $13.5 million, of which $6.0 million is committed to a letter of credit, leaving $7.5 million available for revolving
loans. On January 31, 2006, the Company entered into the first amended and restated credit agreement which reinstated the maximum lending limit of $25.0 million for a one year term. On
August 18, 2006, the Company entered into the second amended and restated credit facility which increased the size of the facility from $25 million to $55 million, increasing the
term of the agreement to three years and allowing the flexibility for MarkWest Hydrocarbon to directly invest in additional units of MarkWest Energy Partners to fund future growth opportunities.

On
February 16, 2007, the Company entered into the first amendment to the second amended and restated credit agreement, increasing the term by one year to August 20, 2010,
and providing an

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additional
$50 million of credit to enable the Company to meet margin requirements associated with its derivative instruments.

The
Company Credit Facility bears interest at a variable interest rate, plus basis points. The variable interest rate typically is based on the LIBOR; however, in certain borrowing
circumstances the rate would be based on the higher of a) the Federal Funds Rate plus 0.5-1%, and b) a rate set by the Facility's administrative agent, based on the U.S.
prime rate. The basis points correspond to the ratio of the Revolver Facility Usage to the Borrowing Base, ranging from 0.50% to 1.75% for Base Rate loans, and 1.50% to 2.75% for Eurodollar Rate
loans. The Company pays a quarterly commitment fee on the unused portion of the credit facility at an annual rate ranging from 37.5 to 50.0 basis points.

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

At
December 31, 2006, we had no debt outstanding on the Company Credit Facility and $28.0 million available for borrowing.

We
spent $0.3 million for capital expenditures for the year ending December 31, 2006. We have budgeted $3.6 million for 2007, principally for computer hardware and
software upgrades. We believe that cash on hand, cash received from quarterly distributions (including the incentive distribution rights) from MarkWest Energy Partners and projected cash generated
from our marketing operations will be sufficient to meet our working capital requirements and fund our required capital expenditures, if any, for the foreseeable future. Cash generated from our
marketing operations will depend on our operating performance, which will be affected by prevailing commodity prices and other factors, some of which are beyond our control.

MarkWest Energy Partners

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

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 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

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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 the Partnership's private and public equity and debt offerings are its primary sources of
liquidity. The timing of the Partnership's efforts to raise equity in 2006 was influenced by its failure to file in a timely manner its Annual Report on Form 10-K for the year ended
December 31, 2004, and its quarterly report on Form 10-Q for the quarter ending March 31, 2005. However, as of October 11, 2006, the Partnership has the ability
to incorporate by reference information from its future Securities and Exchange Commission ("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, the Partnership is 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 it to attempt to raise up to
$500 million by issuing debt and equity securities in the future in registered offerings.

At December 31, 2006, the Partnership and its wholly owned 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 Senior Notes") and senior notes of $271.9 million, net of an unamortized discount of $3.1 million, at a fixed
rate of 8.5%, due in July 15, 2016 (the "2016 Senior Notes"). The proceeds from these notes were used to reduce the Partnership's outstanding debt under its credit facility. Subject to
compliance with certain covenants, the Partnership may issue additional notes from time to time under the indenture pursuant to Rule 144A and Regulation S under the Securities Act of
1933. The 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 Senior Notes will mature on July 15, 2016, and interest is payable each July 15 and January 15, commencing January 15, 2007. The Partnership closed
this private placement of $200 million on July 6, 2006 and it completed the private placement of an additional $75 million under the indenture on 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 offerings to repay the term debt under the Partnership Credit Facility, and used the remaining net
proceeds to fund both capital expenditures and general corporate expenses. 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 million at December 31,
2006.

The
indenture governing the 2014 Senior Notes and the 2016 Senior Notes limits the activity of the Partnership and its restricted subsidiaries. The provisions of such 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 $19.88
per common unit. In addition,

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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 $123.3 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 retire a
portion of the term debt under the Partnership Credit Facility.

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

The
Partnership 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 between $230.0 and $240.0 million for expenditures in 2007 consisting of
approximately $235.0 million for expansion capital and $5.0 million of sustaining capital. The Partnership plans to use between $150.0 and $170.0 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 Flows

|                                                          |  | Year ended December 31, |         
|--------------------------------------------------------- |  | ----------------------- | --------
|
|
|Net cash flows provided by operating activities           |  | $                       | 165,969 
|Net cash flows used in investing activities               |  |                         | (122,046
|Net cash flows provided by (used in) financing activities |  |                         | (16,047 

Net
cash provided by operating activities increased $149.1 million during the year ended December 31, 2006, compared to the year ended December 31, 2005. This
increase resulted primarily from increases in
both our net income and that of the non-controlling interest of the Partnership of $76.0 million; an increase in non-cash equity-based compensation expense of
$17.5 million, primarily due to the Partnership's increased market value; an increase in income tax expense of $7.8 million; and an increase in our unrealized gains on derivative
instruments of $5.2 million and increases in the changes of our operating assets and liabilities totaling $43.9 million.

Net
cash used in investing activities decreased by $323.8 million during 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 $80.1 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 $71.3 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 $453.1 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 acquisitions. Distributions to the Partnership's unitholders increased to
$43.5 million in 2006 from $26.1 million in 2005.

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Dividends
to shareholders increased to $9.7 million during the year ended December 31, 2006 compared to $4.3 million in the prior year period.

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
|---------------------------------- |  | ---------------------
|
|Long-term debt                     |  | $                    
|Interest expense on debt(1)        |  |                      
|Operating leases                   |  |                      
|Purchase obligations               |  |                      
|Other long-term liabilities        |  |                      
|                                   |  |                      
|Total contractual cash obligations |  | $                    
|                                   |  |                      

---

Off-Balance Sheet Arrangements

Other than facility and equipment leasing arrangements, we do not engage in off-balance sheet financing activities.

Matters Influencing Future Results

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 the Partnership's unconsolidated affiliate, Starfish Pipeline Company were nominally impacted by Hurricane Katrina but were significantly impacted by Hurricane Rita. The
Partnership is continuing to submit insurance claims on an on-going basis relating to both business interruption and property damage and have submitted $14.5 million in claims
through January 31, 2007. The Partnership has recorded $11.0 million in insurance claims, net of Starfish insurance premiums with respect to its property loss claims, and it anticipates
additional recoveries for expenses and losses incurred as repairs proceed. As of December 31, 2006, the Partnership has not recorded any insurance recoveries related to business interruption,
due to the uncertainty around collection, but the Partnership has filed a claim for $3.5 million with its insurance carrier.

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.

The Partnership's affiliate, MEA operates the ALPS pipeline to transport NGLs from its Maytown gas processing plant to its 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 OPS Corrective Action Order, MEA

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successfully conducted a hydrostatic test of the affected portion of the ALPS pipeline in 2005 and OPS authorized a partial return to service of the affected pipeline in October 2005. As part
of its ongoing operation of the ALPS pipeline, MEA continued to perform pipeline integrity assessments and implement an in-line inspection program on the ALPS pipeline. Preliminary data
from a four mile section of its in-line inspection program identified areas for investigation and corrective action. In November 2006 MEA temporarily idled the line while additional
assessment and investigation was undertaken to address these concerns. In late January 2007, MEA received the completed report from its in-line inspection operator and consultant.
This report indicated areas of significant external corrosion or other defects in the four mile section of pipeline in which the in-line inspection was conducted. The assessment of this
completed report, coupled with other information MEA has gathered, will continue to be reviewed and MEA will work with Equitable to determine what the most appropriate corrective action may be. In the
interim, the pipeline will be maintained in idle status. MEA is trucking the NGLs produced from our Maytown plant to the Siloam fractionation facility while MEA is maintaining the pipeline in idle
status, and as a result, operations have not been interrupted. The additional transportation costs associated with the trucking are not expected to have material adverse effect on our results of
operations or financial positions.

MarkWest
Hydrocarbon, Inc. is a corporation for federal income tax purposes. As such, our federal taxable income is subject to tax at a maximum rate of 35.0% under current law and
a blended state rate of 2.8%, net of Federal benefit. We expect to have future taxable income allocated to us as a result of our investment in the Partnership and from our Appalachia processing
agreements.

We
anticipate using all of the federal net operating loss carryforwards from previous years for the year ended December 31, 2006. As a result, the amount of money available to
provide dividends to our stockholders will decrease for future distributions.

In June 2006 the Financial Accounting Standards Board ("FASB") issued Interpretation No. 48,Accounting for Uncertainty in Income
Taxesan interpretation of FASB Statement No. 109 ("FIN 48"). The Company is currently evaluating the impact of FIN 48.

Recent Accounting Pronouncements

Refer to Note 2 of the consolidated financial statements for information regarding recent accounting pronouncements.

Effects of Inflation and Pricing

We experienced increased costs during 2006, 2005 and 2004 due to increased demand for natural gas and oil related products and services. The natural gas and oil
industry is very cyclical and the demand for goods and services of natural gas and oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability
and pricing structure within the industry. Typically, as prices for natural gas and oil increase, so do all associated costs. Material changes in prices also impact the current revenue stream,
estimates of future reserves, borrowing base calculations of bank loans and values of properties in purchase and sale transactions. Material changes in prices can impact the value of natural gas and
oil companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, continued high prices for natural gas and
oil could result in increases in the costs of materials, services and personnel.

Commodity Price Sensitivity

Our earnings and cash flow are dependent on sales volumes and our ability to achieve positive sales margins on the product we sell. The volumes of our sales and
our margin on sales can be adversely affected by the prices of commodities, which are subject to significant fluctuation depending

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upon
numerous factors beyond our control, including the supply of and demand for commodity products. The supply of and demand for our products can be affected by, among other things, production
levels, industry-wide inventory levels, the availability of imports, the marketing of products by competitors, and the marketing of competitive fuels.

Seasonality

For the portion of our business that is affected by commodity prices, sales volumes also are affected by various other factors such as fluctuating and seasonal
demands for products, changes in transportation and travel patterns and variations in weather patterns from year to year. In general, we store a portion of the propane that we produce in the summer as
well as pre-purchase in the summer a portion of the natural gas that we are required to replace during the winter in accordance with our Appalachian keep-whole processing
agreements.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk

Our primary risk management objective is to manage volatility in our cash flows. A committee comprised of members of the senior management team 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 Company may also enter into futures contracts traded on the New York Mercantile Exchange ("NYMEX"). Swaps and futures contracts allow us to manage volatility in our margins because
corresponding losses or gains on the financial instruments are generally offset by gains or losses in our physical positions.

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

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

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).

MarkWest Hydrocarbon Standalone

Subsequent to the issuance of the Company's 2006 financial statements, the Company's management determined that the "MarkWest Hydrocarbon Standalone" contract
volumes as previously reported in columns "Fixed Physical Forwards" and "Fixed Swaps" incorrectly presented total volumes rather than daily volumes as noted. As a result, the contract volumes in the
"Fixed Physical Forwards"

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and
"Fixed Swaps" columns within the "MarkWest Hydrocarbon Standalone" tables herein have been restated from the amounts previously reported to appropriately reflect daily contract volumes.

MarkWest
Hydrocarbon Standalone may enter into physical and/or financial positions to manage its risks related to commodity price exposure. Due to timing of purchases and sales, direct
exposure to price volatility can be created because there is no longer an offsetting purchase or sale that remains exposed to market pricing. Through marketing and derivatives activities, direct
exposure may occur naturally, or we may choose direct exposure when we favor that exposure over frac spread risk. Beginning in 2006 MarkWest Hydrocarbon Standalone pre-purchased natural
gas for shrink requirements in future months and, for both natural gas and NGLs, entered into swaps and future sales agreements to manage frac spread risk. These derivative instruments are marked to
market.

The
following tables summarize the current derivative positions specific to MarkWest Hydrocarbon Standalone's segment at December 31, 2006 (in thousands, except price data):

|Fixed Physical Forwards                |  | Contract Period |  | Price |       | Fair Value |  
|-------------------------------------- |  | --------------- |  | ----- | ----- | ---------- | -
|Natural Gas  6,371 MMBtu/d (sale)     |  | Jan 2007        |  | $     | 10.48 |            | $
|Natural Gas  6,371 MMBtu/d (purchase) |  | Jan 2007        |  |       | 8.95  |            |  
|Natural Gas  7,143 MMBtu/d (sale)     |  | Feb 2007        |  |       | 10.76 |            |  
|Natural Gas  7,143 MMBtu/d (purchase) |  | Feb 2007        |  |       | 9.07  |            |  
|Natural Gas  6,308 MMBtu/d (sale)     |  | Apr 2007        |  |       | 7.48  |            |  
|Natural Gas  2,284 MMBtu/d (sale)     |  | May 2007        |  |       | 7.48  |            |  
|Natural Gas  4,665 MMBtu/d (sale)     |  | Jun 2007        |  |       | 7.48  |            |  
|                                       |  |                 |  |       |       |            |  
|                                       |  |                 |  |       |       |            | $
|                                       |  |                 |  |       |       |            |  

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|Fixed Swaps(1)                          |  | Contract Period |  | Price(2) |       | Fair Value |  
|--------------------------------------- |  | --------------- |  | -------- | ----- | ---------- | -
|Crude  139 Bbl/d (sale)                |  | Apr 2007        |  | $        | 63.86 |            | $
|Crude  139 Bbl/d (sale)                |  | Apr 2007        |  |          | 64.87 |            |  
|Crude  955 Bbl/d (sale)                |  | Apr-Jun 2007    |  |          | 71.33 |            |  
|Crude  18 Bbl/d (sale)                 |  | May 2007        |  |          | 63.89 |            |  
|Crude  18 Bbl/d (sale)                 |  | May 2007        |  |          | 65.35 |            |  
|Crude  121 Bbl/d (sale)                |  | Jun 2007        |  |          | 64.83 |            |  
|Crude  121 Bbl/d (sale)                |  | Jun 2007        |  |          | 65.81 |            |  
|Crude  662 Bbl/d (sale)                |  | Jul 2007        |  |          | 65.19 |            |  
|Crude  662 Bbl/d (sale)                |  | Jul 2007        |  |          | 66.17 |            |  
|Crude  698 Bbl/d (sale)                |  | Aug 2007        |  |          | 65.50 |            |  
|Crude  698 Bbl/d (sale)                |  | Aug 2007        |  |          | 66.48 |            |  
|Crude  773 Bbl/d (sale)                |  | Sep 2007        |  |          | 65.77 |            |  
|Crude  773 Bbl/d (sale)                |  | Sep 2007        |  |          | 66.75 |            |  
|Crude  1,252 Bbl/d (sale)              |  | Oct 2007        |  |          | 65.99 |            |  
|Crude  1,252 Bbl/d (sale)              |  | Oct 2007        |  |          | 66.97 |            |  
|Crude  1,383 Bbl/d (sale)              |  | Nov 2007        |  |          | 66.21 |            |  
|Crude  1,383 Bbl/d (sale)              |  | Nov 2007        |  |          | 67.19 |            |  
|Crude  1,958 Bbl/d (sale)              |  | Dec 2007        |  |          | 66.46 |            |  
|Crude  1,958 Bbl/d (sale)              |  | Dec 2007        |  |          | 67.35 |            |  
|Natural Gas  7,088 MMBtu/d (purchase)  |  | Apr 2007        |  |          | 8.16  |            |  
|Natural Gas  86,850 MMBtu/d (purchase) |  | May 2007        |  |          | 8.08  |            |  
|Natural Gas  13,167 MMBtu/d (purchase) |  | Jun 2007        |  |          | 8.16  |            |  
|Natural Gas  12,581 MMBtu/d (purchase) |  | Jul 2007        |  |          | 8.29  |            |  
|Natural Gas  12,258 MMBtu/d (purchase) |  | Aug 2007        |  |          | 8.35  |            |  
|Natural Gas  4,833 MMBtu/d (purchase)  |  | Sep 2007        |  |          | 8.38  |            |  
|IsoButane  6,231 Gal/d (sale)          |  | Jan 2007        |  |          | 1.23  |            |  
|IsoButane  4,210 Gal/d (sale)          |  | Jan-Mar 2007    |  |          | 1.17  |            |  
|IsoButane  1,974 Gal/d (sale)          |  | Jan-Mar 2007    |  |          | 1.14  |            |  
|IsoButane  4,328 Gal/d (sale)          |  | Feb 2007        |  |          | 1.16  |            |  
|IsoButane  3,007 Gal/d (sale)          |  | Feb-Mar 2007    |  |          | 1.35  |            |  
|IsoButane  1,806 Gal/d (sale)          |  | Mar 2007        |  |          | 1.28  |            |  
|Natural Gasoline  17,756 Gal/d (sale)  |  | Jan 2007        |  |          | 1.46  |            |  
|Natural Gasoline  12,446 Gal/d (sale)  |  | Jan-Mar 2007    |  |          | 1.37  |            |  
|Natural Gasoline  10,468 Gal/d (sale)  |  | Feb 2007        |  |          | 1.33  |            |  
|Natural Gasoline  10,034 Gal/d (sale)  |  | Feb-Mar 2007    |  |          | 1.59  |            |  
|Natural Gasoline  4,387 Gal/d (sale)   |  | Mar 2007        |  |          | 1.62  |            |  
|Normal Butane  21,018 Gal/d (sale)     |  | Jan 2007        |  |          | 1.20  |            |  
|Normal Butane  18,981 Gal/d (sale)     |  | Jan-Mar 2007    |  |          | 1.13  |            |  
|Normal Butane  13,879 Gal/d (sale)     |  | Feb 2007        |  |          | 1.12  |            |  
|Normal Butane  10,712 Gal/d (sale)     |  | Feb-Mar 2007    |  |          | 1.29  |            |  
|Normal Butane  5,839 Gal/d (sale)      |  | Mar 2007        |  |          | 1.28  |            |  
|Propane  211,643 Gal/d (sale)          |  | Jan 2007        |  |          | 1.09  |            |  
|Propane  3,559 Gal/d (sale)            |  | Jan-Feb 2007    |  |          | 1.05  |            |  
|Propane  71,516 Gal/d (sale)           |  | Jan-Mar 2007    |  |          | 0.96  |            |  
|Propane  178,742 Gal/d (sale)          |  | Feb 2007        |  |          | 1.06  |            |  
|Propane  23,797 Gal/d (sale)           |  | Feb-Mar 2007    |  |          | 1.18  |            |  
|Propane  25,806 Gal/d (sale)           |  | Mar 2007        |  |          | 1.13  |            |  
|                                        |  |                 |  |          |       |            |  
|                                        |  |                 |  |          |       |            | $
|                                        |  |                 |  |          |       |            |  

67

---



Forward Physical Contracts

Price(2)

Fair ValueNatural Gas  9,000 MMBtu/d

$
7.56

$
(1,417
)Current  Total MarkWest Hydrocarbon Standalone




$
(1,658
)


---



The
following table summarizes the non-current derivative positions specific to MarkWest Hydrocarbon Standalone's segment at December 31, 2006 (in thousands, except
price data):

Fixed Swaps(1)

Contract Period

Price

Fair ValueCrude  2,181 Bbl/d (sale)

Jan 2008

$
67.48

$
16Crude  2,181 Bbl/d (sale)

Jan 2008


66.59


(40
)Crude  1,956 Bbl/d (sale)

Feb 2008


67.58


12Crude  1,956 Bbl/d (sale)

Feb 2008


66.70


(35
)Crude  1,160 Bbl/d (sale)

Mar 2008


67.67


7Crude  1,160 Bbl/d (sale)

Mar 2008


66.78


(23
)Non-current  Total MarkWest Hydrocarbon Standalone

$
(63
)


---



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

December 31,2006

2005Fair value of derivative instruments:Current asset

$
5,727

$
Noncurrent asset


35


Current liability


7,385


Noncurrent liability


98





MarkWest
Hydrocarbon Standalone entered into the following derivative positions subsequent to December 31, 2006:

Fixed Physical Forwards

Contract Period

Price(2)Natural Gas  34,783 MMBtu/d (purchase)

Jan 2007

$
5.96Natural Gas  25,806 MMBtu/d (sale)

Jan 2007


6.66


68

---



Fixed Swaps(1)

Contract Period

Price(2)Natural Gas  4,069 MMBtu/d (purchase)

Apr 2008

$
8.05Natural Gas  15,531 MMBtu/d (purchase)

Apr-Jun 2008


8.01Natural Gas  5,360 MMBtu/d (purchase)

May 2008


7.93Natural Gas  5,482 MMBtu/d (purchase)

Jun 2008


7.98Natural Gas  15,755 MMBtu/d (purchase)

Jul 2008


8.05Natural Gas  15,531 MMBtu/d (purchase)

Jul-Sep 2008


8.10Natural Gas  15,755 MMBtu/d (purchase)

Aug 2008


8.11Natural Gas  16,280 MMBtu/d (purchase)

Sep 2008


8.16Natural Gas  4,069 MMBtu/d (purchase)

Apr 2009


7.56Natural Gas  15,883 MMBtu/d (purchase)

Apr-Jun 2009


7.61Natural Gas  5,360 MMBtu/d (purchase)

May 2009


7.56Natural Gas  5,482 MMBtu/d (purchase)

Jun 2009


7.56Natural Gas  15,755 MMBtu/d (purchase)

Jul 2009


7.69Natural Gas  15,710 MMBtu/d (purchase)

Jul-Sep 2009


7.73Natural Gas  15,755 MMBtu/d (purchase)

Aug 2009


7.69Natural Gas  16,280 MMBtu/d (purchase)

Sep 2009


7.69Crude  921 bbl/d (sale)

Apr 2008


64.22Crude  1,087 bbl/d (sale)

May 2008


63.95Crude  1,096 bbl/d (sale)

Jun 2008


63.93Crude  1,025 bbl/d (sale)

Jul 2008


64.08Crude  1,124 bbl/d (sale)

Aug 2008


64.22Crude  1,268 bbl/d (sale)

Sep 2008


64.53Crude  1,580 bbl/d (sale)

Oct 2008


65.37Crude  2,530 bbl/d (sale)

Nov 2008


65.52Crude  3,856 bbl/d (sale)

Dec 2008


65.51Crude  4,721 bbl/d (sale)

Jan 2009


65.52Crude  4,212 bbl/d (sale)

Feb 2009


65.45Crude  3,069 bbl/d (sale)

Mar 2009


65.33Crude  921 bbl/d (sale)

Apr 2009


63.99Crude  1,087 bbl/d (sale)

May 2009


63.65Crude  1,096 bbl/d (sale)

Jun 2009


63.60Crude  1,026 bbl/d (sale)

Jul 2009


63.67Crude  1,195 bbl/d (sale)

Aug 2009


64.00Crude  1,306 bbl/d (sale)

Sep 2009


64.23Crude  2,378 bbl/d (sale)

Oct 2009


64.69Crude  3,556 bbl/d (sale)

Nov 2009


64.78Crude  3,792 bbl/d (sale)

Dec 2009


64.71Crude  4,729 bbl/d (sale)

Jan 2010


64.60Crude  4,218 bbl/d (sale)

Feb 2010


64.55Crude  3,073 bbl/d (sale)

Mar 2010


64.55


---



69

---





MarkWest Energy Partners

The Partnership's primary risk management objective is to reduce volatility in its cash flows arising from changes in commodity prices related to future sales of
natural gas, 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 Partnership's sales of physical product. While the Partnership largely expects its realized derivative gains and losses to be offset by increases or
decreases in the value of its physical sales, it will experience volatility in reported earnings due to the recording of unrealized gains and losses on its 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, it ultimately expects those gains and losses to
be offset when they become realized.

The
following tables summarize the current derivative positions specific to MarkWest Energy Partner's segment at December 31, 2006 (in thousands, except price data):

Fixed Swaps(1)

Contract Period

Fixed Price(2)

Fair ValueCrude  390 Bbl/d (sale)

Jan-Dec 2007

$
68.46

$
473Crude  600 Bbl/d (sale)

Jan-Dec 2007


64.77


(58
)Ethane  50,000 Gal/d (sale)

Jan-Mar 2007


0.78


736$
1,151


Basis Swaps

Contract Period

Fair ValueNatural Gas  14,000 MMBtu/d

Jan-Oct 2007

$
(33
)


Options (puts)(3)

Contract Period

Floor

Fair ValueEthane  50,000 Gal/d

Apr-Jun 2007

$
0.65

$
7Ethane  50,000 Gal/d

July-Sep 2007


0.65


Ethane  50,000 Gal/d

Oct-Dec 2007


0.65


$
7


Collars(4)

Contract Period

Floor(2)

Cap(2)

Fair ValueCrude  1,105 Bbl/d

Jan-Dec 2007

$
69.08

$
82.43

$
2,469Propane  23,000 Gal/d

Jan-Mar 2007


1.05


1.28


286Propane  30,000 Gal/d

Apr-Jun 2007


0.96


1.16


240Propane  30,000 Gal/d

Jul-Sep 2007


0.97


1.16


Propane  30,000 Gal/d

Oct-Dec 2007


0.98


1.18


2,995Current  Total MarkWest Energy Partners

$
4,120


---



70

---





The
following table summarizes the non-current derivative positions specific to MarkWest Energy Partner's segment at December 31, 2006 (in thousands, except price
data):

Collars(1)

Contract Period

Floor(2)

Cap(2)

Fair ValueCrude  1,476 Bbl/d

Jan-Mar 2008

$
69.76

$
79.01

$
688Crude  550 Bbl/d

Jan-Dec 2008


64.48


73.98


236Crude  1,473 Bbl/d

Apr-Jun 2008


69.48


78.66


627Crude  1,437 Bbl/d

Jul-Sep 2008


68.90


78.32


566Crude  1,473 Bbl/d

Oct-Dec 2008


68.41


77.85


550Crude  925 Bbl/d

Jan-Dec 2008


65.00


68.78


(172
)Crude  550 Bbl/d

Jan-Dec 2009


63.13


72.58


92Crude  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
)Non-Current  Total MarkWest Energy Partners

$
1,397


---



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

December 31,2006

2005Fair value of derivative instruments:Current asset

$
4,211

$
Noncurrent asset


2,759


728Current liability


91


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

Jan-Dec 2007

$
62.11Crude  550 bbl/d

Jan-Mar 2010


64.03Crude  150 bbl/d

Mar-Dec 2007


62.40Crude  2,000 bbl/d

Jan-Mar 2010


64.45


---





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

71

---



rate
or LIBOR at the time of borrowing. The Partnership may make use of interest rate swap agreements in the future, to adjust the ratio of fixed and floating rates in its 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 |                                 
|2014 Senior Notes           |  | Fixed         |  |               | 225.0 million |          | November, 2014    |                                 
|2016 Senior Notes           |  | Fixed         |  |               | 275.0 million |          | July, 2016        |                                 

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 less than $0.1 million, net of tax, over a 12-month period.

72

---





Item 8. Financial Statements and Supplemental 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                       

73

---



Report of Independent Registered Public Accounting Firm

To
the Board of Directors and Stockholders of MarkWest Hydrocarbon, Inc.
Denver, Colorado

We
have audited the accompanying consolidated balance sheets of MarkWest Hydrocarbon, Inc. and subsidiaries (the "Company") as of December 31, 2006 and 2005, and the related consolidated
statements of operations, comprehensive income (loss), changes in stockholders' equity, and cash flows for each of the two years in the period ended December 31, 2006. These financial
statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our 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 Hydrocarbon, Inc. 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 2 to the consolidated financial statements, the Company changed its method of accounting for stock-based compensation in 2006 with the implementation of Statement of
Financial Accounting Standards No. 123R "Share-Based Payment".

As discussed in Note 24, 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 Company's internal control over financial reporting as
of December 31, 2006, based on the criteria established inInternal ControlIntegrated Frameworkissued by the Committee of
Sponsoring Organizations of the Treadway Commission and our report dated March 7, 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 Company's internal control over financial reporting and
an adverse opinion on the effectiveness of the Company's internal control over financial reporting.

|/s/ DELOITTE & TOUCHE, LLP                                                                                                                
|------------------------------------------------------------------------------------------------------------------------------------------
|Denver, Colorado
March 7, 2007
(March 21, 2007 as to Note 13)
(November 2, 2007 as to the effects of the restatement
discussed in Note 24)

74

---



Report of Independent Registered Public Accounting Firm

The
Board of Directors MarkWest Hydrocarbon, Inc.:

We
have audited the accompanying consolidated statements of operations, comprehensive income (loss), changes in stockholders' equity, and cash flows of MarkWest Hydrocarbon, Inc. and its
subsidiaries for the year ended December 31, 2004. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on
these consolidated financial statements based on our audit.

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 Hydrocarbon, Inc. and
subsidiaries for the year ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.

|/s/ KPMG LLP                     
|---------------------------------
|Denver, Colorado
October 14, 2005

75

---





MARKWEST HYDROCARBON, INC.  CONSOLIDATED BALANCE SHEETS  (in thousands, except share data)

|                                                                                                      |                                                                                                                    | December 31,                               |         
|----------------------------------------------------------------------------------------------------- | ------------------------------------------------------------------------------------------------------------------ | ------------------------------------------ | --------
|
|ASSETS                                                                                                |                                                                                                                    |                                            |         
|Current assets:                                                                                       |                                                                                                                    |                                            |         
|                                                                                                      | Cash and cash equivalents                                                                                          |                                            | $       
|                                                                                                      | Marketable securities                                                                                              |                                            |         
|                                                                                                      | Receivables, net of allowances of $156 and $175, respectively                                                      |                                            |         
|                                                                                                      | Inventories                                                                                                        |                                            |         
|                                                                                                      | Fair value of derivative instruments                                                                               |                                            |         
|                                                                                                      | Other current assets                                                                                               |                                            |         
|                                                                                                      |                                                                                                                    |                                            |         
|                                                                                                      |                                                                                                                    | Total current assets                       |         
|                                                                                                      |                                                                                                                    |                                            |         
|Property, plant and equipment                                                                         |                                                                                                                    |                                            | 662,606 
|Less: accumulated depreciation, depletion, amortization and impairment                                |                                                                                                                    |                                            | (108,271
|                                                                                                      |                                                                                                                    |                                            |         
|                                                                                                      | Total property, plant and equipment, net                                                                           |                                            |         
|                                                                                                      |                                                                                                                    |                                            |         
|Other assets:                                                                                         |                                                                                                                    |                                            |         
|                                                                                                      | Investment in Starfish                                                                                             |                                            |         
|                                                                                                      | Intangibles, net of accumulated amortization of $29,080 and $13,321 respectively                                   |                                            |         
|                                                                                                      | Deferred financing costs, net of accumulated amortization of $5,462 and $4,424 respectively                        |                                            |         
|                                                                                                      | Deferred contract cost, net of accumulated amortization of $702 and $390, respectively                             |                                            |         
|                                                                                                      | Investment in and advances to other equity investee                                                                |                                            |         
|                                                                                                      | Fair value of derivative instruments                                                                               |                                            |         
|                                                                                                      | Notes receivable from related parties                                                                              |                                            |         
|                                                                                                      | Other long term assets                                                                                             |                                            |         
|                                                                                                      |                                                                                                                    |                                            |         
|                                                                                                      |                                                                                                                    | Total other assets                         |         
|                                                                                                      |                                                                                                                    |                                            |         
|                                                                                                      |                                                                                                                    | Total assets                               |         
|                                                                                                      |                                                                                                                    |                                            |         
|LIABILITIES AND STOCKHOLDERS' EQUITY                                                                  |                                                                                                                    |                                            |         
|Current liabilities:                                                                                  |                                                                                                                    |                                            |         
|                                                                                                      | Accounts payable, including related party payables of $0 and $25, respectively                                     |                                            | $       
|                                                                                                      | Accrued liabilities                                                                                                |                                            |         
|                                                                                                      | Fair value of derivative instruments                                                                               |                                            |         
|                                                                                                      | Deferred income taxes                                                                                              |                                            |         
|                                                                                                      | Current portion of long term debt                                                                                  |                                            |         
|                                                                                                      |                                                                                                                    |                                            |         
|                                                                                                      |                                                                                                                    | Total current liabilities                  |         
|                                                                                                      |                                                                                                                    |                                            |         
|Deferred income taxes                                                                                 |                                                                                                                    |                                            | 9,553   
|Fair value of derivative instruments                                                                  |                                                                                                                    |                                            | 1,460   
|Long-term debt, net of original issue discount of $3,135 and $0, respectively                         |                                                                                                                    |                                            | 526,865 
|Other long-term liabilities                                                                           |                                                                                                                    |                                            | 30,196  
|Non-controlling interest in consolidated subsidiary                                                   |                                                                                                                    |                                            | 441,572 
|Commitments and contingencies (Note 18)                                                               |                                                                                                                    |                                            |         
|Stockholders' equity (December 31, 2005 adjusted to reflect May 23, 2006 Stock Dividend, see Note 2): |                                                                                                                    |                                            |         
|                                                                                                      | Preferred stock, par value $0.01, 5,000,000 shares authorized, no shares outstanding                               |                                            |         
|                                                                                                      | Common stock, par value $0.01, 20,000,000 shares authorized, 11,975,256 and 11,943,733 shares issued, respectively |                                            |         
|                                                                                                      | Additional paid-in capital                                                                                         |                                            |         
|                                                                                                      | Deferred compensation                                                                                              |                                            |         
|                                                                                                      | Accumulated earnings (deficit)                                                                                     |                                            |         
|                                                                                                      | Accumulated other comprehensive income, net of tax                                                                 |                                            |         
|                                                                                                      | Treasury stock, 0 and 55,619 shares, respectively                                                                  |                                            |         
|                                                                                                      |                                                                                                                    |                                            |         
|                                                                                                      |                                                                                                                    | Total stockholders' equity                 |         
|                                                                                                      |                                                                                                                    |                                            |         
|                                                                                                      |                                                                                                                    | Total liabilities and stockholders' equity |         
|                                                                                                      |                                                                                                                    |                                            |         

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

76

---





MARKWEST HYDROCARBON, INC.        CONSOLIDATED STATEMENTS OF OPERATIONS        (in thousands, except per share data)

|                                                                                                                                           |                                                                                                        | Year ended December 31,                                                                                 |       
|------------------------------------------------------------------------------------------------------------------------------------------ | ------------------------------------------------------------------------------------------------------ | ------------------------------------------------------------------------------------------------------- | ------
|
|
|Revenues:                                                                                                                                  |                                                                                                        |                                                                                                         |       
|                                                                                                                                           | Revenue                                                                                                |                                                                                                         | $     
|                                                                                                                                           | Derivative gain (loss)                                                                                 |                                                                                                         |       
|                                                                                                                                           |                                                                                                        |                                                                                                         |       
|                                                                                                                                           |                                                                                                        | Total revenue                                                                                           |       
|                                                                                                                                           |                                                                                                        |                                                                                                         |       
|Operating expenses:                                                                                                                        |                                                                                                        |                                                                                                         |       
|                                                                                                                                           | Purchased product costs                                                                                |                                                                                                         |       
|                                                                                                                                           | Facility expenses                                                                                      |                                                                                                         |       
|                                                                                                                                           | Selling, general and administrative expenses                                                           |                                                                                                         |       
|                                                                                                                                           | Depreciation                                                                                           |                                                                                                         |       
|                                                                                                                                           | Amortization of intangible assets                                                                      |                                                                                                         |       
|                                                                                                                                           | Accretion of asset retirement obligations                                                              |                                                                                                         |       
|                                                                                                                                           | Impairments                                                                                            |                                                                                                         |       
|                                                                                                                                           |                                                                                                        |                                                                                                         |       
|                                                                                                                                           |                                                                                                        | Total operating expenses                                                                                |       
|                                                                                                                                           |                                                                                                        |                                                                                                         |       
|                                                                                                                                           |                                                                                                        | Income from operations                                                                                  |       
|Other income (expense):                                                                                                                    |                                                                                                        |                                                                                                         |       
|                                                                                                                                           | Earnings (losses) from unconsolidated affiliates                                                       |                                                                                                         |       
|                                                                                                                                           | Interest income                                                                                        |                                                                                                         |       
|                                                                                                                                           | Interest expense                                                                                       |                                                                                                         |       
|                                                                                                                                           | Amortization of deferred financing costs and original issue discount (a component of interest expense) |                                                                                                         |       
|                                                                                                                                           | Dividend income                                                                                        |                                                                                                         |       
|                                                                                                                                           | Miscellaneous income                                                                                   |                                                                                                         |       
|                                                                                                                                           |                                                                                                        |                                                                                                         |       
|                                                                                                                                           |                                                                                                        | Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes |       
|                                                                                                                                           |                                                                                                        |                                                                                                         |       
|Income tax (expense) benefit:                                                                                                              |                                                                                                        |                                                                                                         |       
|                                                                                                                                           | Current                                                                                                |                                                                                                         |       
|                                                                                                                                           | Deferred                                                                                               |                                                                                                         |       
|                                                                                                                                           |                                                                                                        |                                                                                                         |       
|Income tax (expense) benefit                                                                                                               |                                                                                                        |                                                                                                         | (5,252
|                                                                                                                                           | Non-controlling interest in net income of consolidated subsidiary                                      |                                                                                                         |       
|                                                                                                                                           |                                                                                                        |                                                                                                         |       
|                                                                                                                                           |                                                                                                        | Net income (loss)                                                                                       |       
|                                                                                                                                           |                                                                                                        |                                                                                                         |       
|Net income (loss) per share:                                                                                                               |                                                                                                        |                                                                                                         |       
|                                                                                                                                           | Basic                                                                                                  |                                                                                                         | $     
|                                                                                                                                           |                                                                                                        |                                                                                                         |       
|                                                                                                                                           | Diluted                                                                                                |                                                                                                         | $     
|                                                                                                                                           |                                                                                                        |                                                                                                         |       
|Weighted average number of outstanding shares of common stock (2005 and 2004 adjusted to reflect May 23, 2006 Stock Dividend, see Note 2): |                                                                                                        |                                                                                                         |       
|                                                                                                                                           | Basic                                                                                                  |                                                                                                         |       
|                                                                                                                                           |                                                                                                        |                                                                                                         |       
|                                                                                                                                           | Diluted                                                                                                |                                                                                                         |       
|                                                                                                                                           |                                                                                                        |                                                                                                         |       
|Cash dividend declared per common share                                                                                                    |                                                                                                        | $                                                                                                       | 0.793 
|                                                                                                                                           |                                                                                                        |                                                                                                         |       

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

77

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MARKWEST HYDROCARBON, INC.        CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)        (in thousands)

|                                   |                                                                                                                              | Year ended December 31,    |       
|---------------------------------- | ---------------------------------------------------------------------------------------------------------------------------- | -------------------------- | ------
|
|Net income (loss)                  |                                                                                                                              | $                          | 9,537 
|                                   |                                                                                                                              |                            |       
|Other comprehensive income (loss): |                                                                                                                              |                            |       
|                                   | Unrealized gains (losses) on marketable securities, net of tax of $454, $(92) and $291, respectively.                        |                            |       
|                                   | Unrealized gains on commodity derivative instruments accounted for as hedges, net of tax of $0, $158 and $825, respectively. |                            |       
|                                   |                                                                                                                              |                            |       
|                                   |                                                                                                                              | Total comprehensive income |       
|                                   |                                                                                                                              |                            |       
|Other comprehensive income (loss)  |                                                                                                                              | $                          | 10,283
|                                   |                                                                                                                              |                            |       

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

78

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MARKWEST HYDROCARBON, INC.        CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY        (in thousands)

|                                                                               |  | Shares of
Common
Stock |  | Shares of
Treasury
Stock |   | Common
Stock |     | Additional
Paid in
Capital |   | Deferred
Compensation |   | Accumulated
Earnings
(Deficit) |      | Other
Comprehensive
Income (Loss) |   | Treasury
Stock |   | Total
Stockholders'
Equity |       
|------------------------------------------------------------------------------ |  | ---------------------- |  | ------------------------ | - | ------------ | --- | -------------------------- | - | --------------------- | - | ------------------------------ | ---- | --------------------------------- | - | -------------- | - | -------------------------- | ------
|Balance, December 31, 2003                                                     |  | 10,602                 |  | (76                      | ) | $            | 106 |                            | $ | 50,705                |   | $                              |     |                                   | $ | 2,406          |   | $                          | (1,793
|Stock DividendMay 23, 2006                                                    |  | 1,060                  |  |                         |   |              | 11  |                            |   | (11                   | ) |                                |     |                                   |   |               |   |                            |      
|                                                                               |  |                        |  |                          |   |              |     |                            |   |                       |   |                                |      |                                   |   |                |   |                            |       
|Adjusted balanceDecember 31, 2003                                             |  | 11,662                 |  | (76                      | ) |              | 117 |                            |   | 50,694                |   |                                |     |                                   |   | 2,406          |   |                            | (1,793
|Stock option exercises                                                         |  | 193                    |  |                         |   |              | 2   |                            |   | 1,390                 |   |                                |     |                                   |   |               |   |                            |      
|Modification of stock options                                                  |  | 49                     |  |                         |   |              |    |                            |   | 1,994                 |   |                                |     |                                   |   |               |   |                            |      
|Treasury stock acquired                                                        |  |                       |  | (3                       | ) |              |    |                            |   |                      |   |                                |     |                                   |   |               |   |                            |      
|Treasury stock reissued                                                        |  |                       |  | 15                       |   |              |    |                            |   | 68                    |   |                                |     |                                   |   |               |   |                            |      
|Net loss                                                                       |  |                       |  |                         |   |              |    |                            |   |                      |   |                                |     |                                   |   | (903           | ) |                            |      
|Dividends paid                                                                 |  |                       |  |                         |   |              |    |                            |   |                      |   |                                |     |                                   |   |               |   |                            | 2,039 
|Other comprehensive income                                                     |  |                       |  |                         |   |              |    |                            |   | (2,702                | ) |                                |     |                                   |   | (3,126         | ) |                            |      
|                                                                               |  |                        |  |                          |   |              |     |                            |   |                       |   |                                |      |                                   |   |                |   |                            |       
|December 31, 2004                                                              |  | 11,904                 |  | (64                      | ) |              | 119 |                            |   | 51,444                |   |                                |     |                                   |   | (1,623         | ) |                            | 246   
|Stock option exercises                                                         |  | 16                     |  |                         |   |              |    |                            |   | 77                    |   |                                |     |                                   |   |               |   |                            |      
|Issuance of restricted stock                                                   |  |                       |  | 3                        |   |              |    |                            |   | (57                   | ) |                                |     |                                   |   |               |   |                            |      
|Grant of restricted stock                                                      |  |                       |  |                         |   |              |    |                            |   | 482                   |   |                                | (482 | )                                 |   |               |   |                            |      
|Amortization of deferred stock-based compensation                              |  |                       |  |                         |   |              |    |                            |   |                      |   |                                | 84   |                                   |   |               |   |                            |      
|Stock options converted to restricted stock                                    |  |                       |  |                         |   |              |    |                            |   | 66                    |   |                                |     |                                   |   |               |   |                            |      
|Cashless stock options                                                         |  | 23                     |  |                         |   |              |    |                            |   | 965                   |   |                                |     |                                   |   |               |   |                            |      
|Treasury stock acquired                                                        |  |                       |  | (7                       | ) |              |    |                            |   |                      |   |                                |     |                                   |   |               |   |                            |      
|Contribution of treasury stock shares to 401(k) benefit plan                   |  |                       |  | 12                       |   |              |    |                            |   | 124                   |   |                                |     |                                   |   |               |   |                            |      
|Net loss                                                                       |  |                       |  |                         |   |              |    |                            |   |                      |   |                                |     |                                   |   | (6,802         | ) |                            |      
|Dividends paid                                                                 |  |                       |  |                         |   |              |    |                            |   | (4,315                | ) |                                |     |                                   |   |               |   |                            |      
|Other comprehensive income                                                     |  |                       |  |                         |   |              |    |                            |   |                      |   |                                |     |                                   |   |               |   |                            | 111   
|                                                                               |  |                        |  |                          |   |              |     |                            |   |                       |   |                                |      |                                   |   |                |   |                            |       
|December 31, 2005                                                              |  | 11,943                 |  | (56                      | ) |              | 119 |                            |   | 48,786                |   |                                | (398 | )                                 |   | (8,425         | ) |                            | 357   
|Stock option exercises                                                         |  | 19                     |  | 20                       |   |              | 1   |                            |   | 126                   |   |                                |     |                                   |   |               |   |                            |      
|Compensation expense related to equity-based awards                            |  |                       |  |                         |   |              |    |                            |   | 401                   |   |                                |     |                                   |   |               |   |                            |      
|Issuance of restricted stock                                                   |  | 9                      |  | 37                       |   |              |    |                            |   | (328                  | ) |                                |     |                                   |   |               |   |                            |      
|Treasury stock reacquired                                                      |  |                       |  | (3                       | ) |              |    |                            |   | 64                    |   |                                |     |                                   |   |               |   |                            |      
|Cashless stock options exercises                                               |  | 4                      |  | 2                        |   |              |    |                            |   | (9                    | ) |                                |     |                                   |   |               |   |                            |      
|Reclassification of unearned compensation related to the adoption of SFAS 123R |  |                       |  |                         |   |              |    |                            |   | (398                  | ) |                                | 398  |                                   |   |               |   |                            |      
|SFAS 123R windfall pool under APIC                                             |  |                       |  |                         |   |              |    |                            |   | 177                   |   |                                |     |                                   |   |               |   |                            |      
|Net income                                                                     |  |                       |  |                         |   |              |    |                            |   |                      |   |                                |     |                                   |   | 9,537          |   |                            |      
|Dividends paid                                                                 |  |                       |  |                         |   |              |    |                            |   | (8,553                | ) |                                |     |                                   |   | (1,112         | ) |                            |      
|Other comprehensive income                                                     |  |                       |  |                         |   |              |    |                            |   |                      |   |                                |     |                                   |   |               |   |                            | 746   
|                                                                               |  |                        |  |                          |   |              |     |                            |   |                       |   |                                |      |                                   |   |                |   |                            |       
|December 31, 2006                                                              |  | 11,975                 |  |                         |   | $            | 120 |                            | $ | 40,266                |   | $                              |     |                                   | $ |               |   | $                          | 1,103 
|                                                                               |  |                        |  |                          |   |              |     |                            |   |                       |   |                                |      |                                   |   |                |   |                            |       

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

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MARKWEST HYDROCARBON, INC.        CONSOLIDATED STATEMENTS OF CASH FLOWS        (in thousands)

|                                                                              |                                                                                                         | Year ended December 31,                                              |                                                
|----------------------------------------------------------------------------- | ------------------------------------------------------------------------------------------------------- | -------------------------------------------------------------------- | -----------------------------------------------
|
|Cash flows from operating activities:                                         |                                                                                                         |                                                                      |                                                
|Net income (loss)                                                             |                                                                                                         | $                                                                    | 9,537                                          
|                                                                              | Adjustments to reconcile net income to net cash provided by operating activities (net of acquisitions): |                                                                      |                                                
|                                                                              |                                                                                                         | Depreciation                                                         |                                                
|                                                                              |                                                                                                         | Amortization of intangible assets                                    |                                                
|                                                                              |                                                                                                         | Amortization of deferred financing costs and original issue discount |                                                
|                                                                              |                                                                                                         | Accretion of asset retirement obligation                             |                                                
|                                                                              |                                                                                                         | Amortization of gas contract                                         |                                                
|                                                                              |                                                                                                         | Impairments                                                          |                                                
|                                                                              |                                                                                                         | Restricted unit compensation expense                                 |                                                
|                                                                              |                                                                                                         | Participation Plan compensation expense                              |                                                
|                                                                              |                                                                                                         | Stock option compensation expense                                    |                                                
|                                                                              |                                                                                                         | Restricted stock compensation expense                                |                                                
|                                                                              |                                                                                                         | Non-controlling interest in net income of consolidated subsidiary    |                                                
|                                                                              |                                                                                                         | Contribution of treasury shares to 401(k) benefit plan               |                                                
|                                                                              |                                                                                                         | Equity in (earnings) losses from unconsolidated affiliates           |                                                
|                                                                              |                                                                                                         | Distributions from equity investments                                |                                                
|                                                                              |                                                                                                         | Unrealized (gains) losses on derivative instruments                  |                                                
|                                                                              |                                                                                                         | Gain on sale of property, plant and equipment                        |                                                
|                                                                              |                                                                                                         | Deferred income taxes                                                |                                                
|                                                                              |                                                                                                         | Gain from sale of marketable securities                              |                                                
|                                                                              |                                                                                                         | Other                                                                |                                                
|Changes in operating assets and liabilities, net of working capital acquired: |                                                                                                         |                                                                      |                                                
|                                                                              |                                                                                                         | Receivables                                                          |                                                
|                                                                              |                                                                                                         | Inventories                                                          |                                                
|                                                                              |                                                                                                         | Other current assets                                                 |                                                
|                                                                              |                                                                                                         | Accounts payable and accrued liabilities                             |                                                
|                                                                              |                                                                                                         | Notes receivables from officers                                      |                                                
|                                                                              |                                                                                                         | Other assets                                                         |                                                
|                                                                              |                                                                                                         | Other long-term liabilities                                          |                                                
|                                                                              |                                                                                                         |                                                                      |                                                
|                                                                              |                                                                                                         |                                                                      | Net cash flows provided by operating activities
|                                                                              |                                                                                                         |                                                                      |                                                
|Cash flows from investing activities:                                         |                                                                                                         |                                                                      |                                                
|                                                                              |                                                                                                         | Acquisitions                                                         |                                                
|                                                                              |                                                                                                         | Investment in Starfish                                               |                                                
|                                                                              |                                                                                                         | Restricted marketable securities                                     |                                                
|                                                                              |                                                                                                         | Restricted cash                                                      |                                                
|                                                                              |                                                                                                         | Purchase of marketable securities                                    |                                                
|                                                                              |                                                                                                         | Proceeds from sale of marketable securities                          |                                                
|                                                                              |                                                                                                         | Capital expenditures                                                 |                                                
|                                                                              |                                                                                                         | Proceeds from sale of equity investee                                |                                                
|                                                                              |                                                                                                         | Payments on financing lease receivable                               |                                                
|                                                                              |                                                                                                         | Payment on long-term gas purchase contracts                          |                                                
|                                                                              |                                                                                                         | Proceeds from sale of property, plant and equipment                  |                                                
|                                                                              |                                                                                                         |                                                                      |                                                
|                                                                              |                                                                                                         |                                                                      | Net cash flows used in investing activities    
|                                                                              |                                                                                                         |                                                                      |                                                
|                                                                              |                                                                                                         |                                                                      |                                                

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|Cash flows from financing activities:                                 |  |                                                                                   |                                                           |   |          |         |   |          |         |  
|--------------------------------------------------------------------- |  | --------------------------------------------------------------------------------- | --------------------------------------------------------- | - | -------- | ------- | - | -------- | ------- | -
|                                                                      |  | Proceeds from long-term debt                                                      |                                                           |   | 173,024  |         |   | 910,500  |         |  
|                                                                      |  | Payments of long-term debt                                                        |                                                           |   | (529,524 | )       |   | (524,000 | )       |  
|                                                                      |  | Proceeds from MarkWest Energy's private placement of senior notes                 |                                                           |   | 271,700  |         |   |         |         |  
|                                                                      |  | Payments for debt issuance costs, deferred financing costs and registration costs |                                                           |   | (6,826   | )       |   | (11,809  | )       |  
|                                                                      |  | Proceeds from MarkWest Energy's private placement, net                            |                                                           |   | 5,000    |         |   | 92,887   |         |  
|                                                                      |  | Proceeds from MarkWest Energy's public offering, net                              |                                                           |   | 123,256  |         |   |         |         |  
|                                                                      |  | Exercise of stock options                                                         |                                                           |   | 311      |         |   | 77       |         |  
|                                                                      |  | Excess income tax benefits from share-based compensation                          |                                                           |   | 177      |         |   |         |         |  
|                                                                      |  | Purchase of treasury shares                                                       |                                                           |   |         |         |   | (161     | )       |  
|                                                                      |  | Payment of dividends                                                              |                                                           |   | (9,665   | )       |   | (4,315   | )       |  
|                                                                      |  | Distributions to MarkWest Energy unitholders                                      |                                                           |   | (43,500  | )       |   | (26,081  | )       |  
|                                                                      |  |                                                                                   |                                                           |   |          |         |  
|                                                                      |  |                                                                                   | Net cash flows provided by (used in) financing activities |   |          | (16,047 | ) |          | 437,098 |  
|                                                                      |  |                                                                                   |                                                           |   |          |         |  
|Net increase (decrease) in cash                                       |  |                                                                                   | 27,876                                                    |   |          | 8,124   |   |          | (29,300 | )
|Cash and cash equivalents at beginning of year                        |  |                                                                                   | 20,968                                                    |   |          | 12,844  |   |          | 42,144  |  
|                                                                      |  |                                                                                   |                                                           |   |          |         |  
|Cash and cash equivalents at end of year                              |  | $                                                                                 | 48,844                                                    |   | $        | 20,968  |   | $        | 12,844  |  
|                                                                      |  |                                                                                   |                                                           |   |          |         |  
|Supplemental disclosures of cash flow information:                    |  |                                                                                   |                                                           |   |          |         |   |          |         |  
|Cash paid for interest, net of amount capitalized                     |  | $                                                                                 | 16,120                                                    |   | $        | 22,225  |   | $        | 6,532   |  
|Cash paid for income taxes                                            |  |                                                                                   | 2,600                                                     |   |          | 549     |   |          |        |  
|Supplemental schedule of non-cash investing and financing activities: |  |                                                                                   |                                                           |   |          |         |   |          |         |  
|Construction projects in progress                                     |  |                                                                                   | (8,270                                                    | ) |          | (1,545  | ) |          | 4,037   |  
|Property, plant and equipment asset retirement obligation             |  |                                                                                   | 64                                                        |   |          | 561     |   |          | 377     |  
|Deferred offering costs                                               |  |                                                                                   |                                                          |   |          | 215     |   |          |        |  
|Accrued amounts due to Javelina sellers and Starfish                  |  |                                                                                   |                                                          |   |          | 6,888   |   |          |        |  
|Accrued private placement proceeds                                    |  |                                                                                   |                                                          |   |          | 5,000   |   |          |        |  

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

81

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MARKWEST HYDROCARBON, INC.        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.    Organization

MarkWest Hydrocarbon, Inc. ("MarkWest Hydrocarbon" or the "Company") is an energy company primarily focused on marketing natural gas liquids (NGLs) and
increasing shareholder value by growing MarkWest Energy Partners, L.P. ("MarkWest Energy Partners" or the "Partnership"), a consolidated subsidiary and publicly traded master limited partnership.
MarkWest Energy Partners is engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids; and the gathering and
transportation of crude oil. The Company also markets natural gas and NGLs. MarkWest Hydrocarbon and MarkWest Energy Partners provide services primarily in Appalachia, Michigan, Texas, Oklahoma, Gulf
Coast and other areas of the southwest.

2.    Summary of Significant Accounting Policies



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

On
April 27, 2006, MarkWest Hydrocarbon announced that its Board of Directors approved the issuance of one share of common stock for each ten shares of common stock held by common
stockholders. The stock was issued on May 23, 2006, to the stockholders of record as of the close of business on May 11, 2006; the ex-dividend date was May 9, 2006.
1,084,647 shares were issued at a fair value of $24.4 million, based upon the last sale price on the record date ($22.50 per share). Cash of $3,200 was paid in lieu of fractional shares, based
upon the last sale price on the record date. All common stock accounts and per share data have been retroactively adjusted to give effect to the dividend of our common stock.

On
January 25, 2007, the Board of the General Partner of the Partnership declared the Partnership's two-for-one split of the Partnership's units. The units
were issued on February 28, 2007 for holders of record at the close of business on February 22, 2007. The unit split resulted in the issuance of an additional 15,603,257 common units and
600,000 subordinated units. All Partnership specific 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 to
the unit split.



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

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



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



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



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



Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of assets are capitalized. Repairs, maintenance and renewals that do
not extend the useful lives of the assets are expensed as incurred. Interest costs for the construction or development of long-term assets are capitalized and amortized over the related
asset's estimated useful life. Leasehold improvements are depreciated over the shorter of the useful life or lease term. Depreciation is
provided principally on the straight-line method over the following estimated useful lives:

Asset Class

Range of
Estimated
Useful LivesBuildings

20 - 25 yearsGas gathering facilities

20 - 25 yearsGas processing plants

20 - 25 yearsFractionation and storage facilities

20 - 25 yearsNatural gas pipelines

20 - 25 yearsCrude oil pipelines

20 - 25 yearsNGL transportation facilities

20 - 25 yearsEquipment and other

3 - 10 years


83

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The
Company recognizes the fair value of a liability for an asset retirement obligation in the period, in which the liability is incurred, with an offsetting increase in the carrying
amount of the related long-lived asset. Over time, the liability is accreted to its future value, and the capitalized cost is depreciated over the useful life of the related asset. Upon
settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. The Company adopted the Financial Accounting Standards Board ("FASB")
Interpretation No. 47,Accounting for Conditional Asset Retirement Obligations("FIN 47"), on January 1, 2005. FIN 47 clarified the
accounting for conditional asset retirement obligations under Statement of Financial Accounting Standards ("SFAS") No.143,Accounting for Asset Retirement
Obligations("SFAS 143"). A conditional asset
retirement obligation is an unconditional legal obligation to perform an activity in which the timing and / or method of settlement are conditional on a future event that may or may not be within the
control of the entity. FIN 47 requires an entity to recognize a liability for a conditional asset retirement obligation if the amount can be reasonably estimated. Adopting FIN 47 had an immaterial
impact on the Company.



On March 31, 2005, the Partnership acquired its non-controlling, 50% interest in Starfish Pipeline Company, LLC ("Starfish") for
$41.7 million, which is accounted for under the equity method. Differences between the Partnership's investment and its proportionate share of Starfish's reported equity are amortized based
upon the respective useful lives of the assets to which the differences relate. The Partnership's share of Starfish's earnings in 2006 was $5.3 million compared to a loss of $2.2 million
in 2005.

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

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



The Company's intangible assets are comprised of customer contracts and relationships acquired in business combinations, recorded under the purchase method of
accounting at their estimated fair values at the date of acquisition. Using relevant information and assumptions, management determines the

84

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fair
value of acquired identifiable intangible assets. Fair value is generally calculated as the present value of estimated future cash flows using a risk-adjusted discount rate. The key
assumptions include contract renewals, economic incentives to retain customers, historical volumes, current and future capacity of the gathering system, pricing volatility, and the discount rate.
Amortization of intangibles with definite lives is calculated using the straight-line method over the estimated useful life of the intangible asset. The estimated economic life is
determined by assessing the life of the assets to which the contracts or relationships relate, the likelihood of renewals, competitive factors, regulatory or legal provisions, and maintenance and
renewal costs.



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

For
assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value, less the cost to sell, to determine if impairment is
required. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change.



Deferred financing costs, included inOther assetsin the accompanying consolidated balance sheets, are amortized
over the estimated lives of the related obligations or, in certain circumstances, accelerated if the obligation is refinanced, using the straight line method which approximates the effective interest
rate method.



The Company entered into a series of agreements with a gas producer in September 2004, under which the Company processes natural gas under modified
keep-whole arrangements. In connection with these agreements, the Company paid $3.3 million of consideration to the producer in connection with these non-separable
contracts, which are being amortized as additional cost of the gas purchased over the term of the contracts, October 1, 2004 through February 9, 2015. Amortization related to these
contracts for the years ended December 31, 2006 and 2005 was $0.3 million and $0.3 million, respectively.

85

---





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



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

In
the course of normal operations, the Company routinely enters into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs, that
under SFAS 133, qualify for and are designated as a normal purchase and sales contracts. In general, the Company exempts these types of contracts from the mark-to-market
requirements of SFAS 133 and instead accounts for them 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 or purchase product costs.
The following table summarizes our handling of derivative instruments as presented in our accompanying consolidated statements of operations:

Transaction Type

Realized gain (loss)

Unrealized gain (loss)Sales:Fixed Physical Forwards

Revenue

Derivative gain (loss)All other derivative instruments

Derivative gain (loss)

Derivative gain (loss)Purchases:Fixed Physical Forwards

Purchase product costs

Purchase product costsAll other derivative instruments

Purchase product costs

Purchase product costs


Derivative
gain (loss) in the table above are included in total revenues in the accompanying consolidated statements of operations.

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



Management believes the carrying amount of financial instruments, including cash, accounts receivable, accounts payable, accrued expenses, and other financial
instruments approximates fair value because of the short-term maturity of these instruments. Management believes the carrying value of MarkWest Hydrocarbon's Credit Facility and the
Partnership's Credit Facility approximates fair value due to their variable interest rates. The estimated fair value of the Senior Notes was approximately $499.8 million and
$207.0 million at December 31, 2006 and 2005, respectively, based on quoted market prices, see Note 12. Derivative instruments are recorded at fair value, based on available
market information, see Note 13.



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



87

---





In
many cases, the Partnership provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of the Partnership's 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:



88

---





The Company 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 Company acts as the principal, under EITF 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, as the Company 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 Company earns a fixed amount and does not take ownership of the gas and/or NGLs.



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. The estimated accruals are reversed in the following month when actual information is received from third parties and our internal records have been reconciled.



The Company adopted the SFAS No. 123 (revised 2004),Share-Based Payment("SFAS 123R") on
January 1, 2006, using the modified prospective method. Prior to adopting SFAS 123R, the Company 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.

Under
SFAS 123R, compensation expense is based on the fair value of the award. SFAS 123R classifies stock-based compensation as either equity or liability awards. The fair
value on the date of grant for an award classified as equity is recognized over the requisite service period, with a corresponding credit to equity (generally, paid-in capital). The
requisite service period is the period during which an individual is required to provide a service in exchange for the award. The requisite service period is estimated based on an analysis of the
terms of the share-based payment award. Compensation expense for a liability award is based on the award's fair value, remeasured at each reporting date until the date of settlement. Additionally,
compensation expense is reduced for an estimate of expected award forfeitures.



Historically, stock options were issued under the Company's 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan, (together the
"1996 Plans"). In June 2006 shareholders approved the 2006 Stock Incentive Plan (the "2006 Plan") to replace the 1996 Plans. Under SFAS 123R, our stock options are categorized as equity
awards. Compensation expense for stock options is measured based on the grant date fair value and is amortized into earnings over the service period as the options vest. While it was determined in
2005 that the Company does not intend to issue

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stock
options in the future, they are available for issuance under the 2006 Plan. On December 1, 2006 a board resolution provided for the accelerated vesting of 14,950 unvested stock option
grants. Consequently, as of December 31, 2006 the Company had no remaining unvested options or any unrecognized compensation expense pertaining to options.



The Company issued restricted stock under the 1996 Plans until the adoption of the 2006 Plan at which point all new shares are, and will be, issued pursuant to
the rules of the 2006 Plan. Under SFAS 123R, our restricted stock qualifies as an equity award. Accordingly, it is measured at the grant date fair value and the associated compensation expense
is recognized over the requisite service period. The restricted stock vests equally over a three year period.



The Company has also entered into arrangements with certain directors and employees of the Company referred to as the Participation Plan. Under this plan, the
Company 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, the Company 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, the Company 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, some portion of 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 each employee devotes to the Company. Compensation attributable to interests sold to individuals who serve
on both the board of MarkWest Hydrocarbon and the Board of Directors of the Partnership's General Partner is allocated equally.



The Partnership issues restricted units under the MarkWest Energy Partners, L.P. Long-Term Incentive Plan. A restricted unit is a "phantom" unit that
entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the Compensation Committee, cash equivalent to the value of a common unit. The restricted
units are treated as liability awards under SFAS 123R. As a result, the Partnership is required to mark to market the awards at the end of each reporting period. Compensation expense is
remeasured for the phantom unit grants using the market price of MarkWest Energy Partners' common units at each reporting date. The fair value of the units awarded is amortized into earnings over the
period of service and is adjusted monthly for the change in the fair value of the unvested units granted. The phantom units vest equally over a three year period.

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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 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.

To
satisfy common unit awards, the Partnership will issue new common units, acquire common units in the open market, or use common units already owned by the general partner.



Had compensation cost for the Company's stock-based and unit-based compensation plans been determined based on the fair value at the grant dates under
those plans consistent with the method prescribed by SFAS 123R for the fiscal years ended December 31, 2005 and 2004, the Company's net income and earnings per share would have been
adjusted to the pro forma amounts listed below:

Year ended December 31,2005

2004Net loss, as reported

$
(6,802
)
$
(903
)Add: compensation expense included in reported net income, net of related tax effect


6,341


6,770Deduct: total stock-based employee compensation expense determined under fair value-based method for all awards, net of related tax effect


(5,215
)

(4,681
)Proforma income (loss)

$
(5,676
)
$
1,186Net income (loss) per share:Basic:As reported

$
(0.57
)
$
(0.08
)Pro forma

$
(0.48
)
$
0.10Diluted:As reported

$
(0.57
)
$
(0.08
)Pro forma

$
(0.48
)
$
0.10




The Company accounts for income taxes under the asset and liability method pursuant to SFAS No. 109,Accounting for Income
Taxes("SFAS 109"). Under SFAS 109, deferred income taxes are recognized for the future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is
recognized in the period that includes the enactment date of the tax rate change. Realizability of deferred tax assets is assessed

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and,
if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value.



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



Basic earnings (loss) per share are computed by dividing net income by the weighted average number of shares of common stock outstanding during the period.
Diluted earnings per share is computed by adjusting the weighted average number of common shares outstanding for the dilutive effect, if any, of common share equivalents. The Company uses the treasury
stock method to determine the dilutive effect. Dilutive potential common shares include outstanding stock options and stock awards. All share information has been adjusted to give retroactive effect
to the May 2006 stock dividend.

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

|                                                                                                           |                                | Year ended December 31, |       
|---------------------------------------------------------------------------------------------------------- | ------------------------------ | ----------------------- | ------
|
|Net income (loss)                                                                                          |                                | $                       | 9,537 
|Weighted average common shares outstanding during the period                                               |                                |                         | 11,939
|                                                                                                           | Effect of dilutive instruments |                         |       
|                                                                                                           |                                |                         |       
|Weighted average common shares outstanding during the period including the effects of dilutive instruments |                                |                         | 12,033
|                                                                                                           |                                |                         |       
|Net income (loss) per share:                                                                               |                                |                         |       
|                                                                                                           | Basic                          |                         | $     
|                                                                                                           |                                |                         |       
|                                                                                                           | Diluted                        |                         | $     
|                                                                                                           |                                |                         |       



In February 2006 the FASB issued SFAS No. 155,Accounting for Certain Hybrid Financial Instrumentsan amendment
of FASB Statements No. 133 and 140("SFAS 155"). This statement amendsSFAS 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
Liabilitiesand 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

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securitized
financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation;
(d) clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives; and, (e) eliminates restrictions on a qualifying special-purpose entity's
ability to hold passive derivative financial instruments that pertain to beneficial interests that are or contain a derivative financial instrument. The standard also requires presentation within the
financial statements that identifies those hybrid financial instruments for which the fair value election has been applied and information on the income statement impact of the changes in fair value
of those instruments. The Company is required to apply SFAS 155 to all financial instruments acquired, issued or subject to a remeasurement event beginning January 1, 2007, although
early adoption is permitted as of the beginning of an entity's fiscal year. The adoption of SFAS 155 is not expected to have a material impact on the consolidated financial statements of the
Company.

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 SFAS109,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 fiscal years beginning after December 15, 2006. The Company is currently
evaluating the impact of FIN 48.

In
September 2006 the FASB issued SFAS No. 157,Fair Value Measurements("SFAS 157"). SFAS 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 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 Company has not yet determined the impact, if any, the implementation of SFAS 157 may have on the consolidated financial statements of the Company.

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. SAB 108 did not have a material effect on the
consolidated financial statements of the Company.

The
FASB has issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities("SFAS 159"), 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 SFAS 159,
entities that elect the fair value option will report unrealized gains and losses in earnings at

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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. SFAS 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 157. The Company has not yet determined the impact, if any; the implementation of SFAS 159 may have on the
consolidated financial statements of the Company.

3.    Acquisitions by MarkWest Energy Partners

During 2006, 2005 and 2004, the Partnership completed the following acquisitions. Each acquisition was accounted for under the purchase method. The assets
acquired and liabilities assumed were recorded at the estimated fair market values as of the acquisition date. The preliminary allocation of assets and liabilities may be adjusted to reflect the final
determined amounts during a short period of time
following the acquisition. The results of operations from these acquisitions are included in our consolidated financial statements from the acquisition date.



On December 29, 2006, the Partnership purchased 100% of the ownership interest in Santa Fe Gathering, L.L.C for $15.0 million, subject to working
capital adjustments. The gathering system is located in Roger Mills and Beckham Counties, Oklahoma. The Grimes system was constructed in May 2005 to gather from growing production fields.
Current system throughput is approximately 16 MMcf/d. The final purchase price allocation is expected to be completed in the second quarter of 2007.



On November 1, 2005, the Partnership acquired equity interests in Javelina Company, Javelina Pipeline Company and Javelina Land Company, L.L.C., which were
40%, 40% and 20%, respectively, owned by subsidiaries of El Paso Corporation, Kerr-McGee Corporation and Valero Energy Corporation. The Partnership paid consideration of
$357.0 million, plus $41.8 million for net working capital that included approximately $35.5 million in cash. The Corpus Christi, Texas, gas processing facility treats and
processes off-gas from six local refineries, two of which are owned by Valero Energy Corporation, two by Koch Industries, Inc. and two by Citgo Petroleum Corporation. Constructed in
1989 to recover up to 28,000 Bbl/d of NGLs, the facility currently processes approximately 125 to 130 MMcf/d of inlet gas and produces approximately 26,200 Bbl/d of NGLs. The Partnership and the
seller negotiated a final settlement of the acquired working capital of $41.8 million, and the final payment of $5.9 million was paid to the sellers in May of 2006 and included in the
final purchase price allocation, which was completed in the second quarter of 2006.

94

---





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



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



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

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

|                                 |                                      | 2006 |        | 2005   |   | 2004   
|-------------------------------- | ------------------------------------ | ---- | ------ | ------ | - | -------
|
|Acquisition costs:               |                                      |      |        |        |   |        
|                                 | Cash consideration                   |      | $      | 15,000 |   | $      
|                                 | Direct acquisition costs             |      |        |       |   |        
|                                 |                                      |      |        |        |   |        
|Totals                           |                                      |      | 15,000 |        |   | 398,845
|                                 |                                      |      |        |        |   |        
|Allocation of acquisition costs: |                                      |      |        |        |   |        
|                                 | Current assets                       |      |        |       |   |        
|                                 | Customer contracts and relationships |      |        | 12,630 |   |        
|                                 | Property, plant and equipment        |      |        | 2,370  |   |        
|                                 | Liabilities assumed                  |      |        |       |   |        
|                                 |                                      |      |        |        |   |        
|Totals                           |                                      | $    | 15,000 |        | $ | 398,845
|                                 |                                      |      |        |        |   |        



The following table reflects the pro forma consolidated results of operations for the years ended December 31, 2005 and 2004, as though the Javelina,
Starfish and East Texas acquisitions had occurred on January 1, 2004. The unaudited pro forma results of operations for the Hobbs and Santa Fe

95

---



acquisitions have not been presented, as the acquisitions were not considered significant. The results have been prepared for comparative purposes only and may not be indicative of future results. All
earnings per share information have been updated to reflect the May 2006 stock dividend.

|                                                               |         | Year ended December 31,
|-------------------------------------------------------------- | ------- | -----------------------
|
|
|
|Revenue                                                        |         | $                      
|Net income (loss)                                              |         |                        
|Net income (loss) per share:                                   |         |                        
|                                                               | Basic   |                        
|                                                               | Diluted |                        
|Weighted average number of outstanding shares of common stock: |         |                        
|                                                               | Basic   |                        
|                                                               | Diluted |                        

4.    Marketable securities

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

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

|                   |                                  | Cost
Basis |   | Unrealized
Gains |  | Unrealized
Losses |       | Recorded
Basis
|------------------ | -------------------------------- | ---------- | - | ---------------- |  | ----------------- | ----- | --------------
|December 31, 2006  |                                  |            |   |                  |  |                   |       |               
|Equity securities: |                                  |            |   |                  |  |                   |       |               
|                   | Master limited partnership units |            | $ | 5,942            |  | $                 | 1,771 |               
|                   |                                  |            |   |                  |  |                   |       |               
|December 31, 2005  |                                  |            |   |                  |  |                   |       |               
|Equity securities: |                                  |            |   |                  |  |                   |       |               
|                   | Master limited partnership units |            | $ | 5,497            |  | $                 | 714   |               
|                   |                                  |            |   |                  |  |                   |       |               

For
the year ended December 31, 2006, the Company recognized net unrealized gains on marketable securities of $0.7 million, net of the related tax expense of
$0.5 million. These gains are shown as a component of other comprehensive income for 2006.

For
the year ended December 31, 2005, the Company recognized net unrealized losses on marketable securities of $0.2 million, net of the related tax benefit of
$0.1 million. These losses are shown as a component of other comprehensive income for 2005.

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5.    Significant Customers and Concentration of Credit Risk

For the year ended December 31, 2006, revenues from Targa Resources Partners, L.P. ("Targa") totaled $76 million, representing 10% of the Company's
consolidated revenues. Sales to Targa are made primarily from the MarkWest Energy Partner segment. The Company had a receivable of $3.0 million from Targa as of December 31, 2006.

For
the years ended December 31, 2005 and 2004, revenues from one other customer totaled $67 million and $60 million, representing 9% and 13% of the Company's
consolidated revenues, respectively. Sales to this customer were made primarily from the MarkWest Energy Partner segment. The Company had a receivable of $5.5 million from this customer as of
December 31, 2005.

6.    Receivables and Other current assets

Receivables consist of the following (in thousands):

December 31,2006

2005Trade, net

$
81,908

$
135,008Other


19,208


10,531Total Receivables

$
101,116

$
145,539


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

December 31,2006

2005Customer margin deposits

$
7,761

$
6,598Prepaid fuel


3,017


8,696Risk management premiums


1,009


Income tax receivable


2,372


Prepaid other


1,105


1,020Total other current assets

$
15,264

$
16,314




In the third and fourth quarters of 2006 the Partnership entered into certain put option contracts on commodities requiring premium payments to secure certain
floor prices. The Partnership paid $1.0 million to the counterparty as a premium on certain short-term put option contracts. The payment is recorded as a short-term
asset and will be amortized through revenue as the puts expire or are exercised. The contracts are recorded as derivative instruments, so charges in fair value of the contracts are recorded as an
unrelated gain or loss.

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7.    Properties, plant and equipment

Property, plant and equipment consist of (in thousands):

December 31,2006

2005Gas gathering facilities

$
289,586

$
212,042Gas processing plants


217,080


213,943Fractionation and storage facilities


23,470


22,882Natural gas pipelines


42,361


42,246Crude oil pipelines


19,114


19,070NGL transportation facilities


5,326


4,433Furniture, office equipment and other


2,641


2,864Land, building and other equipment


20,705


13,823Construction-in-progress


42,323


41,895662,606


573,198Less: Accumulated depreciation


(108,271
)

(78,500
)Total property, plant and equipment, net

$
554,335

$
494,698


The
Company capitalizes interest on major projects during construction. For the years ended December 31, 2006 and 2005, the Company capitalized interest of $0.9 million and
$2.1 million, respectively.



In late 2006 the Partnership began the construction and operation of the Woodford gathering system and compression system to support wells in a
200-square-mile project area situated in a four-county region in the Arkoma Basin in eastern Oklahoma. As of December 31, 2006, the Partnership invested
capital of $26.4 million.

8.    Intangible assets

The Company's intangible assets at December 31, 2006 and 2005 are comprised of customer contracts and relationships, as follows (in thousands):

|           |  | December 31, 2006 |         | December 31, 2005 |   |       
|---------- |  | ----------------- | ------- | ----------------- | - | ------
|
|East Texas |  | $                 | 165,379 |                   | $ | 19,984
|Javelina   |  |                   | 195,137 |                   |   | 9,096 
|Oklahoma   |  |                   | 12,630  |                   |   |      
|Other      |  |                   |        |                   |   |      
|           |  |                   |         |                   |   |       
|Total:     |  | $                 | 373,146 |                   | $ | 29,080
|           |  |                   |         |                   |   |       

Amortization
expense related to intangible assets was $16.0 million, $9.7 million and $3.6 million for the years ended December 31, 2006, 2005 and 2004,
respectively.

98

---



Estimated
future amortization expense related to the intangible assets at December 31, 2006, is as follows (in thousands):

Year ended December 31,2007

$
16,7052008


16,7052009


16,7052010


16,7052011


16,705Thereafter


260,541Total

$
344,066


9.    Other long-term assets

The Company's other long-term assets at December 31, 2006 and 2005 are comprised of the following (in thousands):

December 31,2006

2005Risk management deposits

$
717

$
Other


326


326$
1,043

$
326




In the third and fourth quarters of 2006 the Partnership entered into certain put option contracts on commodities requiring premium payments to secure certain
floor prices. The Partnership paid $0.7 million to the counterparty as a premium on certain long-term put option contracts. The payment is recorded as a long-term asset
(and reclassified to a current asset once the contract is set to expire within one year) and will be amortized through revenue as the puts expire or are exercised. The contracts are recorded as
derivative instruments, so changes in fair value of the contracts are recorded as an unrealized gain or loss.

99

---



10.    Accrued liabilities

Accrued liabilities consist of the following (in thousands):

December 31,2006

2005Product and operations

$
14,990

$
17,987Customer obligations


203


3,380Professional services


1,689


2,054Taxes, other than income


3,284


3,014Interest


13,936


3,273Javelina working capital adjustment





5,402Starfish contribution





1,486Construction in progress


10,922


2,652Deferred income


375


1,937Bonus and profit sharing, severance and vacation accruals


4,629


3,349Phantom unit compensation expense accrual


2,007


958Deferred lease obligation


2,344


Other


829


377Total accrued liabilities

$
55,208

$
45,869


11.    Asset retirement obligation

The Company adopted Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement
Obligations("SFAS 143"),on January 1, 2003. Under SFAS 143, the fair value of a liability for an asset
retirement obligation is recognized in the period in which the liability is incurred with an offsetting increase in the carrying amount of the related long-lived asset. The recognition of
an asset retirement obligation requires that management make numerous estimates, assumptions and judgments regarding such factors as the estimated probabilities, amounts and timing of settlements; the
credit-adjusted risk-free rate to be used; inflation rates, and future advances in technology. In periods subsequent to initial measurement of the liability, we must recognize
period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash
flows. Over time, the liability is accreted to its future value, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either
settles the obligation for its recorded amount or incurs a gain or loss.

The
Company's assets subject to asset retirement obligations are primarily certain gas-gathering pipelines and processing facilities, a crude oil pipeline and other related
pipeline assets. The Company also has land leases that require the Company to return the land to its original condition upon the termination of the lease. In connection with the adoption of
SFAS 143, the Company reviewed current laws and regulations governing obligations for asset retirements and leases, as well as the Company's leases and other agreements.

100

---



The
following is a reconciliation of the changes in the asset retirement obligation from December 31, 2004, to December 31, 2006 (in thousands):

Asset retirement obligation as of December 31, 2004

$
892Liabilities accrued during the period


554Liabilities settled


(504
)Accretion expense


160Asset retirement obligation as of December 31, 2005


1,102Liabilities accrued during the period


64Liabilities settled


Accretion expense


102Asset retirement obligation as of December 31, 2006

$
1,268


At
December 31, 2006, 2005 and 2004, there were no assets legally restricted for purposes of settling asset retirement obligations. The asset retirement obligation liability has
been recorded as "Other long-term liabilities" in the accompanying consolidated balance sheets.

12.    Debt

Debt as of December 31, 2006 and 2005 is summarized below (in thousands):

December 31,2006

2005MarkWest Hydrocarbon Credit FacilityRevolver facility, 8.75% interest

$


$
7,500Partnership Credit FacilityTerm loan, 8.75% interest at December 31, 2005, retired October 2006





365,000Revolver facility, 8.75% interest at December 31, 2005, due December 2010


30,000


14,000Partnership Senior NotesSenior Notes, 6.875% interest, due November 2014


225,000


225,000Senior Notes, 8.5% interest, net of original issue discount of $3,135, due July 2016


271,865


526,865


611,500Less: obligations due in one year





(2,738
)Total long-term debt

$
526,865

$
608,762




On August 18, 2006, the Company entered into the second amended and restated credit agreement ("Company Credit Facility") which provides a maximum lending
limit of $55.0 million, increased from

101

---



$25.0 million;
and extends the term from one to three years. The Company Credit Facility includes a $40.0 million Revolving Facility and a $15.0 million Unit Acquisition Facility.
The $15.0 million Unit Acquisition Facility may be used to finance the acquisition of MarkWest Energy Partners common or subordinated units.

The
Company Credit Facility bears 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 Facility's administrative
agent, based on the U.S. prime rate. The basis points correspond to the ratio of the Revolver Facility Usage to the Borrowing Base, ranging from 0.50% to 1.75% for Base Rate loans, and 1.50% to 2.75%
for Eurodollar Rate loans. The Company pays a quarterly commitment fee on the unused portion of the credit facility at an annual rate ranging from 37.5 to 50.0 basis points.

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

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



On
February 16, 2007, the Company entered into the first amendment to the second amended and restated credit agreement. The Term of the Agreement was extended by one year, to
August 20, 2010. Additionally, provisions were added for a Non-Borrowing Base Revolving Credit Facility ("NBB Facility"). The NBB Facility provides for up to $50 million of
credit to enable the Company to meet margin requirements associated with its derivative instruments.

The
new agreement also added the following covenant:



On January 31, 2006, the Company entered into the first amended and restated credit agreement, which provided a maximum lending limit of
$25.0 million for a one-year term, and which amended and restated the October 2004 agreement discussed below. As of December 31, 2006, the Company had
$6.0 million of the availability committed to a letter of credit, leaving $19.0 million available for revolving loans.

102

---



On
March 23, 2006, the Company amended the First Amended and Restated Credit Agreement to reduce the cash reserve requirement from $13.0 million to $5.0 million
through December 31, 2006.



In October 2004 the Company entered into a $25.0 million senior credit facility with a term of one year. The $25.0 million revolving facility
had a variable interest rate based on the base rate, which is equal to the higher of a) the Federal Funds Rate plus 1/2 of 1%, and b) the rate of interest in effect for
such day as publicly announced from time to time by the Administrative Agent as its prime rate, plus the applicable rate, which is based on a utilization percentage. In October, November and
December 2005, the Company entered into the first, second and third amendment to the credit agreement. The first amendment extended the term of the original agreement to November 15,
2005. The second amendment reduced the lending amount from $25.0 million to $16.0 million, of which $6.0 million of availability is committed to a letter of credit, leaving
$10.0 million available for revolving loans. The second amendment also extended the term of the revolving credit to December 30, 2005. The third amendment extended the term of the
revolving credit to January 31, 2006, and reduced the lending amount from $16.0 million to $13.5 million, of which $6.0 million is committed to a letter of credit, leaving
$7.5 million available for revolving loans at December 31, 2005.



In July 2006 MarkWest Energy Partners, LP and its wholly owned subsidiary MarkWest Energy Finance Corporation (the "Issuers") co-issued
$200 million in aggregate principal amount of 81/2% senior notes due 2016 (the "2016 Senior Notes") to qualified institutional buyers. The 2016 Senior Notes will mature on
July 15, 2016, and interest is payable on each July 15 and January 15, commencing January 15, 2007. In October 2006 the Issuers offered $75.0 million in
additional debt securities under this same indenture. The net proceeds from the 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 Issuers used a portion of the net proceeds from the offerings to repay the term debt under the Partnership
Credit Facility. 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. Each of the Partnership's existing subsidiaries, other than MarkWest Energy Finance Corporation, has guaranteed the notes jointly and severally and fully and
unconditionally. The 2016 notes are senior unsecured obligations equal in right of payment with all of the Partnership's existing and future senior debt. These notes are senior in right of payment to
all of the Partnership's future subordinated debt but effectively junior in right of payment to its secured debt to the extent of the assets securing the debt, including the Partnership's obligations
in respect of its Partnership Credit Facility.

The
indenture governing the Partnership's 2016 Senior Notes limits the activity of the Partnership and its restricted subsidiaries, including 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,

103

---



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. Subject to compliance with certain covenants, the Partnership may issue
additional notes from time to time under the indenture pursuant to Rule 144A and Regulation S under the Securities Act of 1933.

The
Partnership agreed to file an exchange offer registration statement or, under certain circumstances, a shelf registration statement, pursuant to a registration rights agreement
relating to the 2016 Senior Notes. The Partnership failed to complete the exchange offer in the time provided for in the subscription agreements (January 6, 2007), and as a consequence it began
incurring an interest rate penalty of 0.5% annually, increasing 0.25% every 90 days thereafter up to 1%, until such time as the exchange offer was completed. The Partnership incurred penalty
interest of 0.5% from January 7, 2007 until February 26, 2007.



In October 2004 MarkWest Energy Partners, LP and its wholly owned subsidiary, MarkWest Energy Finance Corporation, co-issued
$225.0 million in senior notes ("2014 Senior Notes") at a fixed rate of 6.875%, payable semi-annually in arrears on May 1 and November 1, and commencing on
May 1, 2005. The 2014 Senior Notes mature on November 1, 2014. The Partnership may redeem some or all of the notes at any time on or after November 1, 2009, at certain redemption
prices together with accrued and unpaid interest to the date of redemption. The Partnership may redeem all of the notes at any time prior to November 1, 2009, at a make-whole
redemption price. In addition, prior to November 1, 2007, the Partnership may redeem up to 35% of the aggregate principal amount of the notes with the proceeds of certain equity offerings at a
stated redemption price. The Partnership must offer to repurchase the notes at a specified price if it a) sells certain assets and does not reinvest the proceeds or repay senior indebtedness,
or b) experiences specific kinds of changes in control. Each of the Partnership's existing subsidiaries, other than MarkWest Energy Finance Corporation, has guaranteed the notes jointly and
severally and fully and unconditionally. The 2014 Senior Notes are senior unsecured obligations equal in right of payment with all of the Partnership's existing and future senior debt. These notes are
senior in right of payment to all of the
Partnership's future subordinated debt but effectively junior in right of payment to its secured debt to the extent of the assets securing the debt, including the Partnership's obligations in respect
of its Partnership Credit Facility.

The
indenture governing the 2014 Senior Notes limits the activity of the Partnership and its restricted subsidiaries. Limitations include 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. Subject to compliance with
certain covenants, the Partnership may issue additional notes from time to time under the indenture pursuant to Rule 144A and Regulation S under the Securities Act of 1933.

104

---



The
Partnership agreed to file an exchange offer registration statement or, under certain circumstances, a shelf registration statement, pursuant to a registration rights agreement
relating to the 2014 Senior Notes. The Partnership failed to complete the exchange offer in the time provided for in the subscription agreements (April 26, 2005) and, as a consequence, was
incurring an interest rate penalty of 0.5% annually, increasing 0.25% every 90 days thereafter up to 1%, until such time as the exchange offer was completed. The registration statement was
filed on January 17, 2006, the exchange offer was completed on March 7, 2006, and the interest penalty ceased.



On December 29, 2005, MarkWest Energy Operating Company, L.L.C., a wholly owned subsidiary of MarkWest Energy Partners L.P., entered into the fifth amended
and restated credit agreement ("Partnership Credit Facility"), which provides for a maximum lending limit of $615.0 million for a five-year term. The credit facility includes a
revolving facility of $250.0 million and a $365.0 million term loan. The credit facility is guaranteed by the Partnership and all of the Partnership's subsidiaries and is collateralized
by substantially all of the Partnership's assets and those of its subsidiaries. The borrowings under the credit facility bear interest at a variable interest rate, plus basis points. The basis points
vary based on the ratio of the Partnership's Consolidated Debt (as defined in the Partnership Credit Facility) to Consolidated EBITDA (as defined in the Partnership Credit Facility), ranging from
0.50% to 1.50% for Base Rate loans, and 1.50% to 2.50% for Eurodollar Rate loans. The basis points will increase by 0.50% during any period (not to exceed 270 days) where the Partnership makes
an acquisition for a purchase price in excess of $50.0 million ("Acquisition





Adjustment Period"). For the year ended December 31, 2006, the weighted average interest rate on the Partnership Credit Facility was 7.2%. The Partnership was in compliance with all debt
covenants at December 31, 2006.

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

Year ended December 31,2007

$
2008


2009


2010


30,0002011


Thereafter


500,000Totals

$
530,000


13.    Derivative financial instruments (As Restated)

Subsequent to the issuance of the Company's 2006 financial statements, the Company's management determined that the "MarkWest Hydrocarbon Standalone" contract
volumes as previously reported in columns "Fixed Physical Forwards" and "Fixed Swaps" incorrectly presented total volumes rather than daily volumes as noted. As a result, the contract volumes in the
"Fixed Physical Forwards" and "Fixed Swaps" columns within the "MarkWest Hydrocarbon Standalone" tables herein have been restated from the amounts previously reported to appropriately reflect daily
contract volumes.

105

---





Our primary risk management objective is to manage volatility in our cash flows. A committee comprised of members of the senior management team 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 Company may also enter into futures contracts traded on the New York Mercantile Exchange ("NYMEX"). Swaps and futures contracts allow us to manage volatility in our margins because
corresponding losses or gains on the financial instruments are generally offset by gains or losses in our physical positions.

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

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

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).



MarkWest Hydrocarbon Standalone may enter into physical and/or financial positions to manage its risks related to commodity price exposure. Due to timing of
purchases and sales, direct exposure to price volatility can be created because there is no longer an offsetting purchase or sale that remains exposed to market pricing. Through marketing and
derivatives activities, direct exposure may occur naturally, or we may choose direct exposure when we favor that exposure over frac spread risk. Beginning in 2006 MarkWest Hydrocarbon Standalone
pre-purchased natural gas for shrink requirements in future months and, for both natural gas and NGLs, entered into swaps and future sales agreements to manage frac spread risk. These
derivative instruments are marked to market.

106

---



The
following tables summarize the current derivative positions specific to MarkWest Hydrocarbon Standalone's segment at December 31, 2006 (in thousands, except price data):

|Fixed Physical Forwards              |  | Contract Period |  | Price |       | Fair Value |  
|------------------------------------ |  | --------------- |  | ----- | ----- | ---------- | -
|Natural Gas6,371 MMBtu/d (sale)     |  | Jan 2007        |  | $     | 10.48 |            | $
|Natural Gas6,371 MMBtu/d (purchase) |  | Jan 2007        |  |       | 8.95  |            |  
|Natural Gas7,143 MMBtu/d (sale)     |  | Feb 2007        |  |       | 10.76 |            |  
|Natural Gas7,143 MMBtu/d (purchase) |  | Feb 2007        |  |       | 9.07  |            |  
|Natural Gas6,308 MMBtu/d (sale)     |  | Apr 2007        |  |       | 7.48  |            |  
|Natural Gas2,284 MMBtu/d (sale)     |  | May 2007        |  |       | 7.48  |            |  
|Natural Gas4,665 MMBtu/d (sale)     |  | Jun 2007        |  |       | 7.48  |            |  
|                                     |  |                 |  |       |       |            |  
|                                     |  |                 |  |       |       |            | $
|                                     |  |                 |  |       |       |            |  

|Fixed Swaps(1)                        |  | Contract Period |  | Price(2) |       | Fair Value |  
|------------------------------------- |  | --------------- |  | -------- | ----- | ---------- | -
|Crude139 Bbl/d (sale)                |  | Apr 2007        |  | $        | 63.86 |            | $
|Crude139 Bbl/d (sale)                |  | Apr 2007        |  |          | 64.87 |            |  
|Crude955 Bbl/d (sale)                |  | Apr-Jun 2007    |  |          | 71.33 |            |  
|Crude18 Bbl/d (sale)                 |  | May 2007        |  |          | 63.89 |            |  
|Crude18 Bbl/d (sale)                 |  | May 2007        |  |          | 65.35 |            |  
|Crude121 Bbl/d (sale)                |  | Jun 2007        |  |          | 64.83 |            |  
|Crude121 Bbl/d (sale)                |  | Jun 2007        |  |          | 65.81 |            |  
|Crude662 Bbl/d (sale)                |  | Jul 2007        |  |          | 65.19 |            |  
|Crude662 Bbl/d (sale)                |  | Jul 2007        |  |          | 66.17 |            |  
|Crude698 Bbl/d (sale)                |  | Aug 2007        |  |          | 65.50 |            |  
|Crude698 Bbl/d (sale)                |  | Aug 2007        |  |          | 66.48 |            |  
|Crude773 Bbl/d (sale)                |  | Sep 2007        |  |          | 65.77 |            |  
|Crude773 Bbl/d (sale)                |  | Sep 2007        |  |          | 66.75 |            |  
|Crude1,252 Bbl/d (sale)              |  | Oct 2007        |  |          | 65.99 |            |  
|Crude1,252 Bbl/d (sale)              |  | Oct 2007        |  |          | 66.97 |            |  
|Crude1,383 Bbl/d (sale)              |  | Nov 2007        |  |          | 66.21 |            |  
|Crude1,383 Bbl/d (sale)              |  | Nov 2007        |  |          | 67.19 |            |  
|Crude1,958 Bbl/d (sale)              |  | Dec 2007        |  |          | 66.46 |            |  
|Crude1,958 Bbl/d (sale)              |  | Dec 2007        |  |          | 67.35 |            |  
|Natural Gas7,088 MMBtu/d (purchase)  |  | Apr 2007        |  |          | 8.16  |            |  
|Natural Gas86,850 MMBtu/d (purchase) |  | May 2007        |  |          | 8.08  |            |  
|Natural Gas13,167 MMBtu/d (purchase) |  | Jun 2007        |  |          | 8.16  |            |  
|Natural Gas12,581 MMBtu/d (purchase) |  | Jul 2007        |  |          | 8.29  |            |  
|Natural Gas12,258 MMBtu/d (purchase) |  | Aug 2007        |  |          | 8.35  |            |  
|Natural Gas4,833 MMBtu/d (purchase)  |  | Sep 2007        |  |          | 8.38  |            |  
|                                      |  |                 |  |          |       |            |  

107

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|IsoButane6,231 Gal/d (sale)         |  | Jan 2007     |  |  | 1.23 |  |   | 15     |  
|------------------------------------ |  | ------------ |  |  | ---- |  | - | ------ | -
|IsoButane4,210 Gal/d (sale)         |  | Jan-Mar 2007 |  |  | 1.17 |  |   | 8      |  
|IsoButane1,974 Gal/d (sale)         |  | Jan-Mar 2007 |  |  | 1.14 |  |   | (1     | )
|IsoButane4,328 Gal/d (sale)         |  | Feb 2007     |  |  | 1.16 |  |   | 1      |  
|IsoButane3,007 Gal/d (sale)         |  | Feb-Mar 2007 |  |  | 1.35 |  |   | 36     |  
|IsoButane1,806 Gal/d (sale)         |  | Mar 2007     |  |  | 1.28 |  |   | 8      |  
|Natural Gasoline17,756 Gal/d (sale) |  | Jan 2007     |  |  | 1.46 |  |   | 72     |  
|Natural Gasoline12,446 Gal/d (sale) |  | Jan-Mar 2007 |  |  | 1.37 |  |   | 52     |  
|Natural Gasoline10,468 Gal/d (sale) |  | Feb 2007     |  |  | 1.33 |  |   | 2      |  
|Natural Gasoline10,034 Gal/d (sale) |  | Feb-Mar 2007 |  |  | 1.59 |  |   | 159    |  
|Natural Gasoline4,387 Gal/d (sale)  |  | Mar 2007     |  |  | 1.62 |  |   | 40     |  
|Normal Butane21,018 Gal/d (sale)    |  | Jan 2007     |  |  | 1.20 |  |   | 51     |  
|Normal Butane18,981 Gal/d (sale)    |  | Jan-Mar 2007 |  |  | 1.13 |  |   | 24     |  
|Normal Butane13,879 Gal/d (sale)    |  | Feb 2007     |  |  | 1.12 |  |   | 1      |  
|Normal Butane10,712 Gal/d (sale)    |  | Feb-Mar 2007 |  |  | 1.29 |  |   | 108    |  
|Normal Butane5,839 Gal/d (sale)     |  | Mar 2007     |  |  | 1.28 |  |   | 30     |  
|Propane211,643 Gal/d (sale)         |  | Jan 2007     |  |  | 1.09 |  |   | 1,071  |  
|Propane3,559 Gal/d (sale)           |  | Jan-Feb 2007 |  |  | 1.05 |  |   | 26     |  
|Propane71,516 Gal/d (sale)          |  | Jan-Mar 2007 |  |  | 0.96 |  |   | 284    |  
|Propane178,742 Gal/d (sale)         |  | Feb 2007     |  |  | 1.06 |  |   | 695    |  
|Propane23,797 Gal/d (sale)          |  | Feb-Mar 2007 |  |  | 1.18 |  |   | 360    |  
|Propane25,806 Gal/d (sale)          |  | Mar 2007     |  |  | 1.13 |  |   | 174    |  
|                                     |  |              |  |  |      |  |   |       
|                                     |  |              |  |  |      |  | $ | (1,026 | )
|                                     |  |              |  |  |      |  |   |       

Forward Physical Contracts

Price(2)

Fair ValueNatural Gas9,000 MMBtu/d

$
7.56

$
(1,417
)CurrentTotal MarkWest Hydrocarbon Standalone




$
(1,658
)




108

---





The
following table summarizes the non-current derivative positions specific to MarkWest Hydrocarbon Standalone's segment at December 31, 2006 (in thousands, except
price data):

Fixed Swaps(1)

Contract Period

Price

Fair ValueCrude2,181 Bbl/d (sale)

Jan 2008

$
67.48

$
16Crude2,181 Bbl/d (sale)

Jan 2008


66.59


(40
)Crude1,956 Bbl/d (sale)

Feb 2008


67.58


12Crude1,956 Bbl/d (sale)

Feb 2008


66.70


(35
)Crude1,160 Bbl/d (sale)

Mar 2008


67.67


7Crude1,160 Bbl/d (sale)

Mar 2008


66.78


(23
)Non-currentTotal MarkWest Hydrocarbon Standalone






$
(63
)




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

December 31,2006

2005Fair value of derivative instruments:Current asset

$
5,727

$
Noncurrent asset


35


Current liability


7,385


Noncurrent liability


98







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 Partnership's sales of physical product. While the Partnership largely expects it's realized derivative gains and losses to be offset by increases or
decreases in the value of its physical sales, it will experience volatility in reported earnings due to the recording of unrealized gains and losses on its 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, it ultimately expects those gains and losses to
be offset when they become realized.

109

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The
following tables summarize the current derivative positions specific to MarkWest Energy Partner's segment at December 31, 2006 (in thousands, except price data):

Fixed Swaps(1)

Contract Period

Fixed Price(2)

Fair ValueCrude390 Bbl/d (sale)

Jan-Dec 2007

$
68.46

$
473Crude600 Bbl/d (sale)

Jan-Dec 2007


64.77


(58
)Ethane50,000 Gal/d (sale)

Jan-Mar 2007


0.78


736$
1,151


Basis Swaps

Contract Period

Fair ValueNatural Gas14,000 MMBtu/d

Jan-Oct 2007

$
(33
)


Options (puts)(3)

Contract Period

Floor

Fair ValueEthane50,000 Gal/d

Apr-Jun 2007

$
0.65

$
7Ethane50,000 Gal/d

July-Sep 2007


0.65


Ethane50,000 Gal/d

Oct-Dec 2007


0.65


$
7


Collars(4)

Contract Period

Floor(2)

Cap(2)

Fair ValueCrude1,105 Bbl/d

Jan-Dec 2007

$
69.08

$
82.43

$
2,469Propane23,000 Gal/d

Jan-Mar 2007


1.05


1.28


286Propane30,000 Gal/d

Apr-Jun 2007


0.96


1.16


240Propane30,000 Gal/d

Jul-Sep 2007


0.97


1.16


Propane30,000 Gal/d

Oct-Dec 2007


0.98


1.18


2,995Current TotalMarkWest Energy Partners









$
4,120




110

---





The
following table summarizes the non-current derivative positions specific to MarkWest Energy Partner's segment at December 31, 2006 (in thousands, except price
data):

Collars(1)

Contract Period

Floor(2)

Cap(2)

Fair ValueCrude1,476 Bbl/d

Jan-Mar 2008

$
69.76

$
79.01

$
688Crude550 Bbl/d

Jan-Dec 2008


64.48


73.98


236Crude1,473 Bbl/d

Apr-Jun 2008


69.48


78.66


627Crude1,437 Bbl/d

Jul-Sep 2008


68.90


78.32


566Crude1,473 Bbl/d

Oct-Dec 2008


68.41


77.85


550Crude925 Bbl/d

Jan-Dec 2008


65.00


68.78


(172
)Crude550 Bbl/d

Jan-Dec 2009


63.13


72.58


92Crude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
)Non-CurrentTotal MarkWest Energy Partners









$
1,397




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

December 31,2006

2005Fair value of derivative instruments:Current asset

$
4,211

$
Noncurrent asset


2,759


728Current liability


91


Noncurrent liability


1,362





111

---



14.    Income taxes

The components of the income tax benefit (expense) from continuing operations are as follows (in thousands):

Year ended December 31,2006

2005

2004Current income tax benefit (expense):Federal

$
288

$
(502
)
$
(20
)State


(109
)

(52
)

Total current


179


(554
)

(20
)Deferred income tax benefit (expense):Federal


(5,416
)

2,839


286State


(15
)

(481
)

(344
)Total deferred


(5,431
)

2,358


(58
)Income tax benefit (expense)

$
(5,252
)
$
1,804

$
(78
)


A
reconciliation of the actual income tax benefit (expense) from continuing operations and the amount computed by applying the federal statutory rate of 35% to the income (loss) before
income taxes is as follows (in thousands):

Year ended December 31,2006

2005

2004Federal income tax at statutory rate(1)

$
(5,176
)
$
2,926

$
280State income taxes, net of federal benefit


(402
)

294


(7
)Permanent items


61


(16
)

Stock options subject to variable accounting








(369
)Percentage depletion in excess of cost basis








37Nondeductible expenses








(21
)Prior year adjustment for state NOL carryforward








1,085Change in valuation allowance


341


(1,053
)

(1,121
)Change in federal / state statutory rate


41


(117
)

(117
)Impact of state amended tax returns








(177
)Alternative minimum tax credit








373Texas margin tax from the Partnership


(129
)




Other


12


(230
)

(41
)Income tax benefit (expense)

$
(5,252
)
$
1,804

$
(78
)




112

---





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

December 31,2006

2005Current deferred tax assetsAccruals and reserves

$
143

$
157Derivative instruments


742


Stock compensation


134


32Other





7Current deferred tax assets


1,019


196Current deferred tax liabilitiesInvestment in third party partnerships


529


343Marketable securities


670


215Current deferred tax liabilities


1,199


558Current subtotalliability


180


362Long-term deferred tax assetsParticipation plan compensation


3,903


1,626Property, plant, and equipment





135Stock compensation





84Tax credit carryforward


2,664


2,920Federal NOL carryforward





6,145State NOL carryforward


802


2,278Long-term deferred tax assets


7,369


13,188Valuation allowance


(802
)

(2,278
)Net long-term deferred tax assets


6,567


10,910Long-term deferred tax liabilitiesProperty, plant, and equipment


82


Stock compensation


19


Investment in consolidated subsidiary


15,890


14,397Other


129


Long-term deferred tax liabilities


16,120


14,397Long-term subtotalliability


9,553


3,487Net deferred tax liability

$
9,733

$
3,849


At
December 31, 2006 the Company had state net operating loss carryforwards of approximately $14.6 million that expire between 2011 and 2026. The Company expects that
future taxable income will likely be apportioned to states other than those in which the net operating loss was generated. As a result, the Company believes it is more likely than not that the state
net operating losses will not be realized and has provided a 100% valuation allowance against this long-term deferred tax asset. The Company had federal alternative minimum tax credit
carryforwards of $2.7 million that have no expiration date and can be applied as a credit to reduce regular federal income tax.

113

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15.    Stock and Incentive Compensation Plans

All previously awarded MarkWest Hydrocarbon restricted stock, stock options and other compensation arrangements based on the market value of our common stock have
been adjusted to reflect the May 2006 stock dividend. Furthermore, all previously awarded Partnership units have been adjusted to reflect the February 2007
two-for-one unit split (see Note 2 above).

Total
compensation cost for share-based pay arrangements was as follows (in thousands):

Year ended December 31,2006

2005

2004Stock options

$
(9
)
$
965

$
1,994Restricted stock


410


84


General partner interests under Participation Plan


20,715


3,192


3,481Subordinated units under Participation Plan


28


52


230Restricted units


1,686


1,076


1,065Total compensation cost


22,830


5,369


6,770Income tax


(8,630
)

(2,013
)

(2,606
)Net compensation cost

$
14,200

$
3,356

$
4,164


Of the total compensation cost recognized for restricted units $0.1 million, $0.4 million and $0.5 million related to the accelerated vesting of restricted units for
the years ended December 31, 2006, 2005 and 2004, respectively. The accelerated vesting of restricted units occurs when specific distribution targets are achieved, as set forth in the
individual grant agreements

The
following summarizes the total compensation cost not yet recognized as of December 31, 2006, related to nonvested awards (in thousands). The actual compensation cost
recognized might differ for the restricted units, as they qualify as liability awards, which are affected by changes in the fair value.

Amount

Weighted-
average
Remaining
Vesting
Period (years)Stock options

$


Restricted stock


362

2.2Restricted units


1,769

1.8Total

$
2,131


At
December 31, 2006, the Company has three stock-based compensation plans, one of which is through its consolidated subsidiary, MarkWest Energy Partners.



In June 2006, the Company's shareholders approved the 2006 Stock Incentive Plan ("2006 Plan"), effective July 1, 2006. The 2006 Plan replaced both
the 1996 Stock Incentive Plan and the 1996 Non-employee Director Stock Option Plan (together the "1996 Plans"). Under the 2006 Plan the

114

---



Company
may grant a maximum of 1,000,000 restricted shares and stock options, subject to varying vesting terms and expected terms as discussed below.



The Company issued stock options under the 1996 Plans until 2005. While it was determined in 2005 that the Company does not intend to issue stock options in the
future, they are available for issuance under the 2006 Plan. On December 1, 2006 a board resolution provided for the accelerated vesting of 14,950 unvested stock option grants affecting eight
employees. Consequently, as of December 31, 2006 the Company had no remaining unvested options or any unrecognized compensation expense pertaining to options. For the year ended
December 31, 2006, the Company received $0.3 million from the exercise of stock options.

Under
SFAS 123R, the Company's stock options are categorized as equity awards. Accordingly, compensation expense for options is measured based on the grant date fair value and is
amortized into
earnings over the service period as the options vest. The options historically vested at the rate of 25% per year for options granted in 1999 and thereafter, and 20% per year for options granted prior
to 1999. The fair value of the options is estimated using the Black-Scholes option-pricing model. The options have a maximum term of ten years and may, at the discretion of the Company, be exercised
using either a Company-assisted or broker-assisted cashless exercise.

The
following summarizes the impact of the Company's stock option plan (in thousands of shares):

Year ended December 31,2006

2005

2004Options exercised, cashless

10

36

145Shares issued, cashless

6

23

49Options exercised, cash

39

16

193Shares issued, cash

39

16

193


The
Company did not grant any stock options in 2006 or 2005. The fair value of each option granted in 2004 was estimated using the Black-Scholes option-pricing model. The following
assumptions were used to compute the weighted average fair value of options granted:

2004Expected life of options

5.5 yearsRisk free interest rates

4.35
%Estimated volatility

46.50
%Dividend yield

2.0
%


115

---



A
summary of the status of the Company's stock option plans as of December 31, 2006, 2005 and 2004, are presented below.

|                                                 |  | Number of
Shares |   | Weighted-
average
Exercise Price |       | Weighted-
average
Remaining
Contractual
Term |     | Aggregate
Intrinsic
Value
|------------------------------------------------ |  | ---------------- | - | -------------------------------- | ----- | -------------------------------------------- | --- | -------------------------
|Outstanding at January 1, 2004                   |  | 603,019          |   | $                                | 7.42  |                                              |     |                          
|Granted                                          |  | 41,085           |   |                                  | 10.67 |                                              |     |                          
|Exercised                                        |  | (338,668         | ) |                                  | 6.91  |                                              |     |                          
|Forfeited                                        |  | (21,940          | ) |                                  | 7.03  |                                              |     |                          
|Expired                                          |  | (94,634          | ) |                                  | 10.24 |                                              |     |                          
|                                                 |  |                  |   |                                  |       |                                              |     |                          
|Outstanding at December 31, 2004                 |  | 188,862          |   |                                  | 7.66  |                                              |     |                          
|                                                 |  |                  |   |                                  |       |                                              |     |                          
|Granted                                          |  |                 |   |                                  |      |                                              |     |                          
|Exercised                                        |  | (52,989          | ) |                                  | 6.92  |                                              |     |                          
|Forfeited                                        |  | (10,011          | ) |                                  | 13.35 |                                              |     |                          
|Expired                                          |  | (453             | ) |                                  | 6.84  |                                              |     |                          
|                                                 |  |                  |   |                                  |       |                                              |     |                          
|Outstanding at December 31, 2005                 |  | 125,409          |   |                                  | 7.52  |                                              |     |                          
|                                                 |  |                  |   |                                  |       |                                              |     |                          
|Granted                                          |  |                 |   |                                  |      |                                              |     |                          
|Exercised                                        |  | (49,999          | ) |                                  | 7.34  |                                              |     |                          
|Forfeited                                        |  | (8,168           | ) |                                  | 9.00  |                                              |     |                          
|Expired                                          |  | (1,607           | ) |                                  | 7.52  |                                              |     |                          
|                                                 |  |                  |   |                                  |       |                                              |     |                          
|Outstanding and Exercisable at December 31, 2006 |  | 65,635           |   |                                  | 7.48  |                                              | 5.3 |                          
|                                                 |  |                  |   |                                  |       |                                              |     |                          

|                                                             |  | Year ended December 31,
|------------------------------------------------------------ |  | -----------------------
|
|Total fair value of options vested during the period         |  | $                      
|Total intrinsic value of options exercised during the period |  |                        



The Company issued restricted stock under the 1996 Plans until the adoption of the 2006 Plan at which point all new shares are, and will be, issued pursuant to
the rules of the 2006 Plan. Under SFAS 123R, the restricted stock qualifies as an equity award. Accordingly, restricted stock is measured at the grant date fair value and the associated
compensation expense is recognized over the requisite service period, reduced for an estimate of expected forfeitures. The restricted stock vests equally over a three year period. No shares were
granted prior to 2005.

116

---



The
following summarizes the impact of the Company's restricted stock plans:

|                              |  | Number of
Shares |   | Weighted-
average
Grant-date
Fair Value
|----------------------------- |  | ---------------- | - | ---------------------------------------
|Unvested at January 1, 2005   |  |                 |   | $                                      
|Granted                       |  | 28,237           |   |                                        
|Vested                        |  | (3,300           | ) |                                        
|Forfeited                     |  |                 |   |                                        
|                              |  |                  |   |                                        
|Unvested at December 31, 2005 |  | 24,937           |   |                                        
|                              |  |                  |   |                                        
|Granted                       |  | 28,109           |   |                                        
|Vested                        |  | (8,243           | ) |                                        
|Forfeited                     |  | (3,110           | ) |                                        
|                              |  |                  |   |                                        
|Unvested at December 31, 2006 |  | 41,693           |   |                                        
|                              |  |                  |   |                                        

|                                                                                                                                    |  | Year ended December 31,
|----------------------------------------------------------------------------------------------------------------------------------- |  | -----------------------
|
|Weighted-average grant-date fair value of restricted stock granted during the period                                                |  | $                      
|Total fair value of restricted stock vested during the period / total intrinsic value of restricted stock settled during the period |  |                        

During
the years ended December 31, 2006, 2005 and 2004, the Company received no proceeds for issuing restricted stock, and there were no cash settlements.



The Company has also entered into arrangements with certain directors and employees of the Company referred to as the Participation Plan. Under it, the Company
sells subordinated units of the Partnership or interests in the Partnership's general partner under a purchase and sale agreement. There is no maximum contractual term under the Participation Plan.
The Company's capacity to grant further general partner interests is limited by its ownership in the general partner. The subordinated units are sold without any restrictions on transfer.

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. Under SFAS 123R, the subordinated units and general partner interests are classified as liability
awards. As a result, the Company is required to mark to market the subordinated unit and general partner interest valuations at the end of each period. Compensation expense related to general partner
interests is calculated as the difference in the formula value and the amount paid by those individuals. The formula value is the amount MarkWest Hydrocarbon would have to pay the employees and
directors to repurchase the general partner interests, and is based on the current market value of the Partnership's common units and the current quarterly distributions paid.

117

---



The
interest in the Partnership's general partner is sold with certain put-and-call provisions. These require MarkWest Hydrocarbon to buy back, or require the
individuals to sell back their interest in the general partner to MarkWest Hydrocarbon. Specifically, the employees and directors can exercise their put if (1) MarkWest Hydrocarbon or the
Partnership's general partner undergoes a change of control; (2) additional membership interests are issued that, on a pro forma basis, decrease the distributions to all the then
existing members; (3) any amendment, alteration or repeal of the provisions of the general partner agreement materially and adversely affects the then existing rights, duties, obligations or
restrictions of the employees and directors; or (4) the employee or director (i) becomes totally disabled while a director, officer or employee of the general partner, of MarkWest
Hydrocarbon or of any of their affiliates, or (ii) dies, or (iii) retires as a director, officer or employee of the general partner of MarkWest Hydrocarbon or of any of their affiliates
after reaching the age of 60 years. The employee or his estate has 120 days after the put event to exercise the put under (4) and 30 days after notice to exercise under
(1) through (3). MarkWest Hydrocarbon can exercise its call option if (i) the employee or director ceases to be a director or employee of MarkWest Hydrocarbon or any of its affiliates,
or (ii) if there is a change of control of MarkWest or of the Partnership's general partner. For the call option based upon a termination of employment or directorship, MarkWest Hydrocarbon has
12 months following the termination date to exercise its call option. MarkWest Hydrocarbon has agreed to exempt the general partner interests of three present or former directors from the call
option based upon a termination of employment or directorship. Additionally, pursuant to the terms of our current CEO's employment agreement with MarkWest Hydrocarbon, all of his general partner
interest has become exempt from the call option based upon a termination of employment or directorship for reasons other than cause. For the call option based upon a change of control of MarkWest or
of the Partnership's general partner, MarkWest Hydrocarbon has 30 days following the change of control to exercise its call option.

On
October 13, 2006, the Company completed the repurchase of a 0.5% interest in the general partner. This purchase resulted in an increase in our ownership level in the general
partner to 89.7%. The Company did not sell any subordinated units to employees or directors in 2006 or 2005. Likewise, the Company did not reacquire any subordinated units in 2006 or 2005.



The number of restricted units available for issuance under the LTIP has been adjusted to reflect the February 2007 two-for-one
unit split (see Note 2 above).

The
general partner has adopted the MarkWest Energy Partners, L.P. Long-Term Incentive Plan for employees and directors of the general partner, as well as employees of its
affiliates who perform services for us. The plan consists of restricted units and unit options. It permits the grant of awards covering an aggregate of 1,000,000 common units, comprised of 400,000
restricted units and 600,000 unit options. The Compensation Committee of the general partner's Board of Directors administers the plan.



A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit of the Partnership 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 vest over a service

118

---



period
of three years; however, vesting for certain awards may be accelerated if specific annualized distribution goals are met. During the vesting period, these restricted units are entitled to
receive distribution equivalents, which represent cash equal to the amount of distributions made on common units.

Under
SFAS 123R, the restricted units are treated as liability awards. 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 at each reporting date. The fair value of the units awarded is amortized
into earnings over the period of service and is adjusted monthly for the change in the fair value of the unvested units granted.

The
following is a summary of restricted unit activity under the Partnership's Long-Term Incentive Plan:

|                               |  | Number
of Units |   | Weighted-
average
Grant-date
Fair Value
|------------------------------ |  | --------------- | - | ---------------------------------------
|Nonvested at January 1, 2004   |  | 68,992          |   | $                                      
|Granted                        |  | 55,800          |   |                                        
|Vested                         |  | (54,906         | ) |                                        
|Forfeited                      |  | (10,886         | ) |                                        
|                               |  |                 |   |                                        
|Nonvested at December 31, 2004 |  | 59,000          |   |                                        
|                               |  |                 |   |                                        
|Granted                        |  | 40,278          |   |                                        
|Vested                         |  | (18,200         | ) |                                        
|Forfeited                      |  | (3,350          | ) |                                        
|                               |  |                 |   |                                        
|Nonvested at December 31, 2005 |  | 77,728          |   |                                        
|                               |  |                 |   |                                        
|Granted                        |  | 81,886          |   |                                        
|Vested                         |  | (26,986         | ) |                                        
|Forfeited                      |  | (7,428          | ) |                                        
|                               |  |                 |   |                                        
|Nonvested at December 31, 2006 |  | 125,200         |   |                                        
|                               |  |                 |   |                                        

|                                                                                                                   |  | Year ended December 31,
|------------------------------------------------------------------------------------------------------------------ |  | -----------------------
|
|Weighted-average grant-date fair value of restricted units granted for the year ended                              |  | $                      
|Total fair value of restricted units vested / total intrinsic value of restricted units settled for the year ended |  |                        

For
the year ended December 31, 2006, the Partnership issued 26,986 common units for vested restricted units. For the years ended December 31, 2005 and 2004 the partnership
issued 17,700 and 54,596 common units, respectively and an additional 500 units were acquired in the open market in 2005.

Of
the total number of restricted units that vested in 2006, 2005 and 2004, the Partnership received no proceeds for issuing restricted units (other than the contributions by the general
partner to maintain

119

---



its
2% ownership interest), and there were no cash settlements. Additionally, in 2004 the Partnership's opted to redeem 310 restricted units for cash.

Unit Options.The Compensation Committee has the authority to make grants of unit options under the plan to employees and
directors containing such terms as the committee shall determine. Unit options are exercisable over a period determined by the Compensation Committee. Unit options also are exercisable upon a change
in control of the Partnership, the general partner, MarkWest Hydrocarbon or upon the achievement of specified financial objectives.

As
of December 31, 2006, the Partnership had not granted any unit options.

16.    Employee Benefit Plan

The Company made contributions of $1.0 million, $1.0 million and $0.5 million to a 401(k) savings and profit-sharing plan for the years ended
December 31, 2006, 2005 and 2004, respectively. The Company did not contribute any common shares to a 401(k) savings or profit-sharing plan for the year ended December 31, 2006. The
Company contributed approximately 12,000 and 15,000 common shares to a 401(k) savings and profit-sharing plan for the years ended December 31, 2005 and 2004, respectively, with an aggregate
fair value of $1.0 million and $0.2 million, respectively. The plan is discretionary, with annual contributions determined by the Company's Board of Directors.

17.    Stockholder's equity



The Company paid quarterly cash dividends for the years ended December 31, 2006, 2005 and 2004, as retroactively restated to give effect to the 2006 and
2004 stock dividends (see below) as follows:

|Quarter ended      |  | Dividend |       | Record Date |                   | Payment Date
|------------------ |  | -------- | ----- | ----------- | ----------------- | ------------
|December 31, 2006  |  | $        | 0.300 |             | February 9, 2007  |             
|September 30, 2006 |  |          | 0.280 |             | November 9, 2006  |             
|June 30, 2006      |  |          | 0.240 |             | August 14, 2006   |             
|March 31, 2006     |  |          | 0.159 |             | May 26, 2006      |             
|December 31, 2005  |  | $        | 0.114 |             | February 15, 2006 |             
|September 30, 2005 |  |          | 0.114 |             | November 15, 2005 |             
|June 30, 2005      |  |          | 0.091 |             | August 15, 2005   |             
|March 31, 2005     |  |          | 0.091 |             | May 16, 2005      |             
|December 31, 2004  |  | $        | 0.068 |             | February 9, 2005  |             
|September 30, 2004 |  |          | 0.045 |             | November 24, 2004 |             
|June 30, 2004      |  |          | 0.021 |             | August 5, 2004    |             
|March 31, 2004     |  |          | 0.021 |             | May 5, 2004       |             

120

---





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

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



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



On February 28, 2007 the Partnership completed a two-for-one split of the Partnership's Common Units, whereby holders of record at
the close of business on February 22, 2007 received one additional Common Unit for each Common Unit owned on that date. The unit split resulted in the issuance of an additional 15,603,257
common units and 600,000 subordinated units. For all periods presented, all Partnership specific 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 to the unit split.



The Partnership priced its offering of 6,000,000 common units at $19.875 per 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 approximately $125.9 million, after the underwriters' commission and legal, accounting and other transaction expenses. The Partnership used the net proceeds from the offering, which
includes a capital contribution from its general partner to maintain its 2% general partner interest in the Partnership, to repay a portion of the outstanding indebtedness under term debt on the
Partnership Credit Facility.



The Partnership sold 1,149,428 common units to certain accredited investors at $21.75 per common unit, for gross proceeds of $25.0 million.
$20 million of the proceeds were received in December 2005. The remaining $5 million was accrued at December 31, 2005, and received in January 2006. Offering costs
of $0.1 million reduced the aggregate gross proceeds of $25.0 million to $24.9 million of net proceeds.

121

---





The Partnership sold 3,288,130 common units to certain accredited investors at $22.11 per common unit, for gross proceeds of $72.7 million. Offering costs
of $0.1 million reduced the aggregate gross proceeds of $72.7 million to $72.6 million of net proceeds.



The Partnership priced its offering of 4,314,790 common units at $21.71 per unit. The Partnership sold 4,000,000 units, for gross proceeds of
$86.8 million. The remaining 314,790 were sold by certain unitholders, who retained the proceeds. In connection with the over-allotment provisions of the underwriting agreement, the
Partnership issued an additional 647,218 common units, for gross proceeds of $14.1 million. Underwriters' fees of $4.8 million, and professional fees and other offering costs of
$0.4 million, reduced the gross proceeds of $100.9 million to $95.7 million of net proceeds. The net proceeds of $95.7 million, and the $2.1 million contributed by
the general partner to maintain its 2% interest, resulted in total net proceeds associated with the offering of $97.8 million.



The Partnership sold 2,608,876 common units to certain accredited investors at $17.25 per common unit, for gross proceeds of $45.0 million. Offering costs
of $0.9 million reduced the aggregate gross proceeds of $45.0 million to $44.1 million of net proceeds. The net proceeds of $44.1 million, and the $0.9 million
contributed by the general partner to maintain its 2% interest, resulted in total net proceeds associated with the private placement of $45.0 million.



The Partnership priced its offering of 2,296,000 common units at $19.95 per unit. The Partnership sold 2,200,888 units, for gross proceeds of
$43.9 million. The remaining 95,112 common units were sold by certain unitholders, who retained the proceeds. In connection with the over-allotment provisions of the underwriting
agreement, the Partnership issued an additional 145,000 common units, for gross proceeds of $2.9 million. Underwriters' fees of $2.5 million, and professional fees and other offering
costs of $1.3 million, reduced the gross proceeds of $46.8 million to $43.0 million of net proceeds. The net proceeds of $43.0 million, and the $0.9 million
contributed by the general partner to maintain its 2% interest, resulted in total net proceeds of $43.9 million.

18.    Commitments and contingencies



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

122

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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 captionedRicky 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, MarkWest Energy Appalachia, LLC ("MEA"). MEA
transports NGLs from the Maytown gas processing plant to MEA's Siloam fractionator. The explosion and fire from the leaked vapors resulted in property damage to several residential structures and
injuries to some of the residents.

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

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

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

123

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The
Company just recently learned that a default judgment had been entered against it in May of 2006, in an action entitledRunyan v. Eclipse Realty LLC et
al, (Arapahoe County District Court, Colorado, Case No. 06CV1054, filed February 2006). The Company was not aware of having ever received a summons and was not
given any notification of a motion for default judgment. The Company is still investigating whether there ever was proper service of process. The action involves a personal injury claim by an
individual who allegedly slipped and fell due to snowy conditions while approaching the office building in which the Company was one of several tenants. Eclipse Realty, the landlord of the building,
was responsible for the maintenance and upkeep of the common areas of the office building. The Company is seeking to have the default judgment vacated, and then having the Company dismissed as an
improper party to the action. The Company also has a contractual indemnification from Eclipse Realty, the landlord of the building, and we have demanded that Eclipse Realty defend and indemnify the
Company. We are unable to predict the outcome of our motion to vacate the default judgment or our indemnification claim, but the Company does not expect at this time that the matter should have a
material adverse effect on our financial position.

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

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 theGonzalescase cited above); andEsmerejilda G. Valasquez, et al. v. Occidental Chemical Corp., et
al., Case No.A-060352-C, 128th Judicial District, Orange County, Texas, original petition filed July 10, 2006; as refiled from
previously dismissed petition captionedJesus 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. TheGonzalesaction 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 Company is a party to various other legal actions. While it is not possible to predict the outcome of the legal actions with certainty, management
is of the opinion that appropriate provision and accruals for potential losses associated with all legal actions have been made in the financial statements. In the opinion of management, none of these
actions, either individually or in the aggregate, will have a material adverse effect on the Company's financial condition, liquidity or results of operations.

124

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The Company has various non-cancelable operating lease agreements for equipment expiring at various times through fiscal 2015. Annual rent expense
under these operating leases was $9.3 million, $7.0 million and $5.2 million for the years ended December 31, 2006, 2005, and 2004, respectively. The minimum future lease
payments under these operating leases as of December 31, 2006, are as follows (in thousands):

Year ended December 31,2007

$
9,4152008


5,5212009


2,9732010


1,9422011


1,5952012 and thereafter


5,139$
26,585


19.    Related party transactions

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

There
were no outstanding related party receivables as of December 31, 2006 or 2005. The Company also has payables to MAK-J, representing its share of revenues
generated in the normal course of business, of zero and less than $0.1 million as of December 31, 2006 and 2005, respectively.

20.    Subsequent Events

On February 16, 2007, the Company entered into the first amendment to the second amended and restated credit agreement, increasing the term by one year to
August 20, 2010, and providing an
additional $50 million of credit to enable the Company to meet margin requirements associated with its derivative instruments.

In
the first quarter of 2007, the Partnership's Gulf Coast business unit received proceeds of $5.5 million from a recently concluded rate case. The proceeds will be recorded as a
reduction of facilities expense and interest income in the first quarter results of operations.

21.    Segment Information

MarkWest Hydrocarbon's operations are classified into two reportable segments:



125

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The
Company evaluates the performance of its segments and allocates resources to them based on operating income. The Company conducts its operations in the United States.

The
tables below present information about the net income or net loss for the reported segments for the three years ended December 31, 2006, 2005 and 2004 (in thousands). Net
income or net loss for each segment includes total revenues minus purchased product costs, facility expenses, selling, general and administrative expenses, depreciation, amortization of intangible
assets, accretion of asset retirement obligations and impairments and excludes interest income, interest expense, amortization of deferred financing costs, gain on sale of non-operating
assets, non-controlling interest in net income of consolidated subsidiary, miscellaneous income or expense and income taxes.

126

---



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

|                                        |                                                                                                        | MarkWest
Hydrocarbon
Standalone                                                                  |   | MarkWest
Energy
Partners |         | Consolidating
Entries |         | Total   |  
|--------------------------------------- | ------------------------------------------------------------------------------------------------------ | ------------------------------------------------------------------------------------------------ | - | ------------------------ | ------- | --------------------- | ------- | ------- | -
|Year ended December 31, 2006:           |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  
|Revenues:                               |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  
|                                        | Revenue                                                                                                |                                                                                                  | $ | 278,655                  |         | $                     | 624,279 |         | $
|                                        | Derivative gain                                                                                        |                                                                                                  |   | 4,751                    |         |                       | 5,632   |         |  
|                                        |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  
|                                        |                                                                                                        | Total revenue                                                                                    |   |                          | 283,406 |                       |         | 629,911 |  
|                                        | Purchased product costs                                                                                |                                                                                                  |   | 239,359                  |         |                       | 376,237 |         |  
|                                        | Facility expenses                                                                                      |                                                                                                  |   | 21,617                   |         |                       | 60,112  |         |  
|                                        | Selling, general and administrative expenses                                                           |                                                                                                  |   | 18,853                   |         |                       | 44,185  |         |  
|                                        | Depreciation                                                                                           |                                                                                                  |   | 1,017                    |         |                       | 29,993  |         |  
|                                        | Amortization of intangible assets                                                                      |                                                                                                  |   |                         |         |                       | 16,047  |         |  
|                                        | Accretion of asset retirement and lease obligations                                                    |                                                                                                  |   |                         |         |                       | 102     |         |  
|                                        |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  
|                                        |                                                                                                        | Income from operations                                                                           |   |                          | 2,560   |                       |         | 103,235 |  
|Other income (expense):                 |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  
|Earnings from unconsolidated affiliates |                                                                                                        |                                                                                                  |  |                          |         | 5,316                 |         |         | 
|                                        | Interest income                                                                                        |                                                                                                  |   | 612                      |         |                       | 962     |         |  
|                                        | Interest expense                                                                                       |                                                                                                  |   | (276                     | )       |                       | (40,666 | )       |  
|                                        | Amortization of deferred financing costs and original issue discount (a component of interest expense) |                                                                                                  |   | (135                     | )       |                       | (9,094  | )       |  
|                                        | Dividend income                                                                                        |                                                                                                  |   | 447                      |         |                       |        |         |  
|                                        | Miscellaneous income                                                                                   |                                                                                                  |   | 437                      |         |                       | 11,100  |         |  
|                                        |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  
|                                        |                                                                                                        | Income before non-controlling interest in net income of consolidated subsidiary and income taxes |   |                          | 3,645   |                       |         | 70,853  |  
|                                        | Income tax expense                                                                                     |                                                                                                  |   | (5,124                   | )       |                       | (769    | )       |  
|                                        | Non-controlling interest in net income of consolidated subsidiary                                      |                                                                                                  |   |                         |         |                       |        |         |  
|                                        | Interest in net income of consolidated subsidiary                                                      |                                                                                                  |   | 11,016                   |         |                       |        |         |  
|                                        |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  
|                                        | Net income                                                                                             |                                                                                                  | $ | 9,537                    |         | $                     | 70,084  |         | $
|                                        |                                                                                                        |                                                                                                  |   |                          |         |                       |         |         |  

127

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|                              |                                                                                                        | MarkWest
Hydrocarbon
Standalone                                                                         |   | MarkWest
Energy
Partners |         | Consolidating
Entries |         | Total   |  
|----------------------------- | ------------------------------------------------------------------------------------------------------ | ------------------------------------------------------------------------------------------------------- | - | ------------------------ | ------- | --------------------- | ------- | ------- | -
|Year ended December 31, 2005: |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|Revenues:                     |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              | Revenue                                                                                                |                                                                                                         | $ | 281,362                  |         | $                     | 542,941 |         | $
|                              | Derivative loss                                                                                        |                                                                                                         |   | (1,347                   | )       |                       | (1,851  | )       |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Total revenue                                                                                           |   |                          | 280,015 |                       |         | 541,090 |  
|                              | Purchased product costs                                                                                |                                                                                                         |   | 258,188                  |         |                       | 408,884 |         |  
|                              | Facility expenses                                                                                      |                                                                                                         |   | 20,545                   |         |                       | 47,972  |         |  
|                              | Selling, general and administrative expenses                                                           |                                                                                                         |   | 11,777                   |         |                       | 21,573  |         |  
|                              | Depreciation                                                                                           |                                                                                                         |   | 1,295                    |         |                       | 19,534  |         |  
|                              | Amortization of intangible assets                                                                      |                                                                                                         |   |                         |         |                       | 9,656   |         |  
|                              | Accretion of asset retirement and lease obligations                                                    |                                                                                                         |   | 1                        |         |                       | 159     |         |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Income (loss) from operations                                                                           |   |                          | (11,791 | )                     |         | 33,312  |  
|Other income (expense):       |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              | Losses from unconsolidated affiliates                                                                  |                                                                                                         |   |                         |         |                       | (2,153  | )       |  
|                              | Interest income                                                                                        |                                                                                                         |   | 693                      |         |                       | 367     |         |  
|                              | Interest expense                                                                                       |                                                                                                         |   | (153                     | )       |                       | (22,469 | )       |  
|                              | Amortization of deferred financing costs and original issue discount (a component of interest expense) |                                                                                                         |   | (199                     | )       |                       | (6,780  | )       |  
|                              | Dividend income                                                                                        |                                                                                                         |   | 392                      |         |                       |        |         |  
|                              | Miscellaneous income                                                                                   |                                                                                                         |   | 215                      |         |                       | 51      |         |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes |   |                          | (10,843 | )                     |         | 2,328   |  
|                              | Income tax benefit                                                                                     |                                                                                                         |   | 1,804                    |         |                       |        |         |  
|                              | Non-controlling interest in net income of consolidated subsidiary                                      |                                                                                                         |   |                         |         |                       | 27      |         |  
|                              | Interest in net income of consolidated subsidiary                                                      |                                                                                                         |   | 2,237                    |         |                       |        |         |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  
|                              |                                                                                                        | Net income (loss)                                                                                       |   | $                        | (6,802  | )                     | $       | 2,355   |  
|                              |                                                                                                        |                                                                                                         |   |                          |         |                       |         |         |  

128

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|                                                                  |                                                                                                         | Markwest
Hydrocarbon
Standalone |       | Markwest
Energy
Partners |         | Consolidating
Entries |         | Total   |       
|----------------------------------------------------------------- | ------------------------------------------------------------------------------------------------------- | ------------------------------- | ----- | ------------------------ | ------- | --------------------- | ------- | ------- | ------
|Year ended December 31, 2004:                                     |                                                                                                         |                                 |       |                          |         |                       |         |         |       
|Revenues:                                                         |                                                                                                         |                                 |       |                          |         |                       |         |         |       
|                                                                  | Revenue                                                                                                 |                                 | $     | 222,082                  |         | $                     | 319,939 |         | $     
|                                                                  | Derivative loss                                                                                         |                                 |       | (3,745                   | )       |                       | (820    | )       |       
|                                                                  |                                                                                                         |                                 |       |                          |         |                       |         |         |       
|                                                                  |                                                                                                         | Total revenue                   |       |                          | 218,337 |                       |         | 319,119 |       
|                                                                  | Purchased product costs                                                                                 |                                 |       | 185,951                  |         |                       | 229,339 |         |       
|                                                                  | Facility expenses                                                                                       |                                 |       | 23,983                   |         |                       | 29,911  |         |       
|                                                                  | Selling, general and administrative expenses                                                            |                                 |       | 11,999                   |         |                       | 16,133  |         |       
|                                                                  | Depreciation                                                                                            |                                 |       | 1,339                    |         |                       | 15,556  |         |       
|                                                                  | Amortization of intangible assets                                                                       |                                 |       |                         |         |                       | 3,640   |         |       
|                                                                  | Accretion of asset retirement and lease obligations                                                     |                                 |       | 2                        |         |                       | 13      |         |       
|                                                                  | Impairments                                                                                             |                                 |       |                         |         |                       | 130     |         |       
|                                                                  |                                                                                                         |                                 |       |                          |         |                       |         |         |       
|                                                                  |                                                                                                         | Income (loss) from operations   |       |                          | (4,937  | )                     |         | 24,397  |       
|Other income (expense):                                           |                                                                                                         |                                 |       |                          |         |                       |         |         |       
|                                                                  | Interest income                                                                                         |                                 |       | 560                      |         |                       | 87      |         |       
|                                                                  | Interest expense                                                                                        |                                 |       | (147                     | )       |                       | (9,236  | )       |       
|                                                                  | Amortization of deferred financing costs and original issue discount (a component of interest expense)  |                                 |       | (45                      | )       |                       | (5,236  | )       |       
|Dividend income                                                   |                                                                                                         |                                 | 259   |                          |         |                      |         |         |      
|Miscellaneous income (expense)                                    |                                                                                                         |                                 | 838   |                          |         | (50                   | )       |         |      
|                                                                  |                                                                                                         |                                 |       |                          |         |                       |         |         |       
|                                                                  | Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes |                                 |       | (3,472                   | )       |                       | 9,962   |         |       
|Income tax expense                                                |                                                                                                         |                                 | (78   | )                        |         |                      |         |         |      
|Non-controlling interest in net income of consolidated subsidiary |                                                                                                         |                                 | 511   |                          |         |                      |         |         | (7,826
|Interest in net income of consolidated subsidiary                 |                                                                                                         |                                 | 2,136 |                          |         |                      |         |         | (2,136
|                                                                  |                                                                                                         |                                 |       |                          |         |                       |         |         |       
|                                                                  | Net income (loss)                                                                                       |                                 | $     | (903                     | )       | $                     | 9,962   |         | $     
|                                                                  |                                                                                                         |                                 |       |                          |         |                       |         |         |       

129

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22.    Quarterly Results of Operations (Unaudited)

The following summarizes the Company's quarterly results of operations for 2006 and 2005 (in thousands, except per share data):

|                             |         | Three months ended |        
|---------------------------- | ------- | ------------------ | -------
|
|
|Revenue                      |         | $                  | 250,644
|Income from operations       |         |                    | 21,955 
|Net income (loss)            |         |                    | 2,832  
|Net income (loss) per share: |         |                    |        
|                             | Basic   |                    | $      
|                             | Diluted |                    | $      

|                              |         | Three months ended |        
|----------------------------- | ------- | ------------------ | -------
|
|
|Revenue                       |         | $                  | 147,463
|Income (loss) from operations |         |                    | 9,446  
|Net income (loss)             |         |                    | 1,539  
|Net income (loss) per share:  |         |                    |        
|                              | Basic   |                    | $      
|                              | Diluted |                    | $      

23.    Valuation and Qualifying Accounts

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

December 31,2006

2005

2004Balance, beginning of period

$
175

$
249

$
120Charged to costs and expenses


141


46


277Other charges(1)


(160
)

(120
)

(148
)Balance, end of period

$
156

$
175

$
249




24.    Restatement of Consolidated Financial Statements

Subsequent to the issuance of the Company's 2006 consolidated financial statements the Company determined that certain revenue transactions in the Partnership's
East Texas segment were reported net and should be accounted for gross as a principal, pursuant to EITF Issue No. 99-19,Revenue Gross as a Principal versus
Net as an Agent ("EITF 99-19").EITF 99-19 requires the Company to record revenue gross when it acts as the
principal in a transaction and net when it acts as an agent. As a result, the Company has restated its consolidated financial statements for the years ended December 31, 2006 and 2005.

130

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The
following tables present the impact of the restatement on the affected line items of the Consolidated Statements of Operations for the periods presented (in thousands):

|                         |  | Year ended
December 31, 2006 |         | Year ended
December 31, 2005
|------------------------ |  | ---------------------------- | ------- | ----------------------------
|
|Revenues                 |  | $                            | 775,339 |                             
|Total revenues           |  |                              | 785,722 |                             
|Purchased product costs  |  |                              | 512,327 |                             
|Total operating expenses |  |                              | 679,927 |                             

This restatement has the effect of increasing the amounts included in the revenue line item "Revenues" and increasing, by the same amount, the amounts included in "Purchased product
costs." 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 reflect the
correction of this error. The restatement of revenue and expenses does not affect net income, earnings per unit, the consolidated statements of stockholders' equity or the consolidated balance sheets.

131

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Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

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

Item 9A. Controls and Procedures (Revised)



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

In connection with the restatement of its financial statements to correct an error in accounting for certain revenue arrangements in our East Texas segment which were inappropriately
accounted for net as an agent, the Company reevaluated its disclosure controls and procedures. In connection with the preparation of this restated Annual Report, our management, with the participation
of our Chief Executive Officer and our Chief Financial Officer, carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of
December 31, 2006. In making this evaluation, our management considered the material weakness discussed in Management's Report on Internal Control Over Financial Reporting. Based on this
evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of December 31,
2006.

Changes in Internal Control Over Financial Reporting

There have been changes in our internal controls over financial reporting that occurred during the fiscal quarter ended December 31, 2006 that have
materially affected or are reasonably likely to materially affect our internal controls over financial reporting:

Remediation of Prior Year's Material Weaknesses in Internal Control

As reported in Item 9A of the Company's 2005 Form 10-K/A, material weaknesses existed in the Company's control structure as of
December 31, 2005 and 2004. The remediation of these material weaknesses and underlying significant deficiencies were addressed by a series of actions detailed in prior filings.

132

---



Although each of the individual control changes may not be material alone, in aggregate the control changes implemented have had a material impact on the effectiveness of the control
environment.

Internal Control Environment.In connection with management's assessment of the effectiveness of internal control over
financial reporting for the year ended December 31, 2005, we identified the presence of an ongoing material weakness related to our internal control environment. Specifically, our control
environment did not sufficiently promote effective internal control over financial reporting through the management structure to prevent a material misstatement, as was evidenced by deficiencies or
significant deficiencies.

In order to remediate this material weakness, we completed the following actions between July 2005 and December 2006:

Deficiency or significant deficiency identified at December 31, 2005, and the remediation activity:



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Risk Management.In connection with management's assessment of the effectiveness of internal control over financial reporting
for the year ended December 31, 2005, we identified, as of December 31, 2005, the presence of a material weakness related to our risk management. We did not have adequate internal
controls and processes in place to support our management's assertions with respect to the completeness, accuracy and validity of commodity transactions. The design of internal controls over





commodity transactions did not support the independent validation of data or control and review of transaction activity. In particular, personnel responsible for executing and entering transactions
into commodity accounting systems also had duties that were not compatible with transaction execution and entry. In order to remediate this material weakness, we added the following personnel in
July 2005, January and September 2006, respectively:



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Management tests of controls conducted in the fourth quarter of 2006 and as of December 31, 2006, provide reasonable assurance that the enhanced and changed controls were
operating effectively and that the material weaknesses identified at December 31, 2005, except for the material weakness reported at December 31, 2006 and described in the 2006
Management's Report on Internal Controls Over Financial Reporting, have been remediated.

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

Remediation Efforts for Current Year's Material Weakness in Internal Control Subsequent to December 31, 2006

As reported in Management's Report on Internal Controls Over Financial Reporting, a material weakness existed related to proper contract accounting for certain
technical accounting issues such as accounting for derivatives and revenue recognition as of December 31, 2006. Specifically, there was an issue related to our prior year material weakness that
had not been fully remediated prior to year-end. As of year-end, management did not have a process in place to monitor previously existing contracts in response to specific
technical accounting issues such as changes in SFAS No. 133 and revenue recognition issues such as whether to record revenue gross as a principal or net as an agent.

In our Form 10-K originally filed on March 7, 2007, management believed this material weakness was narrowly related to the lack of a comprehensive review of all
contracts entered into prior to 2006 for the purpose of ensuring that determinations about derivative implications and SFAS No. 133 issues had been made appropriately and remained appropriate.
The reason such a comprehensive review was deemed necessary was because the determinations related to these historical contracts were originally made in an environment where material weaknesses are
known to have existed. Inappropriate conclusions could lead to errors, the most significant of which would likely be in recognition of unrealized gains or losses. Prior to our Form 10K
originally filed on March 7, 2007, management had enhanced the process for identifying derivatives and conducted a comprehensive review of substantially all contracts across the Company to
determine whether derivatives and embedded derivatives have been appropriately identified and that those determinations remain appropriate given evolving literature. No errors with respect to
derivatives and embedded derivatives were noted in that review process.

Subsequent to March 7, 2007, management determined that in addition to the improper evaluation of derivatives, other contract accounting issues existed at December 31,
2006, specifically related to recording revenue gross as a principal or net as an agent.

Subsequent to December 31, 2006, management has enhanced its contract accounting review process to ensure appropriate accounting treatment for new and previously existing
contracts. Management has also completed a reevaluation of all critical accounting memos that have a direct impact on contract accounting. In addition, management will enhance existing contract
accounting review checklists to ensure proper accounting analysis of significant revenue recognition and technical accounting areas.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING (REVISED)

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in
Rule 13a-15(f) under the Exchange Act. The Company's

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internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles in the United States of America and includes those policies and procedures that:



Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and
operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.



Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation
of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance
with the policies or procedures deteriorates.

Management assessed the effectiveness of our internal controls over financial reporting as of December 31, 2006. In making this assessment, management used the criteria
established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). A material weakness is a deficiency, or combination of
deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented
or detected on a timely basis. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our internal control over financial reporting was not effective at the
reasonable assurance level as of December 31, 2006.

At December 31, 2006, management identified the existence of a continuing material weakness related to contract accounting. Specifically, 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.

Deloitte & Touche LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on
Form 10-K/A, has issued an attestation report on management's assessment of the effectiveness of the Company's internal control over financial reporting as of December 31,
2006. The report, which expresses an unqualified opinion on management's assessment and an adverse opinion on the effectiveness of the Company's

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internal control over financial reporting as of December 31, 2006, is included in this Item under the heading "Report of Independent Registered Public Accounting Firm".

|Date: November 2, 2007 |  | By: |  | /s/FRANK M. SEMPLEFrank M. Semple President & Chief Executive Officer          
|---------------------- |  | --- |  | -------------------------------------------------------------------------------
|Date: November 2, 2007 |  | By: |  | /s/NANCY K. BUESENancy K. Buese Senior Vice President & Chief Financial
Officer

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
MarkWest Hydrocarbon, Inc.
Denver, Colorado

We have audited management's assessment, included in the accompanying Management's Report on Internal Control Over Financial Reporting, that MarkWest Hydrocarbon, Inc. and subsidiaries (the
"Company") did not maintain effective internal control over financial reporting as of December 31, 2006, because of the effect of the material weakness identified in management's assessment
based on criteria established inInternal ControlIntegrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway
Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial
reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

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

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

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

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the
annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management's revised assessment: At
December 31, 2006, management identified and we confirmed the existence of a continuing material weakness related to accounting for contracts involving certain technical accounting issues such
as accounting for derivatives and revenue recognition. Specifically, there was an issue related to a prior year material weakness that had not been fully remediated prior to year-end. As
of year-end, management did not have a process in

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place to monitor previously existing contracts for certain technical accounting issues such as accounting for derivatives in response to changes in SFAS No. 133 and revenue recognition issues
such as whether to record revenue gross as a principal or net as an agent. Management had not conducted a comprehensive review of all contracts entered into prior to 2006 for the purpose of ensuring
that accounting for contracts involving technical accounting issues such as revenue recognition and determinations about derivative implications and SFAS No. 133 issues had been made
appropriately and remained appropriate. A comprehensive review was deemed necessary as the determinations related to these historical contracts were originally made in an environment where material
weaknesses are known to have existed. Inappropriate conclusions could lead to errors, the most significant of which would likely be in recognition of unrealized gains or losses.

The material weakness resulted from deficiencies in the design and operating effectiveness of controls relating to the ongoing monitoring of previously existing contracts for certain technical
accounting issues such as accounting for derivatives in response to changes in SFAS No. 133 and revenue recognition issues such as whether to record revenue gross as a principal or net as an
agent. The operating effectiveness deficiencies relate to the application of normal purchase/normal sale provisions of SFAS No. 133 and recording of revenue net as an agent versus gross as a
principal. This identified weakness resulted in a material adjustment requiring that revenue be recorded gross, as a principal, instead of net, as originally recorded. This adjustment of revenue and
purchased product costs represents a control deficiency and resulted in the restatement of the company's annual consolidated financials for the year ending December 31, 2005 and 2006, and the
quarters ending March 31, 2007 and June 30, 2007, as discussed in Note 23 to the consolidated financial statements.

This material weakness was considered in determining the nature, timing, and extent of audit tests applied to our audit of the consolidated financial statements as of and for the year ended
December 31, 2006, of the Company and this report does not affect our report on such financial statements.

In our opinion, management's assessment that the Company did not maintain effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material
respects, based on the criteria established inInternal ControlIntegrated Frameworkissued by the Committee of Sponsoring Organizations of
the Treadway Commission. Also, in our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, the Company has not
maintained effective internal control over financial reporting as of December 31, 2006,



based on the criteria established inInternal ControlIntegrated Frameworkissued by the Committee of Sponsoring Organizations of the
Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended
December 31, 2006, of the Company and our report dated March 7, 2007 (March 21, 2007 as to Note 13) (November 2, 2007 as to the effects of the restatement discussed
in Note 24) expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE, LLP

Denver, Colorado
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)

Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

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

|Name                 |  | Age |  | Position                                                  |  | Director
Since
|-------------------- |  | --- |  | --------------------------------------------------------- |  | --------------
|John M. Fox          |  | 66  |  | Chairman of the Board of Directors                        |  | 1988          
|Michael L. Beatty    |  | 59  |  | Director                                                  |  | 2005          
|Donald C. Heppermann |  | 64  |  | Director                                                  |  | 2002          
|William A. Kellstrom |  | 65  |  | Director                                                  |  | 2000          
|Anne E. Mounsey      |  | 40  |  | Director                                                  |  | 2004          
|Karen L. Rogers      |  | 50  |  | Director                                                  |  | 2000          
|William F. Wallace   |  | 67  |  | Director                                                  |  | 2004          
|Donald D. Wolf       |  | 63  |  | Director                                                  |  | 1999          
|Frank M. Semple      |  | 55  |  | President, Chief Executive Officer and Director           |  | 2003          
|C. Corwin Bromley    |  | 49  |  | Senior Vice President, General Counsel and Secretary      |  | NA            
|Nancy K. Buese       |  | 37  |  | Senior Vice President, Chief Financial Officer            |  | NA            
|John C. Mollenkopf   |  | 45  |  | Senior Vice President, Chief Operations Officer           |  | NA            
|Randy S. Nickerson   |  | 45  |  | Senior Vice President, Chief Commercial Officer           |  | NA            
|David L. Young       |  | 47  |  | Senior Vice President, Corporate Services                 |  | NA            
|Richard A. Ostberg   |  | 41  |  | Vice President, Compliance and Risk Management            |  | NA            
|Andrew L. Schroeder  |  | 48  |  | Vice President, Finance, Treasurer and Investor Relations |  | NA            

John M. Foxhas served as MarkWest Hydrocarbon's Chairman of the Board of Directors since its inception in April 1988, and in the
same capacity for the general partner of MarkWest Energy since May 2002. Mr. Fox also served as President and Chief Executive Officer of MarkWest Hydrocarbon and the general partner of
MarkWest Energy from April 1988 until his retirement as President on November 1, 2003 and his resignation as Chief Executive Officer effective December 31, 2003. Mr. Fox
was a founder of Western Gas Resources, Inc. and was its Executive Vice President and Chief Operating Officer from 1972 to 1986.

Michael L. Beattyhas served as a member of the Board of Directors at MarkWest Hydrocarbon sine June 2005. Mr. Beatty is
currently Chairman and CEO of the law firm of Beatty & Wozniak, P.C. located in Denver, Colorado, with a practice focused on energy and natural resources. Mr. Beatty began his career at
Vinson & Elkins and later became a professor of law at the University of Idaho before joining the legal department of Colorado Interstate Gas Company, a subsidiary of The Coastal Corporation.
Mr. Beatty thereafter served in a variety of legal positions with Coastal, ultimately becoming Executive Vice President, General Counsel and a Director of the company. Mr. Beatty also
served as Chief of Staff to Colorado Governor Roy Romer from 1993 to 1995.

Donald C. Heppermannserved as Executive Vice President, Chief Financial Officer and Secretary of MarkWest Hydrocarbon, Inc. and
the general partner of MarkWest Energy since October 2003 until his retirement in March 2004. Mr. Heppermann joined MarkWest Hydrocarbon and the general partner of the Partnership
in November 2002 as Senior Vice President and Chief Financial Officer, and served as Senior Executive Vice President beginning in January 2003. Mr. Heppermann has served as a
member of the Company's Board of Directors since November 2002 and the general partner of the Partnership's board of directors since its inception in May 2002 and serves as Chairman of
the Finance Committee. Prior to joining MarkWest Hydrocarbon and the general partner of MarkWest Energy, Mr. Heppermann was a private investor and a career executive in the energy industry with

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responsibilities
in operations, finance, business development and strategic planning. From 1990 to 1997, Mr. Heppermann served as President and Chief Operating Officer for InterCoast Energy
Company, an unregulated subsidiary of Mid American Energy Company. From 1987 to 1990, Mr. Heppermann was employed by Pinnacle West Capital Corporation, the holding company for Arizona Public
Service Company, where he was Vice President of Finance. From 1965 to 1987, Enron Corporation and its predecessors employed Mr. Heppermann in a variety of positions, including Executive Vice
President, Gas Pipeline Group.

William A. Kellstromhas served as a member of the Board of Directors of MarkWest Hydrocarbon since May 2000 and the general
partner of MarkWest Energy since its inception in May 2002. Mr. Kellstrom has held a variety of managerial positions in the natural gas industry since 1968. They include distribution,
pipelines and marketing. He held various management and executive positions with Enron Corporation, including Executive Vice President, Pipeline Marketing and Senior Vice President, Interstate
Pipelines. In 1989, he created and was President of Tenaska Marketing Ventures, a gas marketing company for the Tenaska Power Group. From 1992 until 1997 he was with NorAm Energy
Corporation (since merged with Reliant Energy, Incorporated) where he was President of the Energy Marketing Company and Senior Vice President, Corporate Development. Mr. Kellstrom retired in
1997 and is periodically engaged as a consultant to energy companies.

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

Karen L. Rogershas served as a member of the Board of Directors of MarkWest Hydrocarbon since June 2000. Ms. Rogers serves
on the Board's Audit Committee. Ms. Rogers also serves as the Chief Financial Officer for Winter Ridge Energy since October 2006. In June 2005, Ms. Rogers joined Blacksand
Energy, Inc., a privately held oil and gas development and production company, as the Chief Financial Officer. Prior to joining Blacksand Energy, Inc. Ms. Rogers was employed
since 2000 as Vice President, Energy Group, for Wells Fargo Bank N.A. Prior to 1997, Ms. Rogers was Senior Vice President and Manager of NationsBank Energy Group Denver, Inc. She has
more than 25 years of experience in energy finance and corporate banking.

William F. Wallacehas served as a member of the Board of Directors of MarkWest Hydrocarbon since June 2004. Prior to his
retirement in 2001, Mr. Wallace was Vice Chairman of the board of directors of Barrett Resources Corp. since 1996, after being named to that position in 1995 following the merger of Barrett
Resources and Plains Petroleum Co., both oil and gas exploration companies. From 1994 to 1995, Mr. Wallace was President, Chief Operating Officer and a Director of Plains Petroleum Co. Prior to
joining Plains Petroleum; Mr. Wallace spent 23 years with Texaco Inc., an integrated oil and gas company, including six years as Vice President of Exploration for Texaco USA and
as Regional Vice President of Texaco's Eastern Region. Mr. Wallace served on the Kerr-McGee Corporation board of directors from 2004 until its merger with Anadarko in 2006.
Previously, he served as a director of Westport Resources Corporation from 1997 until Westport's merger with Kerr-McGee Corporation in 2004.

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

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Frank M. Semple, President, Chief Executive Officer and Director, was appointed as President of both MarkWest Hydrocarbon and the general
partner of MarkWest Energy on November 1, 2003. Mr. Semple also became Chief Executive Officer of both MarkWest Hydrocarbon and the general partner of MarkWest Energy on
January 1, 2004. Prior to his appointment, Mr. Semple served in various capacities, most recently as Chief Operating Officer of WilTel Communications, formerly Williams Communications
Group, Inc. ("WCG") from 1997 to 2003. Prior to his tenure at WilTel Communications, he was the Senior Vice President/General Manager of Williams Natural Gas from 1995 to 1997, Vice President
of Marketing and Vice President of Operations and Engineering for Northwest Pipeline, and Director of Product Movements and Division Manager for Williams Pipeline during his 22-year career
with The Williams Companies. During his tenure at Williams Communications, he also served on the board of directors for PowerTel Communications and the Competitive Telecommunications Association
(Comptel). On April 22, 2002, WCG and one of its subsidiaries ("Debtors") filed a petition for relief under the Bankruptcy Code with the United States Bankruptcy Court for the Southern District
of New York. On September 30, 2002, the Bankruptcy Court entered an order confirming the Debtors' plan of reorganization that became effective October 15, 2002. Mr. Semple holds a
Mechanical Engineering degree from the United States Naval Academy and is a professional engineer registered in the State of Kansas.

C. Corwin Bromley, Senior Vice President, General Counsel and Secretary, was appointed as General Counsel of MarkWest Hydrocarbon MarkWest
Energy in October 2004. Prior to joining MarkWest, Mr. Bromley served as Assistant General Counsel at RAG American Coal Holding, Inc. from 1999 through 2004, and as
General-Managing Attorney and Sr. Environmental Attorney at Cyprus Amax Minerals Company from 1989 to 1999. Prior to that, Mr. Bromley was in private practice with the law firm Popham, Haik,
Schnobrich & Kaufman from 1984 through 1989. Preceding his legal career, Mr. Bromley worked as a structural/design engineer involved in several domestic and international LNG and energy
projects with the firms CBI, Inc. and Chicago Bridge and Iron Company. Mr. Bromley received his J.D. degree from the University of Denver and his bachelor's degree in civil engineering
from the University of Wyoming.

Nancy K. Buese(formerly Masten), Senior Vice President, Chief Financial Officer, was appointed Chief Financial Officer of both MarkWest
Hydrocarbon and the general partner of MarkWest Energy in October 2006. Prior to her appointment as CFO, Ms. Buese served as Chief Accounting Officer of the Company and the Partnership's
general partner since November 2005. Prior to joining MarkWest, Ms. Buese was the Chief Financial Officer for Experimental and Applied Sciences ("EAS") in Golden, Colorado. EAS is a
wholly owned subsidiary of the Ross Product Division of Abbott Laboratories. Prior to her employment at EAS, Ms. Buese was a Vice President with TransMontaigne Inc. in Denver, Colorado.
Preceding this appointment, Ms. Buese was a Partner with Ernst & Young LLP, having spent time in the firm's Denver, London, New York and Washington, D.C. offices.

John C. Mollenkopf, Senior Vice President, Chief Operations Officer, was appointed as Chief Operations Officer of both MarkWest
Hydrocarbon and the general partner of MarkWest Energy in October 2006. Prior to his appointment as COO, Mr. Mollenkopf served as Senior Vice President, Southwest Business Unit since
January 2004 and as Vice President, Business Development since January 2003. Prior to these positions he served as Vice President, Michigan Business Unit, of MarkWest Energy's general
partner since its inception in May 2002 and in the same capacity with MarkWest Hydrocarbon since December 2001. Prior to that, Mr. Mollenkopf was General Manager of the Michigan
Business Unit of MarkWest Hydrocarbon since 1997. He joined MarkWest Hydrocarbon in 1996 as Manager, New Projects. From 1983 to 1996, Mr. Mollenkopf worked for ARCO Oil and Gas
Company, holding various positions in process and project engineering, as well as operations supervision.

Randy S. Nickerson, Senior Vice President, Chief Commercial Officer, was appointed as Chief Commercial Officer of both MarkWest
Hydrocarbon and the general partner of MarkWest Energy in

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October 2006.
Prior to his appointment as CCO, Mr. Nickerson served as Senior Vice President, Corporate Development of MarkWest Hydrocarbon since October 2003, and as Executive
Vice President, Corporate Development of the Partnership's general partner since January 2003. Prior to these positions, Mr. Nickerson served as Senior Vice President of the
Partnership's general partner since its inception in May 2002 and served in the same capacity with MarkWest Hydrocarbon since December 2001. Prior to that, Mr. Nickerson served as
MarkWest Hydrocarbon's Vice President and the General Manager of the Appalachia Business Unit since June 1997. Mr. Nickerson joined MarkWest Hydrocarbon in July 1995 as Manager,
New Projects and served as General Manager of the Michigan Business Unit from June 1996 until June 1997. From 1990 to 1995, Mr. Nickerson was a Senior Project Manager and Regional
Engineering Manager for Western Gas Resources, Inc. From 1984 to 1990, Mr. Nickerson worked for Chevron USA and Meridian Oil Inc. in various process and project engineering
positions.

David L. Young, Senior Vice President, Corporate Services, was appointed to that position for both MarkWest Hydrocarbon and the
Partnership's general partner effective October 2006. Prior to that Mr. Young served as Senior Vice President, Northeast Business Unit, since February 1, 2004. Prior to joining
MarkWest, Mr. Young spent eighteen years at The Williams Companies, Inc. in Tulsa, Oklahoma, having served most recently as Vice President and General Manager of the video services
business for WilTel Communications, formerly WCG from 1997 to 2003. Prior to that, Mr. Young's management positions at The Williams Companies included serving as Senior Vice President and
General Manager for Texas Gas Pipeline and Williams Central Pipeline Company. On April 22, 2002, the Debtors filed a petition for relief under the Bankruptcy Code with the United States
Bankruptcy Court for the Southern District of New York. On September 30, 2002, the Bankruptcy Court entered an order confirming the Debtors' plan of reorganization that became effective
October 15, 2002.

Richard A. Ostberg, Vice President of Risk and Compliance, was appointed the Risk and Compliance Officer of both MarkWest Hydrocarbon and
the general partner of MarkWest Energy in July 2005. Prior to that, Mr. Ostberg served as Vice President and Controller of Black Hills Energy. Prior to Black Hills, Mr. Ostberg
spent four years with Pacific Minerals, Inc, the operator of the Bridger Coal mine and spent eight years with Deloitte & Touche LLP in their audit practice, including two years consulting from
his national office assignment in Washington, D.C.

Andrew L. Schroeder, Vice President Finance, Investor Relations, Treasurer, and Assistant Secretary has served in these with MarkWest
Hydrocarbon and the Partnership's general partner since February 2003. Prior to his appointment, he was Director of Finance/Business Development at Crestone
Energy Ventures from 2001 through 2002. Prior to that, Mr. Schroeder worked at Xcel Energy for two years as Director of Corporate Financial Analysis. Prior to that, he spent seven years working
with various energy companies. He began his career with Touche, Ross & Co. and spent eight years in public accounting. He is a Certified Public Accountant licensed in the State of Colorado.

Audit Committee Financial Expert

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

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Audit Committee Pre-Approval Policy

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

Code of Conduct and Ethics

We have adopted a Code of Conduct and Ethics that complies with SEC standards, applicable to the persons serving as our directors, officers (including, without
limitation, our CEO, CFO and Principal
Operations Officers) and employees. This includes the prompt disclosure to the SEC of a Current Report on Form 8-K of any waiver of the code for executive officers or directors
approved by the board of directors. A copy of our Code of Business Conduct and Ethics is available free of charge in print to any shareholder who sends a request to the office of the Secretary of
MarkWest Hydrocarbon, Inc. at 1515 Arapahoe Street, Suite 700, Denver, Colorado 80202. The Code of Conduct and Ethics is also posted on our website, www.markwest.com.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our directors, executive officers, and persons who own more than 10% of a
registered class of our equity securities registered under Section 12 of the Exchange Act, to file with the SEC initial reports of ownership and reports of changes in ownership in such
securities. SEC regulations also require directors, executive officers and greater than 10% stockholders to furnish us with copies of all Section 16(a) reports they file.

To
our knowledge, based solely on review of the copies of such reports furnished to us and written representations that no other reports were required, we believe our directors,
executive officers and greater than 10% stockholders complied with all Section 16(a) filing requirements during the year ended December 31, 2006, except as noted:



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

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Item 11. Executive Compensation

Compensation Discussion and Analysis

Introduction

MarkWest Hydrocarbon has developed a total compensation philosophy and structure which is designed to be both market responsive and performance based. All our
employees, including the executives are employed by MarkWest Hydrocarbon, and are compensated by MarkWest Hydrocarbon. However, the executive officers are also executive officers for the General
Partner and perform management services for the Partnership. The Partnership and its general partner, have no direct officers or employees, but instead have entered into a Services Agreement with us
to provide the day to day operational, management, accounting, personnel and related administrative services to the Partnership. Under the Services Agreement, the General Partner reimburses us for an
allocated portion of our employees' and executives' base and incentive compensation. Further, due to the relatively greater amount of cash flow and income generated by the Partnership, the Partnership
funds a proportional share of the short-term cash incentive pool available for our employees, including the executive officers. Accordingly, the General Partner's Compensation Committees
and Boards of Directors have a significant interest in and participate with us, in the determination of the compensation of our executive officers and employees. The compensation of named executive
officers presented in this Compensation Discussion and Analysis and the accompanying tables, reflect the total combined compensation for the named executive officers' services to both the Partnership
and MarkWest Hydrocarbon.

Compensation Committee



The Compensation Committee consists of three members of the board of directors, Donald D. Wolf (Chairman), William F. Wallace, and William A. Kellstrom. The
Compensation Committee is charged with overseeing the compensation of the Company's directors and executives, and with administering the Company's incentive-compensation plans, including its
equity-based plan, the MarkWest Hydrocarbon, Inc. 2006 Stock Incentive Plan. Each member of the Compensation Committee qualifies as an independent director under the requirements of the
Securities and Exchange Commission, and the American Stock Exchange.



The Compensation Committee discharges the Board's responsibilities relating to general compensation policies and practices and to compensation of our directors
and executives. The Compensation Committee also administers our incentive-compensation plans and equity-based plans. In discharging its responsibilities, the Compensation Committee establishes
principles and procedures in order to ensure to the Board and the unitholders that the compensation practices of the Company are appropriately designed and implemented to attract, retain and reward
high quality directors and executives, and are in accordance with all applicable legal and regulatory requirements. In this context, the Compensation Committee's authority, duties and responsibilities
are:



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Our Compensation Committee meets as often as necessary to perform its duties and responsibilities. The Compensation Committee held eight meetings during fiscal
2006, and the chairman of the General Partner's Compensation Committee also attended four meetings of the MarkWest Hydrocarbon Compensation Committee.

Our
Compensation Committee receives and reviews materials prepared by management, consultants, or committee members, in advance of each meeting. Depending on the agenda for the
particular meeting, these materials may include:



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Compensation Philosophy



The primary objectives of our compensation program are to attract, retain and challenge high quality executives through a total compensation plan that is both
market competitive and performance-based. We strive to accomplish these objectives by compensating all employees, including our Named Executive Officers (the "NEOs"); with total compensation packages
consisting of a combination of competitive base salary and incentive compensation. We believe that compensation should be designed to reward executives for achievement of the Company's financial plans
and strategic objectives, and to provide opportunities for increased compensation based on extraordinary performance by our employees, including our NEOs.



At the core of our compensation philosophy is our strong belief that pay should also be directly linked to performance. We believe in a pay for performance
culture that places a significant portion of executive officer total compensation as contingent upon, or variable with, individual performance, Company performance and achievement of strategic goals
including increasing shareholder value.

The
performance based compensation for our executives is in the form of (i) annual cash incentives to promote achievement of, and accountability for, shorter term performance
plans and strategic goals, and (ii) equity grants, designed to align the long-term interests of our executive officers with those of our shareholders, by creating a strong and
direct link between executive compensation and shareholder return over a multiple year performance cycle. Long term incentive equity awards are granted in restricted stock issued under the MarkWest
Hydrocarbon 2006 Stock Incentive Plan and phantom units issued under the Partnership's Long-Term Incentive Plan. These shares/units vest one-third annually over a
three-year period. In addition to the performance based equity grants, the NEOs and other key members of management have had the opportunity to purchase from the Company membership
interests in the Partnership's general partner. This opportunity for General Partner ownership was provided in order to incent and retain key employees and align their interests with our long term
strategic goals. The purchase arrangements are referred to as the Participation Plan and are discussed in further detail below.



A key component of an executive's total compensation, base salaries are designed to compensate executives commensurate with their respective level of experience,
scope of responsibilities, sustained individual performance and future potential. The goal has been to provide for base salaries that are sufficiently competitive with other similar-sized energy
companies and/or partnerships, both regionally and nationally, in order to attract and retain talented leaders.



Our compensation philosophy is based on the premise of attracting and motivating exceptional leaders, setting high goals, working toward the common objectives of
meeting the expectations of customers and stockholders, and rewarding outstanding performance. Following this philosophy, in determining NEO compensation, we consider all relevant factors, such as the
competition for talent, our desire to link pay with performance, the use of equity to align NEO interests with those of our stockholders, individual contributions, teamwork and performance, each NEO's
total compensation package, and internal pay equity.

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Compensation Setting Process



Management plays a significant role in the compensation-setting process. The most significant aspects of management role are:



The
Chief Executive Officer and the General Counsel and Secretary generally attend the Committee meetings. However, the Committee also regularly meets in executive session. The Chief
Executive Officer makes recommendations with respect to financial and corporate goals and objectives, and makes non CEO executive compensation recommendations to the Compensation Committee based on
company performance, individual performance and the peer group compensation market analysis. The Compensation Committee considers and deliberates on this information and in turn makes recommendations
to the Board of Directors, for the Board's determination and approval of the NEO's and other members of senior management's compensation, including base compensation, short-term cash
incentives and long-term equity incentives. The Chief Executive Officer's performance and compensation is reviewed, evaluated and established separately by the Compensation Committee and
ratified and approved by the Board of Directors.



To evaluate all areas of executive compensation, the Compensation Committee seeks the additional input of outside compensation consultants and available
comparative information. In 2006, our Compensation Committee engaged Towers Perrin as a compensation consultant, primarily to provide and analyze peer group data to assist our Compensation Committee
in assessing executive compensation levels, for total compensation as well as the individual base and incentive components. The peer group data assembled by Towers Perrin included data from sixteen
midstream pipeline/energy companies, replicating our industry competitors and giving a large sample size, but which included companies of varying revenue and market-cap sizes, with varying
market maturity from start-up to very mature companies. We selected these companies because they are essentially the same set of companies against which we also compare our overall
performance as a performance objective. These peer group companies include: ONEOK Partners, Hiland Partners, DCP Midstream, Regency Energy, Sunoco Logistics, Williams Partners, Magellan Midstream,
Atlas Pipeline, TEPPCO Partners, TransMontaigne Partners, Crosstex Energy, Martin Midstream, Buckeye Partners, Holly Energy, Valero, L.P., and Eagle Rock. To normalize the data for comparison, Towers
Perrin size adjusted the data using regression analysis to a revenue scope of $1 billion. While the Towers Perrin data was provided to the Compensation Committee to demonstrate the market
levels within our industry, the consultant did not provide recommendations in terms of pay package for the NEOs. Towers-Perrin did not make recommendations regarding any element of the NEO
compensation package.

We
also take into account broader based survey data for executive compensation among public companies in the energy industry, both regionally and nationally, such as the "ECI Liquid
Pipeline Roundtable 2006 Compensation Survey," conducted by Effective Compensation, Incorporated, and the Altman Weil, Inc. "Compensation Benchmarking Survey for 2006," as we believe that this
information provides us with a statistically significant sample that supplements the Towers Perrin peer group data.

148

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To evaluate our total compensation is competitive and provides appropriate rewards to attract and retain talented leaders, as discussed above, we rely on analyses
of peer companies performed by our independent compensation consultants and on other industry and occupation specific survey data available to us. Our general benchmark is to establish both base
salary and total compensation for the executive officers at the 50th percentile of the peer group data, recognizing that a significant portion of executive officer total compensation
should be contingent upon, or variable with, achievement of individual and Company performance objectives and strategic goals, as well as being variable with stockholder value. Further, while the
objective for base salary is at the 50th percentile of the peer group data, Executives' base salaries are designed to reward core competencies and contributions to the Company, and may
be increased above this general benchmark based on (i) the individual's increased contribution over the preceding year; (ii) the individual's increased responsibilities over the
preceding year; and (iii) any increase in median competitive pay levels.



The Company's annual and five year business plans and strategic objectives are presented by management at the Company's January board meeting. The board engages
in an active discussion concerning the financial targets, the appropriateness of the strategic objectives, and the difficulty in achieving same. After making changes it deems appropriate, the board
adopts the Company's annual business plan. In establishing the compensation plan, our Compensation Committee then utilizes the primary financial objectives from the adopted business plan, operating
cash flow, as the primary targets for determining the executive officers' short-term cash incentives and long term equity incentive compensation. The Committee also establishes additional
non-financial performance goals and objectives, the achievement of which is required for funding of a significant portion (25%) of the executive officers' incentive compensation. In 2006,
these non financial performance goals and objectives included achieving accurate financial reporting and timely SEC filings; demonstrating full compliance and superior performance in the Partnership's
environmental, health and safety practices; performing appropriate SOX/404 remediation activities and achieving successful testing of and compliance with SOX requirements; and general and
administrative expense management.



The Chief Executive Officer recommends the actual incentive award amounts for all other NEOs based on actual company performance relative to the targets as well
as on individual performance, and recommends the NEOs' base salaries levels for the coming year. The Compensation Committee considers these recommendations at the end of each fiscal year in
determining its recommendations to the Board of Directors for the final short-term cash incentive and long-term equity award amounts for each NEO and for the NEO's base salary
levels. The actual incentive amounts awarded to each NEO are ultimately subject to the discretion of the Compensation Committee and the Board of Directors. The incentive awards for the Chief Executive
Officer are separately evaluated and determined by the Compensation Committee using similar metrics, and ratified and approved by the Board of Directors.



Additional equity-based awards may be also granted to NEOs, as well as other employees, upon commencement of employment, for promotions or special performance
recognition, or for retention purposes, based on the recommendation of the Chief Executive Officer. In determining whether to recommend additional grants to an NEO, the Chief Executive Officer
typically considers the individual's performance and any planned change in functional responsibility.

149

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As noted above, our executive officers are also executive officers for the General Partner and these executive officers and our employees perform management,
accounting, personnel and related administrative services for the Partnership pursuant to a Services Agreement between us and the General Partner. Under the Services Agreement, the General Partner
reimburses us for an allocated portion of our employees' and executives' base and incentive compensation. Further, due to the relatively greater amount of cash flow and income generated by the
Partnership, the Partnership funds a proportional share of the short-term cash incentive pool available for our employees, including the executive officers. Accordingly, the General
Partner's Compensation Committee participates with us in the determination of the employees' and executives' base and incentive compensation and the General Partner and Partnership participates in an
allocated portion of the
funding of short term incentive cash compensation payments, as well as the long term equity incentive awards provided to our executives and key management employees.

Elements of Executive Compensation



Total compensation for our NEOs consists of four elements: (i) base salary; (ii) an annual short-term incentive cash award based on
achieving specific performance targets as measured by cash flow and other objectives; (iii) an annual long-term equity incentive award, which is also performance based and paid out
over a future period in the form of restricted units; and finally (iv) the fair value of each NEO's investment in the General Partner under the Participation Plan (discussed below). Base
salaries are the value upon which both the short-term and long term incentive compensation percentage targets are measured against. See table under section entitled Allocation Among Elements, below. For
evaluation and comparison of overall compensation of the executives, and to assist it in making its compensation
decisions, the Compensation Committee reviews an executive compensation summary worksheet, which sets forth for each NEO: current compensation and compensation target percentages, current equity
ownership holdings and GP interest, and current and projected value of each and all such compensation elements, including distributions and dividends therefrom, over a five year period.



Base salaries are designed to compensate executives commensurate with their respective level of experience, scope of responsibilities, and to reward sustained
individual performance and future potential. The goal has been to provide for base salaries that are sufficiently competitive with other similar-sized energy companies and/or partnerships, both
regionally and nationally, in order to attract and retain talented leaders.



Incentive compensation is intended to align compensation with business objectives and performance and enable the company to attract, retain and reward high
quality executive officers whose contributions are critical to short and long-term success of the Company. The NEOs incentive awards are based upon four key performance metrics:
1) the Company's operating cash flow; 2) MarkWest Hydrocarbon's operating cash flow; 3) achievement of agreed-upon strategic and corporate performance goals; and
4) each executive's departmental and individual goals and performance. The actual incentive amounts awarded to each NEO are ultimately subject to the discretion of the Compensation Committee
and the Board of Directors.

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Short-term incentive awards are paid out in annual cash awards. The short-term cash incentive award targets for the NEOs are established
at the beginning of the year as a percentage of their base salary, and the actual awards are determined at the following year's January Board of Directors meetings based on actual company performance
relative to established goals and objectives, as well as on evaluation of the NEO's relevant departmental and individual performance during the past year. The short-term cash incentive
pool is funded only if a minimum of 75% of the respective cash flow targets of the Partnership and of MarkWest Hydrocarbon is met. Once the threshold is met, then the size of the fund available for
all cash incentive awards increases in relation to the extent to which financial targets and non financial objectives are achieved and exceeded, in a linear fashion from threshold through to full
stretch, which is capped at 125% of the respective cash flow targets. Short-term cash incentive awards for the NEOs in 2006 were targeted at 40%-50% of base salary for
achievement of base-plan performance goals and at up to an additional 40%-50% of base salary for achievement of stretch performance.



In addition to the base salary and short-term cash incentive payments, our NEOs and other members of senior management are awarded
long-term equity compensation based upon meeting or exceeding financial and operational targets that are established by the Board of
Directors at the outset of the year. Long term incentive equity awards are granted in phantom units issued under the Partnership's Long-Term Incentive Plan, and in restricted stock issued
under the MarkWest Hydrocarbon 2006 Stock Incentive Plan. Allocation of value of long-term equity awards between Partnership phantom units and MarkWest Hydrocarbon shares of restricted
stock is based upon time devoted by the individual NEO to the respective entities' business and affairs. Both the phantom units of Partnership and the restricted shares of MarkWest Hydrocarbon vest in
equal installments over a three-year period. Recipients are eligible to collect stock dividends and/or common unit distribution payments on these awards during the vesting period. The
awards are intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the shares or units. Recipients do
not pay any consideration for the shares or units they receive. Long-term equity incentive award targets for the NEOs in 2006 were targeted at a value of at 40-75% of base
salary for achievement of the base-plan goals, and the opportunity for stretch long-term equity incentive awards are left to the discretion of the Compensation Committee and
the Board.



To enable executives to develop and maintain a significant long-term ownership position and alignment with our long term strategic goals, each of the
NEOs have been permitted to purchase from the Company membership interests in the Partnership's General Partner ("GP interest"), which purchase arrangements are in general referred to as the
Participation Plan. The purchase and sale price of a GP Interest is based upon a formula which is derived from the then current market value of the Partnership's common units, and the then quarterly
distributions previously paid by the Partnership. The GP Interests were purchased by each NEO at different times and in different percentage levels. The fair value of each NEO's GP Interest investment
under the Participation Plan is included in the Summary Compensation Table under the column "Other Compensation." Our Board of Directors have determined at this time to cease any further sales of GP
Interests.

Due
to the differences in each of the NEOs individual level of membership GP interests and the nature and value of such GP Interest as opposed to the incentive grants of phantom units,
an NEOs individual GP Interest level is taken into account in setting an executive's long-term equity incentive target percentages; i.e. generally the higher the individual general partner
membership interest, the lower the long-term equity incentive target percentage.

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Under our 2006 compensation structure, the mix and allocation of base salary, short-term incentive, and long-term incentive for our NEOs
is shown in the following table. Base salary is the value upon which the incentive award amounts are based. The long-term equity award target percentages of base salary levels for
performance achievement of base-plan objectives are generally higher than the target percentage levels for short-term cash incentive awards, but as noted above, the
long-term equity incentive target percentage levels are differentiated amongst the NEOs to take into account the individual NEO's GP Interest values in an effort to partially ameliorate
internal inequities for the GP interest values. Opportunities for stretch awards for short-term cash incentive awards for the NEOs are generally targeted up to double of the
base-plan target percentages (e.g. an additional incremental target percentage of 40% to 50% of base salary), while the opportunity for stretch awards for long-term equity
awards are left to the discretion of the compensation committee and the Board.

|                                  |  | Base Salary |  | Short-Term
Incentive Target |  | Equity Target
|--------------------------------- |  | ----------- |  | --------------------------- |  | -------------
|Chief Executive Officer           |  | Value       |  | Value X 50%                 |  | Value X TBD% 
|Chief Financial Officer           |  | Value       |  | Value X 40%                 |  | Value X 70%  
|Chief Financial Officer (retired) |  | Value       |  | Value X 40%                 |  | Value X 40%  
|Chief Commercial Officer          |  | Value       |  | Value X 40%                 |  | Value X 40%  
|Chief Operations Officer          |  | Value       |  | Value X 40%                 |  | Value X 40%  
|General Counsel                   |  | Value       |  | Value X 40%                 |  | Value X 75%  

Compensation Decisions for 2006



Short-term cash incentive awards for the NEOs for 2006 were targeted at 40%-50% of base salary for achievement of base-plan
performance goals and at up to an additional 40%-50% of base salary for achievement of stretch performance. In 2006, we exceeded all of our base-plan goals and achieved stretch
performance levels in financial and operational targets. The Compensation Committees and the Boards of Directors of the General Partner and of MarkWest Hydrocarbon approved the NEOs
short-term cash incentive awards for 2006 at 40% of base salary. For achieving stretch performance in 2006, incremental stretch short term cash incentive awards for the NEOs were granted
in the range of approximately 30% to 45% of base salary. The Compensation Committees separately derived the CEO's base, short-term, and long-term incentive. The CEO's
short-term cash incentive award for 2006, including the incremental stretch component, was granted at 91% of base salary.



The Compensation Committee set the 2006 long-term incentive award targets for NEOs having a value of at 40-75% of base salary for
achievement of the base-plan goals, and the opportunity for stretch long-term equity incentive awards are left to the discretion of the Compensation Committee and the Board.
For 2006, we exceeded all of our base-plan goals and achieved stretch performance levels in financial and operational targets. The Compensation Committees and the Boards of Directors of
MarkWest Hydrocarbon and the General Partner approved the NEOs long-term equity incentive awards in the range from 40% to 75% of base salary. For achieving stretch performance in 2006,
incremental stretch long-term equity incentive awards were granted in the range of approximately 10% to 20% of their base salary. The Compensation Committees separately derived the CEO's
long-term incentive, and these are granted at the Board's discretion. The CEO's long-term incentive award for 2006, including the incremental stretch component, was granted at
100% of base salary.

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Other Compensation Components



Directors, executive officers and certain designated key employees are covered under the MarkWest Hydrocarbon, Inc.1997 Severance Plan. The 1997 Severance
Plan provides for payment of benefits in the event that (i) the covered person terminates his or her employment for "good reason" (as defined), (ii) the covered person's employment is
terminated "without cause" (as defined), (iii) the covered person's employment is terminated by reason of death or disability or (iv) the covered person voluntarily resigns. In the case
of (i), (ii) and (iii) above, the covered person shall be entitled to receive base salary and continued medical benefits for a period ranging from six months to twenty-four
months, depending upon the covered person's status at the time of the termination. In the case of (iv) above, the covered person shall be entitled to receive base salary for a period ranging
from one month to six months and continued medical benefits for a period ranging from one month to six months. In either case, the aggregate amount of benefits paid to an employee shall in no event
exceed twice the employee's annual compensation during the year immediately preceding the termination. The
eligibility for qualifying for these benefits is subject to the covered person entering into acceptable non-compete and release agreements with the Company.

A
few of our General Partner's named executive officers are already party to a Non-Competition, Non-Solicitation and Confidentiality Agreement. As a result of
signing the Non-Competition, Non-Solicitation and Confidentiality Agreement, they are eligible to receive severance payments under the above described MarkWest Hydrocarbon 1997
Severance Plan.



Except for the Chief Executive Officer, none of the NEOs have an employment agreement.



Mr. Semple entered into an executive employment agreement with MarkWest Hydrocarbon on November 1, 2003, pursuant to which Mr. Semple serves
as MarkWest Hydrocarbon's President and Chief Executive Officer and pursuant to which the Board of Directors of MarkWest Hydrocarbon appointed Mr. Semple to serve as the President and Chief
Executive Officer of our general partner.

Under
the employment agreement, Mr. Semple receives an annual base salary and is entitled to receive benefits for which employees and/or executive officers are generally eligible.
In addition, Mr. Semple was awarded phantom units in the general partner under the general partner's long-term incentive plan and stock options under the MarkWest Hydrocarbon
incentive stock plan. Mr. Semple also agreed to purchase from MarkWest Hydrocarbon an interest in each of the general partner and the Partnership, subject to certain repurchase rights by
MarkWest Hydrocarbon following the termination of his employment.

Under
his employment agreement, in the event Mr. Semple's employment is terminated without cause, or if he resigns for good reason, he is entitled to severance payments equal to
his base salary for a period of thirty-six months. In addition, Mr. Semple is entitled to COBRA benefits for a period of twenty-four months. In the event
Mr. Semple voluntarily resigns, he is entitled to receive severance payments equal to his base salary and COBRA benefits for a period of six months. In the event Mr. Semple is terminated
for cause, he shall not be entitled to receive any severance or COBRA benefits.



In January 2007, the Partnership, our General Partner and MarkWest Hydrocarbon entered into Indemnification Agreements with certain directors and officers
("Indemnitees"). By the terms of the

153

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



MarkWest Hydrocarbon maintains a 401(k) plan to which MarkWest matches employee contributions up to the first 6% of an employee's annual base salary. We do not
provide any supplemental retirement benefits to our senior executives.



Our executives are not awarded any type of protection upon a change in control other than what is offered by the 1997 Severance Plan and the vesting of phantom
units upon a change in control.



MarkWest does not provide for any perquisites or any other benefits for its senior executives that are not generally available to all employees.



We believe that internal equity is an important factor to be considered in establishing compensations for the executive officers. We have not adopted a policy;
however, we do review compensation levels to ensure that appropriate equity exists.



We generally will seek to maximize the deductibility for tax purposes all elements of compensation. Section 162(m) of the Internal Revenue Code places a
$1,000,000 annual limit on the compensation deductible by the Company paid to certain of its executives. The limit, however, does not apply to "qualified performance-based compensation." We review
compensation plans in light of applicable tax provisions and may revise plans to maximize deductibility. However, we may approve compensation that does not qualify for deductibility when we deem it in
the best interests of MarkWest.



Although we have granted stock options in the past, we ceased granting stock options after 2004 as incentive awards as a result of accounting, tracking and
expensing issues associated with stock options under Statement of Financial Accounting Standards No. 123R. All stock options which were granted in the past were granted at an option price at
least equal to the fair market value of our common stock on the date of grant. To further reduce ongoing accounting, tracking and expensing burdens, we vested the remaining 14,950 unvested options in
December 2006, which affected a total of eight individuals, including two NEOs and three current directors. As a result of this action described above, these options, with varying remaining
vesting schedules, have become immediately exercisable.

154

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Although
permitted under MarkWest Energy, L.P.'s Long Term Incentive Plan, no options have been granted by the Partnership.

Compensation Committee Report

We have reviewed and discussed the foregoing Compensation Discussion and Analysis with management. Based on our review and discussion with management, we have
recommended to the Board of Directors that the Compensation Discussion and Analysis be included in the Company's Proxy Statement and its Annual Report on Form 10-K/A for the year
ended December 31, 2006.

|Submitted by: |  | Donald D. Wolf
William F. Wallace
William A. Kellstrom
Members of the Compensation Committee
|------------- |  | --------------------------------------------------------------------------------------------

Summary Compensation Table

The following table sets forth the cash and non cash compensation earned for the year ended December 31, 2006 by each person who served as the Chief
Executive Officer, Chief Financial Officer during 2006 and the three other highest paid officers (the "Named Executive Officers").

|Name and Principal Position                                        |  | Year |  | Salary
($) |  | Bonus
($) |  | Stock
Awards
($)(1) |  | Option
Awards
($)(2) |   | Non-Equity
Incentive Plan
Compensation
($) |  | Change in
Pension Value
and Non-
qualified
Deferred
Compensation
Earnings
($) |  | All Other
Compensation
($)(3)(4)(5)
(6)(7)(8)(9)(10) |  | Total
($)
|------------------------------------------------------------------ |  | ---- |  | ---------- |  | --------- |  | ------------------- |  | -------------------- | - | ------------------------------------------ |  | ----------------------------------------------------------------------------- |  | ---------------------------------------------------- |  | ---------
|Frank M. Semple
President and Chief Executive Officer              |  | 2006 |  | 351,800    |  |          |  | 255,219             |  | 20,536               |   | 319,141                                    |  |                                                                              |  | 6,792,797                                            |  | 7,739,493
|James G. Ivey
Chief Financial Officer (Retired)                    |  | 2006 |  | 166,351    |  |          |  | 82,780              |  | (34,874              | ) | 60,363                                     |  |                                                                              |  | 1,093,380                                            |  | 1,368,000
|Nancy K. Buese
Senior Vice President, Chief Financial Officer      |  | 2006 |  | 226,800    |  |          |  | 352,072             |  |                     |   | 190,000                                    |  |                                                                              |  | 1,057,258                                            |  | 1,826,130
|Randy S. Nickerson
Senior Vice President, Chief Commercial Officer |  | 2006 |  | 211,800    |  |          |  | 114,772             |  |                     |   | 162,933                                    |  |                                                                              |  | 4,957,476                                            |  | 5,446,981
|John C. Mollenkopf
Senior Vice President, Chief Operations Officer |  | 2006 |  | 201,800    |  |          |  | 101,444             |  |                     |   | 155,240                                    |  |                                                                              |  | 4,891,528                                            |  | 5,350,012
|C. Corwin Bromley
Senior Vice President, General Counsel           |  | 2006 |  | 217,000    |  |          |  | 376,684             |  | 7,425                |   | 167,000                                    |  |                                                                              |  | 767,546                                              |  | 1,535,655

---

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Grant of Plan-Based Awards Table

The following table sets forth the stock awards granted for the year ended December 31, 2006 and estimated future payments under our non-equity
incentive compensation plan for the Named Executive Officers. Previously awarded Partnership units have been adjusted to reflect the February 2007 two-for-one unit split
(see Note 2 to the consolidated financial statements).

|                                                                   |  |                                 |  |                                   |  |                |  |                |  |                 |  |            |  |            |  |            |  | All Other
Stock
Awards:
Number of
Shares of
Stock or
Units
(#)(2)(3) |  | All Other
Option
Awards:
Number of
Securities
Underlying
Options
(#) |  |          
|------------------------------------------------------------------ |  | ------------------------------- |  | --------------------------------- |  | -------------- |  | -------------- |  | --------------- |  | ---------- |  | ---------- |  | ---------- |  | -------------------------------------------------------------------- |  | -------------------------------------------------------------------- |  | ---------
|
|
|Frank M. Semple
President and Chief Executive Officer              |  | 1/31/06
1/31/06                 |  | 1/26/06
1/25/06                   |  | 87,950

     |  | 175,900

    |  | NA

          |  | NA

     |  | NA

     |  | NA

     |  | 
3,337
3,088                                                        |  | 
MWP
MWE                                                            |  | 

    
|James G. Ivey
Chief Financial Officer (Retired)                    |  | 1/31/06
1/31/06                 |  | 1/26/06
1/25/06                   |  | 
            |  | 
            |  | 
             |  | 
        |  | 
        |  | 
        |  | 2,026
1,874                                                          |  | MWP
MWE                                                              |  | 
      
|Nancy K. Buese
Senior Vice President, Chief Financial Officer      |  | 1/31/06
1/31/06
11/1/06
11/1/06 |  | 1/26/06
1/25/06
10/26/06
10/25/06 |  | 56,700



 |  | 90,720



 |  | 181,440



 |  | NA



 |  | NA



 |  | NA



 |  | 
783
10,726
2,500
5,000                                             |  | 
MWP
MWE
MWP
MWE                                                    |  | 




|Randy S. Nickerson
Senior Vice President, Chief Commercial Officer |  | 1/31/06
1/31/06                 |  | 1/26/06
1/25/06                   |  | 52,950

     |  | 84,720

     |  | 169,440

     |  | NA

     |  | NA

     |  | NA

     |  | 
1,399
1,942                                                        |  | 
MWP
MWE                                                            |  | 

    
|John C. Mollenkopf
Senior Vice President, Chief Operations Officer |  | 1/31/06
1/31/06                 |  | 1/26/06
1/25/06                   |  | 50,450

     |  | 80,720

     |  | 161,440

     |  | NA

     |  | NA

     |  | NA

     |  | 
1,706
1,578                                                        |  | 
MWP
MWE                                                            |  | 

    
|C. Corwin Bromley
Senior Vice President, General Counsel           |  | 1/31/06
1/31/06                 |  | 1/26/06
1/25/06                   |  | 54,250

     |  | 86,800

     |  | 173,600

     |  | NA

     |  | NA

     |  | NA

     |  | 
1,642
11,520                                                       |  | 
MWP
MWE                                                            |  | 
      

---

156

---





Outstanding Equity Awards at Year End Table

The following table summarizes the options and stock awards outstanding as of December 31, 2006 for the Named Executive Officers. The market value was
determined using the closing prices on MWP and MWE on December 29, 2006. Previously awarded Partnership units have been adjusted to reflect the February 2007
two-for-one unit split (see Note 2 to the consolidated financial statements).

|                                                                   |  | Option Awards               |  |           |  |     |  |       |                          | 
|------------------------------------------------------------------ |  | --------------------------- |  | --------- |  | --- |  | ----- | ------------------------ | 
|
|
|
|Frank M. Semple
President and Chief Executive Officer              |  | 12,100                      |  |          |  | N/A |  | $     | 8.41                     | 
|James G. Ivey Chief Financial Officer (Retired)                    |  |                            |  |          |  | N/A |  |       |                         | 
|Nancy K. Buese
Senior Vice President, Chief Financial Officer      |  |                            |  |          |  | N/A |  |       |                         | 
|Randy S. Nickerson
Senior Vice President, Chief Commercial Officer |  | 998
1,742
1,506             |  | 

     |  | N/A |  | $$$   | 6.58
8.45
5.75           | 
|John C. Mollenkopf
Senior Vice President, Chief Operations Officer |  | 867
1,044
1,044
2,408
2,469 |  | 



 |  | N/A |  | $$$$$ | 7.89
4.04
6.58
8.45
5.75 | 
|C. Corwin Bromley
Senior Vice President, General Counsel           |  | 2,420                       |  |          |  | N/A |  | $     | 12.05                    | 

---

157

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Option Exercise and Stock Vesting Table

The following table summarizes the option and stock award activity during the year ended December 31, 2006 for the Named Executive Officers. Partnership
units that vested during the year have been adjusted to reflect the February 2007 two-for-one unit split (see Note 2 to the consolidated financial statements).

|                                                                   |  | Option Awards |  | Stock Awards
|------------------------------------------------------------------ |  | ------------- |  | ------------
|
|Frank M. Semple
President and Chief Executive Officer              |  | 12,100
      |  | 170,308
   
|James G. Ivey
Chief Financial Officer (Retired)                    |  | 6,050
       |  | 233,925
   
|Nancy K. Buese
Senior Vice President, Chief Financial Officer      |  | 
           |  | 
         
|Randy S. Nickerson
Senior Vice President, Chief Commercial Officer |  | 
           |  | 
         
|John C. Mollenkopf
Senior Vice President, Chief Operations Officer |  | 
           |  | 
         
|C. Corwin Bromley
Senior Vice President, General Counsel           |  | 
           |  | 
         

158

---



Pension Benefits Table

The Partnership does not offer any pension benefits.

|Name and Principal Position                                        |  | Plan Name |  | Number of Years
Credited Service
(#) |  | Present Value
of Accumulated
Benefit
($) |  | Payments During
Last Fiscal Year
($)
|------------------------------------------------------------------ |  | --------- |  | ------------------------------------ |  | ---------------------------------------- |  | ------------------------------------
|Frank M. Semple
President and Chief Executive Officer              |  | N/A       |  | N/A                                  |  | N/A                                      |  | N/A                                 
|James G. Ivey
Chief Financial Officer (Retired)                    |  | N/A       |  | N/A                                  |  | N/A                                      |  | N/A                                 
|Nancy K. Buese
Senior Vice President, Chief Financial Officer      |  | N/A       |  | N/A                                  |  | N/A                                      |  | N/A                                 
|Randy S. Nickerson
Senior Vice President, Chief Commercial Officer |  | N/A       |  | N/A                                  |  | N/A                                      |  | N/A                                 
|John C. Mollenkopf
Senior Vice President, Chief Operations Officer |  | N/A       |  | N/A                                  |  | N/A                                      |  | N/A                                 
|C. Corwin Bromley
Senior Vice President, General Counsel           |  | N/A       |  | N/A                                  |  | N/A                                      |  | N/A                                 

Non-Qualified Deferred Compensation

The Partnership has no non-qualified deferred compensation plans.

|Name and Principal Position                                        |  | Executive
Contributions
in Last FY
($) |  | Registrant
Contributions
in Last FY
($) |  | Aggregate
Earnings
in Last FY
($) |  | Aggregate
Withdrawls /
Distributions
($) |  | Aggregate
Balance at
Last FYE
($)
|------------------------------------------------------------------ |  | -------------------------------------- |  | --------------------------------------- |  | --------------------------------- |  | ---------------------------------------- |  | ---------------------------------
|Frank M. Semple
President and Chief Executive Officer              |  | N/A                                    |  | N/A                                     |  | N/A                               |  | N/A                                      |  | N/A                              
|James G. Ivey
Chief Financial Officer (Retired)                    |  | N/A                                    |  | N/A                                     |  | N/A                               |  | N/A                                      |  | N/A                              
|Nancy K. Buese
Senior Vice President, Chief Financial Officer      |  | N/A                                    |  | N/A                                     |  | N/A                               |  | N/A                                      |  | N/A                              
|Randy S. Nickerson
Senior Vice President, Chief Commercial Officer |  | N/A                                    |  | N/A                                     |  | N/A                               |  | N/A                                      |  | N/A                              
|John C. Mollenkopf
Senior Vice President, Chief Operations Officer |  | N/A                                    |  | N/A                                     |  | N/A                               |  | N/A                                      |  | N/A                              
|C. Corwin Bromley
Senior Vice President, General Counsel           |  | N/A                                    |  | N/A                                     |  | N/A                               |  | N/A                                      |  | N/A                              

159

---



Director Compensation Table

The following table sets forth the cash and non cash compensation earned for the year ended December 31, 2006 by each person who served as a
Non-employee Director of MarkWest Hydrocarbon, Inc.

|Name                              |  | Cash
($) |  | Fees Earned
or Paid in
Stock Awards
($)(1)(2) |  | Option Awards
($)(3) |  | All Other
Compensation
($)(4)(5)(6)(7) |  | Total
($)
|--------------------------------- |  | -------- |  | --------------------------------------------- |  | -------------------- |  | -------------------------------------- |  | ---------
|John M. Fox
Chairman of the Board |  | 37,000   |  | 13,427                                        |  |                     |  | 4,482,630                              |  | 4,533,057
|Michael L. Beatty                 |  | 39,000   |  | 13,427                                        |  |                     |  | 869                                    |  | 53,296   
|Donald C. Heppermann              |  | 34,000   |  | 13,427                                        |  | 6,304                |  | 2,809,408                              |  | 2,863,139
|William A. Kellstrom              |  | 54,000   |  | 13,427                                        |  |                     |  | 7,625                                  |  | 75,052   
|Anne E. Mounsey                   |  | 37,000   |  | 13,427                                        |  | 3,129                |  | 5,154                                  |  | 58,710   
|Karen L. Rogers                   |  | 42,000   |  | 13,427                                        |  |                     |  | 5,945                                  |  | 61,372   
|William F. Wallace                |  | 46,000   |  | 13,427                                        |  | 3,129                |  | 1,304                                  |  | 63,860   
|Donald D. Wolf                    |  | 48,000   |  | 13,427                                        |  |                     |  | 8,908                                  |  | 70,335   

---

160

---



MarkWest Energy G.P., L.L.C.

The following table sets forth the cash and non cash compensation earned for the year ended December 31, 2006 by each person who served as a
Non-employee Director of MarkWest Energy G.P., L.L.C.

|Name                              |  | Fees Earned
or Paid in
Cash
($) |  | Unit Awards
($)(1)(2) |  | All Other
Compensation
($)(3)(4)(5) |  | Total
($)
|--------------------------------- |  | ------------------------------- |  | --------------------- |  | ----------------------------------- |  | ---------
|John M. Fox
Chairman of the Board |  | 34,000                          |  | 26,246                |  | 4,508,233                           |  | 4,568,479
|Keith E. Bailey                   |  | 52,000                          |  | 18,193                |  | 29,825                              |  | 100,018  
|Charles K. Dempster               |  | 55,000                          |  | 28,036                |  | 74,563                              |  | 157,599  
|Donald C. Heppermann              |  | 34,000                          |  | 26,246                |  | 2,835,177                           |  | 2,895,423
|William A. Kellstrom              |  | 34,000                          |  | 28,036                |  | 74,563                              |  | 136,599  
|William P. Nicoletti              |  | 50,000                          |  | 28,036                |  | 74,563                              |  | 152,599  

---

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth certain information as of February 15, 2007, regarding the beneficial ownership of our common stock held by beneficial
owners of 5% or more of common stock, by each

161

---



director,
by each Named Executive Officer and by all of the directors and officers of the Company as a group.

Name and Address of Beneficial Owner(1)

Common
Shares
Beneficially
Owned(2)

Percent of
Class(3)John M. Fox(4)

5,377,446

44.6
%Kayne Anderson Capital Advisors, L.P.
1800 Avenue of the Stars, Second Floor
Los Angeles, CA 90067(5)

908,099

7.5
%Richard A. Kayne
1800 Avenue of the Stars, Second Floor
Los Angeles, CA 90067(5)

908,099

7.5
%Michael L. Beatty

2,100

*Donald C. Heppermann

29,599

*William A. Kellstrom

20,921

*Anne E. Mounsey

13,816

*Karen L. Rogers

15,597

*William F. Wallace

8,710

*Donald D. Wolf

37,548

*Frank M. Semple

40,556

*C. Corwin Bromley

9,246

*Nancy K. Buese

8,175

*John C. Mollenkopf

12,232

*Randy S. Nickerson

15,495

*All directors and named executive officers as a group (13 persons)

5,591,441

46.4
%




162

---





163

---





MarkWest GP, L.L.C.

The following table sets forth the beneficial ownership of the Partnership's general partner as of February 15, 2007, held by the directors, each named
executive officer and by all directors and officers as a group.

Name of Beneficial Owner

Percentage of
Limited Liability
Company Interests
OwnedJohn M. Fox(1)

91.3
%Donald C. Heppermann

1.0
%Keith E. Bailey

Charles K. Dempster

William A. Kellstrom

William P. Nicoletti

Frank M. Semple

2.0
%John C. Mollenkopf

1.6
%Randy S. Nickerson

1.6
%Nancy K. Buese

0.2
%C. Corwin Bromley

0.1
%All Directors and Named Executive Officers as a Group (11 persons)

97.8
%




MarkWest Energy Partners

The following table sets forth the beneficial ownership of units as of March 1, 2007, held by beneficial owners of 5% or more of the units; by directors of
our general partner; by each named executive officer listed in the summary compensation table included in this Form 10-K/A; and by all

164

---



directors and officers of our general partner as a group. The units reported have been adjusted to reflect the February 2007 two-for-one unit split (see Note 2 to
the consolidated financial statements).

Name and Address of Beneficial Owner(1)

Common Units
Beneficially
Owned(2)

Percent of
ClassMarkWest Energy GP, L.L.C.



MarkWest Hydrocarbon, Inc.(3)

4,938,992

15.2
%John M. Fox(4)

5,029,454

15.5
%Tortoise Capital Advisors, L.L.C.
10801 Mastin Boulevard, Suite 222
Overland Park, KS 66210(5)

3,128,470

9.7
%Tortoise Energy Infrastructure Corporation
10801 Mastin Boulevard, Suite 222
Overland Park, KS 66210(5)

2,080,354

6.4
%Kayne Anderson Capital Advisors, L.P.
1800 Avenue of the Stars, Second Floor
Los Angeles, CA 90067(6)

2,831,560

8.7
%Richard A. Kayne
1800 Avenue of the Stars, Second Floor
Los Angeles, CA 90067(6)

2,831,560

8.7
%Keith E. Bailey

21,734

*Charles K. Dempster

3,000

*Donald C. Heppermann

24,000

*William A. Kellstrom

9,000

*William P. Nicoletti

8,000

*Frank M. Semple

33,742

*C. Corwin Bromley

5,304

*Nancy K. Buese

4,196

*John C. Mollenkopf

17,718

*Randy S. Nickerson

14,978

*All Directors and Executive Officers as a Group (11 persons)

5,171,126

16.0
%




165

---





Item 13. Certain Relationships, Related Transactions and Director Independence

Transactions with Management and Others

In September 2006 the Company entered into a Consulting Services Agreement and Separation Agreement with James G. Ivey. Pursuant to the Consulting Services
Agreement, Mr. Ivey provided consulting services to the Company from October 2 through October 31, 2006, and received compensation in the amount of $19,850. Pursuant to the
Separation Agreement, the Company agreed to pay Mr. Ivey his base salary for a period of eighteen months, through March 2008, or approximately $0.3 million. Also pursuant to the
Separation Agreement, Mr. Ivey executed a release and waiver of

166

---



claims
against the Company and provided non-compete and non-solicitation covenants for the eighteen-month period of separation payments referenced above.

Participation Plan

From time to time, MarkWest Hydrocarbon sells to certain of its executive officers and directors (i) a certain amount of the subordinated units the Company
obtained during the formation of MarkWest Energy in May 2002 and (ii) a portion of its ownership interest in the general partner, which was also obtained by the Company during the
formation of the Partnership. These transactions are accounted for as compensatory arrangements, consistent with the guidance in APB No. 25,Accounting for Stock Issued
to Employeesand EITF No 95-16,Accounting for Stock Compensation Arrangements with Employer Loan Features under APB Opinion
No. 25,which requires the Company to record compensation expense based on the market value of the subordinated Partnership units and the formula value of the general
partner interests held by the employees and directors, at the end of each reporting period. The sales are governed by a purchase and sales agreement that outlines the terms and conditions. Immediately
after MarkWest Energy's initial public offering on May 24, 2002, MarkWest Hydrocarbon sold an 8.6% interest in the general partner of the Partnership and 49,728 of its Partnership subordinated
units, to certain officers of MarkWest Hydrocarbon. The officers and executives paid approximately 30% of the purchase price in cash and financed the remainder with loans from MarkWest Hydrocarbon.
The loans were evidenced by non-recourse promissory notes requiring the principal balance to be repaid no later than June 30, 2009 and bearing interest at the rate of 7% per annum
on the unpaid balance. As of December 31, 2006, there was no loans outstanding related to the initial purchase of the general partner interests or subordinated units by the executives and
officers. In accordance with the Sarbanes-Oxley Act of 2002, the Company no longer grants loans to employees.

Since
May 2002, MarkWest Hydrocarbon has sold additional interests in the general partner to employees and directors of 5.0% and has repurchased ownership interests from employees
and directors of 3.3%. During the same timeframe, the Partnership has sold an additional 28,000 subordinated units and repurchased 16,720. As of December 31, 2006, 10.3% of the general partner
is currently held by employees and directors. The Board of Directors of the Partnership's general partner has determined at this time to cease any further sales of GP Interests.

Item 14. Principal Accountant Fees and Services

For the years ended December 31, 2006 and 2005, consolidated accounting fees and services for the Company were as follows (in thousands):

Year ended December 31,2006

2005(4)Audit fees

$
3,135

$
3,282Audit-related fees(1)


414


125Tax fees(2)


15


All other fees(3)


2


5Total accounting fees and services

$
3,566

$
3,412




167

---





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

168

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PART IV

Item 15. Exhibits and Financial Statement Schedules



|Exhibit
Number |  | Description                                                                                                                                                                                                                                                                                  
|-------------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|2.1(6)         |  | Purchase Agreement dated as of March 24, 2003, among PNG Corporation, Energy Spectrum Partners LP, MarkWest Energy GP, L.L.C., MW Texas Limited, L.L.C. and MarkWest Energy Partners, L.P.                                                                                                   
|2.2(6)         |  | Plan of Merger entered into as of March 28, 2003, by and among MarkWest Blackhawk L.P., MarkWest Pinnacle L.P., MarkWest PNG Utility L.P., MarkWest Texas PNG Utility L.P., Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG Transmission
Company and Bright Star Gathering, Inc.
|2.3(11)        |  | Purchase and Sale Agreement, dated as of November 7, 2003, by and between Shell Pipeline Company, LP and Equilon Enterprises L.L.C., dba Shell Oil Products US, and MarkWest Michigan Pipeline Company, L.L.C.                                                                               
|2.4(10)        |  | Asset Purchase and Sale Agreement dated as of November 18, 2003, by and between American Central Western Oklahoma Gas Company, L.L.C., MarkWest Western Oklahoma Gas Company, L.L.C. and American Central Gas Technologies, Inc.                                                             
|2.5(13)        |  | Asset Purchase and Sale Agreement and addendum, thereto, dated as of July 1, 2004 by and between American Central Eastern Texas Gas Company Limited Partnership, ACGC Gathering Company, L.L.C. and MarkWest Energy East Texas Gas Company's
L.P.                                            
|2.6(20)        |  | Purchase and Sale Agreement dated as of September 16, 2005 by and between El Paso Corporation, as seller, and MarkWest Energy Partners, L.P. as buyer.                                                                                                                                       
|2.7(20)        |  | Purchase and Sale Agreement dated as of September 16, 2005 by and between Kerr-McGee Corp., KM Investment Corp., and Javelina Holdings Corp., as joint sellers, and MarkWest Energy Partners, L.P. as buyer.                                                                                 
|2.8(20)        |  | Purchase and Sale Agreement dated as of September 16, 2005 by and between Valero Energy Corp., and Valero Javelina, L.P., as sellers, and MarkWest Energy Partners, L.P. as buyer.                                                                                                           
|3.1(1)         |  | Certificate of Incorporation of MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                                                   
|3.2(1)         |  | Bylaws of MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                                                                         
|               |  |                                                                                                                                                                                                                                                                                              

169

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|4.1(5)   |  | Subordinated Unit Purchase Agreement among MarkWest Hydrocarbon, Inc. and Tortoise MWEP, L.P., dated as of November 20, 2002.                                                                                                                                                                                                                                                                                                                                                                                                                    
|-------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.2(7)   |  | Purchase Agreement dated as of June 13, 2003, by and among MarkWest Energy Partners, L.P. and Tortoise Capital Advisors, LLC as attorney-in-fact for the Purchasers.                                                                                                                                                                                                                                                                                                                                                                             
|4.3(7)   |  | Registration Rights Agreement dated as of June 13, 2003, by and among MarkWest Energy Partners, L.P. and Tortoise Capital Advisors, LLC as attorney-in-fact for the Purchasers.                                                                                                                                                                                                                                                                                                                                                                  
|4.4(13)  |  | Unit Purchase Agreement dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and MarkWest Energy GP, L.L.C. and each of Kayne Anderson Energy Fund II, L.P., and MarkWest Energy GP, L.L.C. and each of Kayne Anderson Energy Fund II,
L.P., Kayne Anderson Capital Income Partners, L.P., Kayne Anderson MLP Fund, L.P., Kayne Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR RV Performance Master Trust, Tortoise Energy Infrastructure Corporation and
Energy Income and Growth Fund as Purchasers.
|4.5(13)  |  | Registration Rights Agreement dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and each of Kayne Anderson Energy Fund II, L.P., Kayne Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR RV
Performance Master Trust, Tortoise Energy Infrastructure Corporation and Energy Income and Growth Fund.                                                                                                                                                                                                    
|4.6(14)  |  | Purchase Agreement dated October 19, 2004, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein.                                                                                                                                                                                                                                                                                                                                                     
|4.7(14)  |  | Registration Rights Agreement dated October 25, 2004, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein.                                                                                                                                                                                                                                                                                                                                          
|4.8(14)  |  | Indenture dated as of October 25, 2004, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee.                                                                                                                                                                                                                                                                                                                                          
|4.9(14)  |  | Form of 6.875% Series A Senior Notes due 2014 with attached notation of Guarantees (incorporated by Reference to Exhibits A and D of Exhibit 4.8 hereto).                                                                                                                                                                                                                                                                                                                                                                                        
|4.10(27) |  | Registration Rights Agreement dated as of July 6, 2006 among MarkWest Energy Partners, L.P., with MarkWest Energy Finance Corporation as the Issuers, the Guarantors named therein, and each of RBC Capital Markets Corporation, J.P. Morgan
Securities Inc., Wachovia Capital Markets, LLC, A.G. Edwards & Sons, Inc., Credit Suisse Securities (USA) LLC, Fortis Securities LLC, Mizuho International plc, Piper Jaffray & Co. and SG Americas Securities, LLC
collectively as Initial Purchasers.                                             
|4.11(27) |  | Indenture dated as of July 6, 2006, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, as Issuers, the Guarantors named therein, and Wells Fargo Bank, National Association, as Trustee.                                                                                                                                                                                                                                                                                                                                 
|4.12(27) |  | Form of 8.5% Series A and Series B Senior Notes due 2016 with attached notation of Guarantees (incorporated by Reference to Exhibits A and D of Exhibit 4.11 hereto).                                                                                                                                                                                                                                                                                                                                                                            
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  

170

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|4.13(29)  |  | Registration Rights Agreement dated as of October 20, 2006 among MarkWest Energy Partners, L.P., with MarkWest Energy Finance Corporation as the Issuers, the Guarantors named therein, and RBC Capital Markets Corporation as the Initial
Purchaser.                                                                                             
|--------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.1(1)^  |  | 1996 Incentive Compensation Plan.                                                                                                                                                                                                                                                                                                                 
|10.2(1)^  |  | 1996 Stock Incentive Plan.                                                                                                                                                                                                                                                                                                                        
|10.3(1)^  |  | 1996 Non-employee Director Stock Option Plan.                                                                                                                                                                                                                                                                                                     
|10.4(1)   |  | Form of Non-Compete Agreement between John M. Fox and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                                                                                  
|10.5(2)^  |  | MarkWest Hydrocarbon, Inc., 1997 Severance Plan.                                                                                                                                                                                                                                                                                                  
|10.6+     |  | Amendment to Gas Processing Agreement (Maytown) dated as of March 26, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                   
|10.7(3)   |  | Contribution, Conveyance and Assumption Agreement dated as of May 24, 2002, among MarkWest Energy Partners, L.P.; MarkWest Energy Operating Company, L.L.C; MarkWest Energy GP, L.L.C.; MarkWest Michigan, Inc.; MarkWest Energy Appalachia,
L.L.C.; West Shore Processing Company, L.L.C.; Basin Pipeline, L.L.C.; and MarkWest Hydrocarbon, Inc.
|10.8(4)   |  | Fifth Amended and Restated Credit Agreement among MarkWest Hydrocarbon, Inc. and Certain Financial Institutions as the Lenders, Bank of America, N.A., as the Administrative Agent of the Lenders, and Bank of America Securities, L.L.C., as Lead
Arranger and Sole Book Manager, dated as of May 24, 2002.                                      
|10.9(3)   |  | Omnibus Agreement dated as of May 24, 2002, among MarkWest Hydrocarbon, Inc.; MarkWest Energy GP, L.L.C.; MarkWest Energy Partners, L.P.; and MarkWest Energy Operating Company, L.L.C.                                                                                                                                                           
|10.10(3)+ |  | Fractionation, Storage and Loading Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                  
|10.11(3)+ |  | Gas Processing Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                                      
|10.12(3)+ |  | Pipeline Liquids Transportation Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                     
|10.13(3)  |  | Natural Gas Liquids Purchase Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                        
|10.14++   |  | Gas Processing Agreement (Maytown) dated as of May 28, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                                  
|10.15(8)  |  | Purchase and Sale Agreement, dated as of June 5, 2003, by and among MarkWest Hydrocarbon, Inc., MarkWest Resources, Inc., and XTO Energy Inc.                                                                                                                                                                                                     
|10.16(9)  |  | Purchase and Sale Agreement dated as of July 31, 2003, among Raptor Natural Plains Marketing LLC, Raptor Gas Transmission LLC, Power-Tex Joint Venture and MarkWest Pinnacle L.P.                                                                                                                                                                 
|          |  |                                                                                                                                                                                                                                                                                                                                                   

171

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|10.17(10)  |  | Amended and Restated Credit Agreement dated as of December 1, 2003, among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Bank One, NA, as
Syndication Agent, and Fortis Capital Corp., as Documentation Agent, to the $140,000,000 Senior Credit Facility.                                                                                                                                                                                                                                                                    
|---------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.18(12)^ |  | Executive Employment Agreement effective November 1, 2003 between MarkWest Hydrocarbon, Inc. and Frank Semple.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|10.19(13)  |  | Second Amended and Restated Credit Agreement dated as of July 30, 2004 among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis Capital
Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe Generale, as Documentation Agent to the $315,000,000 Senior Credit Facility.                                                                                                                                                                                                                         
|10.20(13)  |  | First Amendment to the Second Amended and Restated Credit Agreement dated as of August 20, 2004, among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative
Agent, Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe Generale, as Documentation Agent.                                                                                                                                                                                                                                          
|10.21(15)  |  | Third Amended and Restated Credit Agreement dated as of October 25, 2004 among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Bank One, N.A.,
as Syndication Agent, Fortis Capital Corp., as Documentation Agent, U.S. Bank National Association, as Documentation Agent, Societe Generale, as Documentation Agent, and Wachovia Bank, National Association, as Documentation Agent, RBC Capital Markets
and J.P. Morgan Securities Inc., as Lead Arrangers and Joint Bookrunners, to the $200,000,000 Senior Credit Facility.
|10.22(3)^  |  | MarkWest Energy Partners, L.P. Long-Term Incentive Plan.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|10.23(3)^  |  | First Amendment to MarkWest Energy Partners, L.P. Long-Term Incentive Plan.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|10.24(16)  |  | Credit Agreement among MarkWest Hydrocarbon, Inc. as the Borrower, Royal Bank of Canada, as Administrative Agent and RBC Capital Markets, as Lead Arranger and Sole Bookrunner, to the $25,000,000 Senior Credit Facility.                                                                                                                                                                                                                                                                                                                                                                                                          
|10.25++    |  | Purchase and Sale of Natural Gas Agreement dated as of September 24, 2004, between MarkWest Hydrocarbon, Inc. and Equitable Production Company.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|10.26++    |  | A Firm Natural Gas Processing Agreement dated as of September 24, 2004, between MarkWest Hydrocarbon, Inc. and Equitable Production Company.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|10.27++    |  | A Netting, Financial and Security Agreement dated as of September 24, 2004, between MarkWest Hydrocarbon, Inc. and Equitable Production Company.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|10.28(17)  |  | Purchase and Sale Agreement dated as of January 24, 2005 by and among Enterprise Products Operating, L.P., as seller and MarkWest Energy Partners, L.P., as buyer.                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|           |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     

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|10.29(19)  |  | Fourth Amended and Restated Credit Agreement, dated as of November 1, 2005, among MarkWest Energy Operating Company, L.LC., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, JP Morgan Chase
Bank, N.A., as Co-Syndication Agent, Fortis Capital Corp., as Co-Syndication Agent, Societe Generale, as Co-Documentation Agent, Wachovia Bank, National Association, as Co-Documentation Agent and RBC Capital Markets, as Sole Lead Arranger and
Bookrunner to the $100,000,000 Revolver Facility and $400,000 Term Loan                                                                                                     
|---------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.30(21)  |  | Fifth Amended and Restated Credit Agreement dated as of December 29, 2005, among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent and Collateral
Agent, JP Morgan Chase Bank, N.A., as Syndication Agent, Fortis Capital Corp., as Co-Documentation Agent, U.S. Bank, National Association, as Co-Documentation Agent, Societe Generale, as Co-Documentation Agent, and Wachovia Bank, National Association,
 as Co-Documentation Agent, RBC Capital Markets and J.P. Morgan Securities Inc., as Lead Arrangers and Joint Bookrunners, to the $615,000,000 Senior Credit Facility.
|10.31(21)  |  | Third Amendment to Credit Agreement dated as of December 30, 2005, among MarkWest Hydrocarbon, Inc., as Borrower, MarkWest Energy, G.P., L.L.C., as Co-Guarantor, MarkWest Michigan, Inc., as Co-Guarantor, MarkWest Resources, Inc.,
as Co-Guarantor, Matrex, L.L.C., as Co-Guarantor, Royal Bank of Canada, as Administrative Agent for the Lenders, U.S. Bank, National Association and Bank of Oklahoma, N.A. as Lenders to the $25,000,000 Senior Credit Facility.                                                                                                                                                                                                              
|10.32(22)  |  | First Amended and Restated Credit Agreement dated as of January 31, 2006, among MarkWest Hydrocarbon, Inc., as Borrower, Royal Bank of Canada, as Administrative Agent for the Lenders, U.S. Bank, National Association and Bank of Oklahoma,
N.A. as Lenders to the $25,000,000 Senior Credit Facility.                                                                                                                                                                                                                                                                                                                                                                             
|10.33(23)  |  | Amendment No. 1 to the First Amended and Restated Credit Agreement dated as of March 23, 2006, among MarkWest Hydrocarbon, Inc., as Borrower, Royal Bank of Canada, as Administrative Agent for the Lenders, U.S. Bank, National
Association and Bank of Oklahoma, N.A. as Lenders to the $25,000,000 Senior Credit Facility.                                                                                                                                                                                                                                                                                                                                                        
|10.34(24)  |  | Lease Agreement dated as of April 19, 2006 between MarkWest Energy Partners, L.P., and Park Central Property, L.L.C.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|10.35(25)^ |  | 2006 Stock Incentive Plan.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|10.36(26)+ |  | Gas Processing Agreement dated as of May 10, 2006 between MarkWest Pinnacle, L.P., and Chesapeake Exploration, L.P.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|10.37(28)  |  | Second Amended and Restated Credit Agreement dated as of August 18, 2006 among MarkWest Hydrocarbon, Inc., as Borrower, Royal Bank of Canada, as Administrative Agent and Collateral Agent, and the Lenders party thereto the $65,000,000 Senior
Credit Facility.                                                                                                                                                                                                                                                                                                                                                                                                                    
|10.38(30)+ |  | Construction, Operation and Gas Gathering Agreement dated as of September 21, 2006 between MarkWest Western Oklahoma Gas Company, L.L.C., and Newfield Exploration Mid-Continent, Inc.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
|           |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      

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|10.39(32) |  | Form of Indemnification Agreement between MarkWest Hydrocarbon, Inc. and each Non-employee Director and the following Officers of the Company: Frank Semple, President and Chief Executive Officer; Nancy Buese, Senior Vice President and Chief
Financial Officer; Randy Nickerson, Senior Vice President and Chief Commercial Officer; John Mollenkopf, Senior Vice President and Chief Operations Officer; C. Corwin Bromley, Senior Vice President, General Counsel and Secretary; David Young, Senior
Vice President of Corporate Services; Richard Ostberg, Vice President of Risk and Compliance, and Andrew Schroeder, Vice President and Treasurer dated as of January 26, 2007.
|--------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.40(31) |  | First Amendment to the Second Amended and Restated Credit Agreement entered into as of February 16, 2007, among MarkWest Hydrocarbon, Inc., as borrower, the undersigned Guarantors, Royal Bank of Canada, as Administrative Agent and
Collateral Agent and the undersigned Issuer and Lenders party thereto the $50,000,000 Revolving Credit Facility.                                                                                                                                                                                                                                                                                                                                  
|16.1(18)  |  | Letter from KPMG, LLP regarding Change in Certifying Accountants.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|21.1(32)  |  | List of Subsidiaries of MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|23.1*     |  | Consent of Deloitte & Touche, LLP.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|23.2*     |  | Consent of KPMG, LLP.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|31.1*     |  | Chief Executive Officer Certification Pursuant to Rule 13a-14(a) of the Securities Exchange Act.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|31.2*     |  | Chief Financial Officer Certification Pursuant to Rule 13a-14(a) of the Securities Exchange Act.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|32.1*     |  | Certification of the Chief Executive Officer Pursuant to 18 U.S. C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes- Oxley Act of 2002.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|32.2*     |  | Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   

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175

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176

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SIGNATURES

Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its
behalf by the undersigned, thereunto duly authorized.

|                 |  | MarkWest Hydrocarbon, Inc.
(Registrant)
|---------------- |  | ---------------------------------------
|November 2, 2007 |  | By:                                    

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

|Date: November 2, 2007 |  | By: | /s/FRANK M. SEMPLEFrank M. Semple President and Chief
Executive Officer
(Principal Executive Officer)                 
|---------------------- |  | --- | ----------------------------------------------------------------------------------------------------------------------
|Date: November 2, 2007 |  | By: | /s/NANCY K. BUESENancy K. Buese Chief Financial Officer
(Principal Financial Officer and Principal Accounting Officer)
|Date: November 2, 2007 |  | By: | /s/JOHN M. FOXJohn M. Fox Chairman of the Board and Director                                                          
|Date: November 2, 2007 |  | By: | /s/MICHAEL L. BEATTYMichael L. Beatty Director                                                                        
|Date: November 2, 2007 |  | By: | /s/DONALD C. HEPPERMANNDonald C. Heppermann Director                                                                  
|                       |  |     |                                                                                                                       

177

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|Date: November 2, 2007 |  | By: | /s/WILLIAM A. KELLSTROMWilliam A. Kellstrom Director
|---------------------- |  | --- | ----------------------------------------------------
|Date: November 2, 2007 |  | By: | Anne E. Mounsey Director                            
|Date: November 2, 2007 |  | By: | /s/KAREN L. ROGERSKaren L. Rogers Director          
|Date: November 2, 2007 |  | By: | /s/WILLIAM F. WALLACEWilliam F. Wallace Director    
|Date: November 2, 2007 |  | By: | /s/DONALD D. WOLFDonald D. Wolf Director            

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