Use these links to rapidly review the documentTable of Contents ITEM 8. Financial Statements and Supplementary Data Starfish Pipeline Company, LLC Index December 31, 2006 and 2005



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

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FORM 10-K/A(Amendment No. 3)

|ý                                            |  | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934    
|-------------------------------------------- |  | ----------------------------------------------------------------------------------------
|For the fiscal year ended December 31, 2006.
|or                                          
|o                                            |  | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

for the transition period
from                        to                
        .

Commission File Number 001-31239

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

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

1515 Arapahoe Street, Tower 2, Suite 700, Denver, CO 80202-2126(Address of principal executive offices)

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

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

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

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

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

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

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

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

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

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

The aggregate market value of Common Units held by non-affiliates of the registrant on June 30, 2006 was approximately $556,894,000.

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

DOCUMENTS INCORPORATED BY REFERENCE:None.



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

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

As discussed in Note 23,Restatement of Consolidated Financial Statements, to the consolidated financial statements in
Item 8 of this Form 10-K/A, we have restated our previously reported results to properly record certain types of revenue transactions on a gross presentation in the Partnership's East
Texas segment consistent with the guidance in Emerging Issues Task Force ("EITF") Issue No. 99-19,Reporting Revenue Gross as a Principal versus Net as an
Agent.These transactions were previously accounted for net as an agent. This guidance requires the Partnership to record revenue gross when it acts as a principal and net when
it acts as an agent.

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

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

Table of Contents



|PART I    
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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 Energy" or the "Partnership" are intended to mean MarkWest
Energy Partners, L.P., and its consolidated subsidiaries.

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Glossary of Terms

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

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

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Forward-Looking Statements

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

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

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



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

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PART I

ITEM 1.    Business

General

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

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

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



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Industry Overview, Competition

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

ART

The
natural gas gathering process begins with the drilling of wells into gas bearing rock formations. Once completed, the well is connected to a gathering system. Gathering systems
typically consist of a

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

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

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

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

ART

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

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

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

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



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

Our
competitors include:



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

We
believe our competitive strengths include:



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



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

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



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

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



Our Contracts

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



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

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

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

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

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

Year ended December 31,2006

2005

2004Revenues

$
629,911

$
541,090

$
319,119Purchased product costs


376,237


408,884


229,339Net operating margin


253,674


132,206


89,780Facility expenses


60,112


47,972


29,911Selling, general and administrative


44,185


21,573


16,133Depreciation


29,993


19,534


15,556Amortization of intangible


16,047


9,656


3,640Accretion of asset retirement obligation


102


159


13Impairments








130Income from operations

$
103,235

$
33,312

$
24,397


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

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

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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.

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Acquisitions

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

|Name                    |  | Assets                                                          |  | Location                          |  | Consideration |       | Closing Date
|----------------------- |  | --------------------------------------------------------------- |  | --------------------------------- |  | ------------- | ----- | ------------
|Santa Fe                |  | Grimes gathering system                                         |  | Oklahoma                          |  | $             | 15.0  |             
|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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We were formed by MarkWest Hydrocarbon in 2002 to acquire most of its natural gas gathering and processing assets and NGL transportation, fractionation and
storage assets. MarkWest Hydrocarbon remains one of our largest customers. We expect to continue deriving a portion of our revenues from the services we provide under our contracts with MarkWest
Hydrocarbon; however, the percentage of our revenues and net operating margins will likely continue to decline as our other businesses grow. For the years ended December 31, 2006 and 2005, it
accounted for 13% of our revenues. As of December 31, 2006, MarkWest Hydrocarbon and its subsidiaries, in the aggregate, owned a 17% interest in the Partnership, consisting of 1,200,000
subordinated units, 3,738,992 common units and a 2% general partner interest.

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

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



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

Segment Reporting

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



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

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

|                     |  | East Texas |   | Oklahoma |   | Other
Southwest |   | Appalachia |   | Michigan |   | Gulf Coast |   | Total |  
|-------------------- |  | ---------- | - | -------- | - | --------------- | - | ---------- | - | -------- | - | ---------- | - | ----- | -
|Revenue              |  | 28         | % | 33       | % | 14              | % | 12         | % | 2        | % | 11         | % | 100   | %
|Net operating margin |  | 33         | % | 15       | % | 7               | % | 13         | % | 4        | % | 28         | % | 100   | %

Regulatory Matters

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



Interstate Gas Pipelines.Our natural gas pipeline operations are subject to federal, state and local regulatory authorities.
Specifically, our Hobbs, New Mexico natural gas pipeline and our Michigan

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



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

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

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

Natural
gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a less stringent approach to regulation of the gathering
activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. Our gathering operations could be adversely
affected should they be subject in

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the
future to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design,
installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to
time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on
future legislative and regulatory changes.

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

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

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

With
respect to our Michigan Crude Pipeline, we filed a tariff establishing a cost-of-service rate structure to be effective starting January 1, 2006. Two
shippers and a producer protested the filing. On December 29, 2005, the Commission accepted our filing and permitted the rates to go into effect subject to refund. The Commission established
hearing procedures but first referred the parties to settlement discussions before a FERC-appointed settlement judge. On January 31, 2006, the parties submitted a settlement to the
FERC that re-established the pre-existing Michigan intrastate pipeline rates with minor modifications and place a moratorium on rate changes or challenges for a
three-year period, with limited exceptions. On March 7, 2006, the FERC settlement judge certified the settlement to the FERC as uncontested and fair, reasonable, and in the public
interest.

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Environmental Matters



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

We
believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations, and that the cost of continued compliance with such laws
and regulations will not have a material adverse effect on our results of operations or financial condition. We cannot ensure, however, that existing environmental laws and regulations will not be
revised or that
new laws and regulations will not be adopted or become applicable to us. The clear trend in environmental law is to place more restrictions and limitations on activities that may be perceived to
affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental-regulation compliance or remediation, and actual future expenditures may
be different from the amounts we currently anticipate. Revised or additional environmental requirements that result in increased compliance costs or additional operating restrictions, particularly if
those costs are not fully recoverable from our customers, could have material adverse effect on our business, financial condition, results of operations and cash flow.



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

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



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



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



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

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Pipeline Safety Regulations

Our pipelines are subject to regulation by the U.S. Department of Transportation ("DOT") under the Pipeline Safety Act of 1992, as amended, and the newly enacted
Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, (collectively the "Pipeline Safety Acts"), and the Hazardous Liquid Pipeline Safety Act of 1979 ("HLPSA"), as amended; and the
Pipeline Integrity Management ("PIM") in High Consequence Areas (Gas Transmission Pipelines) amendment to 49 CFR Part 192, effective February 14, 2004, relating to the design,
installation, testing, construction, operation, replacement and management of pipeline facilities. The Pipeline Safety Act of 1992 required the Research and Special Programs Administration of the DOT
to consider environmental impacts, as well as its traditional public safety mandate, when developing pipeline safety regulations. The DOT's pipeline operator qualification rules require minimum
qualification requirements for personnel performing operations and maintenance activities on hazardous liquid pipelines. HLPSA covers crude oil, carbon dioxide, NGL and petroleum products pipelines
and requires any entity which owns or operates pipeline facilities to comply with the regulations under HLPSA, to permit access to and allow copying of records and to make certain reports and provide
information as required by the Secretary of Transportation. The Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) amendment to 49 CFR Part 192 (PIM) requires
operators of gas transmission pipelines to ensure the integrity of their pipelines through hydrostatic pressure testing, the use of in-line inspection tools or through
risk-based direct assessment techniques. The Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 expands the DOT's authority and calls for additional studies and
additional regulations to be promulgated in many areas, including integrity management, corrosion control, incident reporting, inspection and enforcement orders. While we believe that our pipeline
operations are in substantial compliance with applicable requirements, due to the possibility of new or amended laws and regulations, or reinterpretation of existing laws and regulations, there can be
no assurance that future compliance with the requirements will not have a material adverse effect on our results of operations or financial position.

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

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Employee Safety

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

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

Employees

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

Available Information

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

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ITEM 1A.    Risk Factors

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

Risks Inherent in Our Business

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

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



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



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

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

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

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

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

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



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

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

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

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

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

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

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

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

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



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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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



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

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

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

The
extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. We have a policy to enter into derivative transactions related
to only a portion of the volume of our expected production or fuel requirements and, as a result, we will continue to have direct commodity price exposure to the unhedged portion. Please read
"Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operationsand Item 7A. Quantitative and Qualitative Disclosures about Market Risk" as set
forth in this report. Our actual future production or fuel requirements may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the
actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the amount that is subject to our derivative financial
instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity,
resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in
certain circumstances may actually increase the volatility of our cash flows. In addition, our hedging activities are subject to the risks that a counterparty may not perform its

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obligation
under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our hedging policies and procedures are not properly followed. It is possible that the
steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional
misconduct is involved. For further information about our risk management policies and procedures, please read "Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operationand Item 7A. Quantitative and Qualitative Disclosures About Market RiskCommodity Price Risk and Our Risk Management Policy" as set forth in this report.

We have found a material weakness in our internal controls that requires remediation and concluded, pursuant to Section 404 of the Sarbanes-Oxley
Act of 2002, that our internal controls over financial reporting at December 31, 2006, were not effective.

As we discuss in our Management's Report on Internal Control over Financial Reporting in Part II, Item 9A, "Controls and Procedures," of this
Form 10-K/A, we have discovered deficiencies, including a material weakness, in our internal controls over financial reporting as of December 31, 2006. In particular, we
identified the presence of, the following material weakness:

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

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

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

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

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

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

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

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

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

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

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

Numerous governmental agencies enforce comprehensive and stringent laws and regulations on a wide range of environmental, safety and other regulatory matters. We
could be adversely affected by increased costs due to stricter pollution-control requirements or liabilities resulting from non-compliance with operating or other regulatory permits. New
environmental laws and regulations might adversely influence our products and activities. Federal, state and local agencies also could impose additional safety requirements, any of which could affect
our profitability. In addition, we face the risk of accidental releases or spills associated with our operations. These could result in material costs and liabilities, including those relating to
claims for damages to property and persons. Our failure

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

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

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

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

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



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

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

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

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

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

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

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

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

Risks Related to Our Partnership Structure

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

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

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

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

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



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

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

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

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

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

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

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

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

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

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

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

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

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

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

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



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



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

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

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

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

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

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

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

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

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

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

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

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

ITEM 1B.    Unresolved Staff Comments

None.

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ITEM 2.    Properties

Gas Processing Facilities:

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

|            |                               |  |                     |  |      |  |         | Year ended December 31, 2006
|----------- | ----------------------------- |  | ------------------- |  | ---- |  | ------- | ----------------------------
|
|
|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 |                             

---

Fractionation Facility:

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

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

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Natural Gas Pipelines:

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

|                 |                                    |  |                                         |  |     |  |           |  |         | Year ended December 31, 2006 |        
|---------------- | ---------------------------------- |  | --------------------------------------- |  | --- |  | --------- |  | ------- | ---------------------------- | -------
|
|
|East Texas:      |                                    |  |                                         |  |     |  |           |  |         |                              |        
|                 | East Texas gathering system        |  | Panola County, TX                       |  | 311 |  | 1990      |  | 410,000 |                              | 378,000
|Oklahoma:        |                                    |  |                                         |  |     |  |           |  |         |                              |        
|                 | Foss Lake gathering system         |  | Roger Mills 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  

---

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NGL Pipelines:

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

|            |                         |  |                                        |  |      |  |      |  |         | Year ended December 31, 2006 |        
|----------- | ----------------------- |  | -------------------------------------- |  | ---- |  | ---- |  | ------- | ---------------------------- | -------
|
|
|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 liquidline   |  | 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:

|          |                         |  |                                            |  |     |  |      |  |        | 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

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

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

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

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

ITEM 3.    Legal Proceedings

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

In
2005 MarkWest Hydrocarbon, the Partnership, several of its affiliates, and an unrelated co-defendant, were served with three lawsuits, which in 2006 were
consolidated into a single action 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
Partnership notified its general liability insurance carriers of the incident and the lawsuits in a timely manner and coordinated its legal defense with the insurers. As of
February 1, 2007, all of the claims in the litigation were fully settled, with MarkWest's insurance carrier and its co-defendant and its separate insurance carrier, funding the
settlements.

Related
to the above referenced pipeline incident, MarkWest Hydrocarbon and the Partnership have filed an independent action 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 Partnership for certain expenses related to the
pipeline incident. These include the Partnership's internal expenses and costs incurred for damage to, and loss of use of the pipeline, equipment and products; the extra transportation costs incurred
for transporting the liquids while the pipeline was out of service; the reduced volumes of liquids that could be processed; and the costs of complying with the OPS Corrective Action Order (hydrostatic
testing, repair/replacement and other pipeline integrity assurance measures). These expenses and costs have been expensed as incurred and any potential recovery from the All-Risks Property
and Business Interruption insurance carriers will be treated as "other income" if and when it is received. Following initial discovery, the Partnership was granted leave of the Court to amend its
complaint to add a bad faith claim, and a claim for punitive damages. The Partnership has not provided for a receivable for any of the claims in this action because of the uncertainty as to

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

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

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

With
regard to the Partnership's Javelina facility, MarkWest Javelina is a party with numerous other defendants to several lawsuits brought by various plaintiffs who had residences or
businesses located near the Corpus Christi industrial area, an area which included the Javelina gas processing plant, and several petroleum, petrochemical and metal processing and refining operations.
These suits,Victor Huff v. ASARCO Incorporated, et al. (Cause No. 98-01057-F, 214th Judicial Dist. Ct.,
County of Nueces, Texas, original petition filed in March 3, 1998);Hipolito Gonzales et al. v. ASARCO Incorporated, et al., (Cause
No. 98-1055-F, 214th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in 1998);Jason and Dianne Gutierrez,
individually and as representative of the estate of Sarina Galan Gutierrez(Cause No. 05-2470-A, 28TH Judicial District, severed
May 18, 2005, from theGonzalescase cited above); andEsmerejilda G. Valasquez, et al. v. Occidental Chemical
Corp., et al.,Case No. A-060352-C, 128thJudicial District, Orange County, Texas, original petition filed July 10, 2006; as
refiled from previously dismissed petition 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 Partnership is a party to various other legal actions. While it is not possible to predict the outcome of the legal actions with certainty,
management is of the opinion that appropriate provision and accruals for potential losses associated with all legal actions have been made in the financial statements. In the opinion of management,
none of these actions, either individually or in the aggregate, will have a material adverse effect on the Partnership's financial condition, liquidity or results of operations.

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

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

44

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PART II

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

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

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

|Quarter Ended      |  | High |       | Low |   | Distributions
Per
Common
Unit |  | Distributions
Per
Subordinated
Unit |       | Record Date |   | Payment Date
|------------------ |  | ---- | ----- | --- | - | ----------------------------- |  | ----------------------------------- | ----- | ----------- | - | ------------
|December 31, 2006  |  | $    | 29.95 |     | $ | 23.38                         |  | $                                   | 0.500 |             | $ | 0.500       
|September 30, 2006 |  | $    | 24.75 |     | $ | 20.50                         |  | $                                   | 0.485 |             | $ | 0.485       
|June 30, 2006      |  | $    | 23.33 |     | $ | 19.75                         |  | $                                   | 0.460 |             | $ | 0.460       
|March 31, 2006     |  | $    | 24.00 |     | $ | 21.76                         |  | $                                   | 0.435 |             | $ | 0.435       
|December 31, 2005  |  | $    | 25.48 |     | $ | 21.01                         |  | $                                   | 0.410 |             | $ | 0.410       
|September 30, 2005 |  | $    | 26.75 |     | $ | 23.59                         |  | $                                   | 0.410 |             | $ | 0.410       
|June 30, 2005      |  | $    | 25.77 |     | $ | 23.26                         |  | $                                   | 0.400 |             | $ | 0.400       
|March 31, 2005     |  | $    | 26.25 |     | $ | 22.63                         |  | $                                   | 0.400 |             | $ | 0.400       

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

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

Distributions of Available Cash

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

45

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Distributions of Available Cash During the Subordination Period

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



Distributions of Available Cash After the Subordination Period

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



Incentive Distribution Rights

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

If
for any quarter:



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



46

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

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

Subordinated
UnitsSubordinated units outstanding at December 31, 2004

6,000,000ConversionAugust 15, 2005

(1,200,000
)ConversionNovember 15, 2005

(1,200,000
)Subordinated units outstanding at December 31, 2005

3,600,000ConversionAugust 15, 2006

(1,200,000
)ConversionNovember 15, 2006

(1,200,000
)Subordinated units outstanding at December 31, 2006

1,200,000


Securities Authorized for Issuance under Equity Compensation Plans

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

|                                                            |                                             | Number of securities
to be issued upon
exercise of outstanding
options, warrants
and rights |         | Weighted-average
exercise price of
outstanding options,
warrants and rights(1) |   | Number of securities
remaining available
for future issuance
under equity
compensation plans
|----------------------------------------------------------- | ------------------------------------------- | ------------------------------------------------------------------------------------------- | ------- | ------------------------------------------------------------------------------ | - | --------------------------------------------------------------------------------------------
|Equity compensation plans approved by security holders      |                                             |                                                                                            |         |                                                                               |   |                                                                                            
|Equity compensation plans not approved by security holders: |                                             |                                                                                             |         |                                                                                |   |                                                                                             
|                                                            | Long-Term Incentive Plan(restricted units) |                                                                                             | 125,200 |                                                                                |  |                                                                                             
|                                                            | Long-Term Incentive Plan(unit options)     |                                                                                             |        |                                                                                |  |                                                                                             
|                                                            |                                             |                                                                                             |         |                                                                                |   |                                                                                             
|Total                                                       |                                             | 125,200                                                                                     |         |                                                                               |   | 728,242                                                                                     
|                                                            |                                             |                                                                                             |         |                                                                                |   |                                                                                             

---

47

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ITEM 6.    Selected Financial Data

The following table sets forth selected consolidated historical financial and operating data for MarkWest Energy Partners. We have derived the
summary selected historical financial data from our consolidated financial statements and related notes. Certain amounts below have been restated to reflect the Partnership's conclusion that certain
types of revenue transactions were incorrectly accounted for net as an agent and should have been recorded in a gross presentation in the Partnership's East Texas segment. Refer to Note 23 to
the accompanying consolidated financial statements included in Item 8 of this Form 10-K/A for a more detailed explanation of the financial statement restatements. All earnings per share
and dividend information have been updated to reflect the February 2007 two-for-one unit split. The selected financial data should be read in conjunction with the
combined and consolidated financial statements, including the notes thereto, andItem 7. Management's Discussion and Analysis of Financial Condition and Results of
Operation.

|                                     |                                                                                                        | Year Ended December 31,    |        
|------------------------------------ | ------------------------------------------------------------------------------------------------------ | -------------------------- | -------
|
|
|
|Statement of Operations:             |                                                                                                        |                            |        
|Revenues                             |                                                                                                        | $                          | 629,911
|                                     | 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                                                                                 |                            |        
|                                     | Earnings (losses) from unconsolidated affiliates                                                       |                            |        
|                                     | Interest income                                                                                        |                            |        
|                                     | Interest expense                                                                                       |                            |        
|                                     | Amortization of deferred financing costs and original issue discount (a component of interest expense) |                            |        
|                                     | Miscellaneous income (expense)                                                                         |                            |        
|                                     |                                                                                                        |                            |        
|                                     | Income before income taxes                                                                             |                            |        
|                                     | Income tax benefit (expense)                                                                           |                            |        
|                                     |                                                                                                        |                            |        
|                                     |                                                                                                        | Net income                 |        
|                                     |                                                                                                        |                            |        
|                                     | Net income per limited partner unit (see Item 8.Note 12):                                             |                            |        
|                                     | Basic                                                                                                  |                            | $      
|                                     | Diluted                                                                                                |                            | $      
|                                     | Cash distributions declared per limited partner unit                                                   |                            | $      
|Balance Sheet Data (at December 31): |                                                                                                        |                            |        
|                                     | Working capital                                                                                        |                            | $      
|                                     | Property, plant and equipment, net                                                                     |                            |        
|                                     | Total assets                                                                                           |                            |        
|                                     | Total long-term debt, including debt due to parent                                                     |                            |        
|                                     | Partners' capital                                                                                      |                            |        
|Cash Flow Data:                      |                                                                                                        |                            |        
|                                     | Net cash flow provided by (used in):                                                                   |                            |        
|                                     |                                                                                                        | Operating activities       |        
|                                     |                                                                                                        | Investing activities       |        
|                                     |                                                                                                        | Financing activities       |        
|Other Financial Data:                |                                                                                                        |                            |        
|                                     | Sustaining capital expenditures(4)                                                                     |                            | $      
|                                     | Expansion capital expenditures(4)                                                                      |                            |        
|                                     |                                                                                                        |                            |        
|                                     |                                                                                                        | Total capital expenditures |        
|                                     |                                                                                                        |                            |        

---

48

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Operating Data

|                    |                                                        | Year ended December 31,                   
|------------------- | ------------------------------------------------------ | ------------------------------------------
|
|East Texas:(1)      |                                                        |                                           
|                    | Gathering systems throughput (Mcf/d)                   |                                           
|                    |                                                        | NGL product sales (gallons)               
|Oklahoma:           |                                                        |                                           
|                    | Foss Lake gathering systems throughput (Mcf/d)         |                                           
|                    | Woodford Shale gathering systems throughput (Mcf/d)(2) |                                           
|                    |                                                        | Arapaho NGL product sales (gallons)       
|Other Southwest:(3) |                                                        |                                           
|                    | Appleby gathering systems throughput (Mcf/d)           |                                           
|                    |                                                        | Other gathering systems throughput (Mcf/d)
|                    |                                                        | Lateral throughput volumes (Mcf/d)(3)     
|Appalachia:(4)      |                                                        |                                           
|                    | 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)                |                                           
|                    |                                                        |                                           

49

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|Gulf Coast:(5) |                                         |  |         |  |         |  |    |  |    | 
|-------------- | --------------------------------------- |  | ------- |  | ------- |  | -- |  | -- | 
|               | Natural gas processed for a fee (Mcf/d) |  | 124,300 |  | 115,000 |  | NA |  | NA | 
|               | NGLs fractionated for a fee (Bbl/d)     |  | 26,200  |  | 25,600  |  | NA |  | NA | 

---

50

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

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

Overview

MarkWest Energy is a master limited partnership whose diverse portfolio of midstream assets serves many of the most prolific natural gas basins in the United
States. The Partnership is primarily engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids; and the gathering and
transportation of crude oil.

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

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

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

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

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

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

Financial Statement Restatement

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

51

---



upon. Although the misstatement for the year ended December 31, 2004 was deemed immaterial, revenue and purchased product costs have both been increased by $17.8 million to correct the
error. The restatement involves transactions in which the Partnership has determined it acted as a principal instead of an agent, thereby giving rise to accounting for revenue from such activities on
a gross rather than net basis. The Partnership arrived at this decision after an extensive review of its accounting for revenue arrangements consistent with the guidance in Emerging Issues Task Force
("EITF") Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent.

Impact of Acquisitions on Comparability of Financial Results

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

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

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



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



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



Our Relationship with MarkWest Hydrocarbon, Inc.

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

52

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

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

Results of Operations

Segment Reporting

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

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

East Texas

|                                                                     |                                           | Year ended December 31,                                                      |         |        |         |         |       
|-------------------------------------------------------------------- | ----------------------------------------- | ---------------------------------------------------------------------------- | ------- | ------ | ------- | ------- | ------
|
|
|
|Revenues                                                             |                                           | $                                                                            | 174,279 |        | $       | 128,267 |       
|Operating expenses:                                                  |                                           |                                                                              |         |        |         |         |       
|                                                                     | Purchased product costs                   |                                                                              |         | 91,637 |         |         | 81,030
|                                                                     | Facility expenses                         |                                                                              |         | 15,683 |         |         | 10,463
|                                                                     | Depreciation                              |                                                                              |         | 7,783  |         |         | 4,836 
|                                                                     | Amortization of intangible assets         |                                                                              |         | 8,244  |         |         | 8,293 
|                                                                     | Accretion of asset retirement obligations |                                                                              |         | 44     |         |         | 33    
|                                                                     |                                           |                                                                              |         |        |         |         |       
|                                                                     |                                           | Total operating expenses before selling, general and administrative expenses |         |        | 123,391 |         |       
|                                                                     |                                           |                                                                              |         |        |         |         |       
|Operating income before selling, general and administrative expenses |                                           | $                                                                            | 50,888  |        | $       | 23,612  |       
|                                                                     |                                           |                                                                              |         |        |         |         |       

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

53

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

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

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

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

Oklahoma

|                                                                     |                                           | Year ended December 31,                                                      |         |         |         |         |        
|-------------------------------------------------------------------- | ----------------------------------------- | ---------------------------------------------------------------------------- | ------- | ------- | ------- | ------- | -------
|
|
|
|Revenues                                                             |                                           | $                                                                            | 207,510 |         | $       | 214,043 |        
|Operating expenses:                                                  |                                           |                                                                              |         |         |         |         |        
|                                                                     | Purchased product costs                   |                                                                              |         | 170,168 |         |         | 193,787
|                                                                     | Facility expenses                         |                                                                              |         | 7,883   |         |         | 4,927  
|                                                                     | Depreciation                              |                                                                              |         | 3,007   |         |         | 2,385  
|                                                                     | Accretion of asset retirement obligations |                                                                              |         | 26      |         |         | 63     
|                                                                     |                                           |                                                                              |         |         |         |         |        
|                                                                     |                                           | Total operating expenses before selling, general and administrative expenses |         |         | 181,084 |         |        
|                                                                     |                                           |                                                                              |         |         |         |         |        
|Operating income before selling, general and administrative expenses |                                           | $                                                                            | 26,426  |         | $       | 12,881  |        
|                                                                     |                                           |                                                                              |         |         |         |         |        

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

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

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

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

54

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Other Southwest

|                                                                     |                                           | Year ended December 31,                                                      |        |        |        |         |       
|-------------------------------------------------------------------- | ----------------------------------------- | ---------------------------------------------------------------------------- | ------ | ------ | ------ | ------- | ------
|
|
|
|Revenues                                                             |                                           | $                                                                            | 84,595 |        | $      | 107,712 |       
|Operating expenses:                                                  |                                           |                                                                              |        |        |        |         |       
|                                                                     | Purchased product costs                   |                                                                              |        | 67,349 |        |         | 92,602
|                                                                     | Facility expenses                         |                                                                              |        | 5,638  |        |         | 4,990 
|                                                                     | Depreciation                              |                                                                              |        | 4,100  |        |         | 3,383 
|                                                                     | Amortization of intangible assets         |                                                                              |        |       |        |         | 68    
|                                                                     | Accretion of asset retirement obligations |                                                                              |        | 20     |        |         | 22    
|                                                                     |                                           |                                                                              |        |        |        |         |       
|                                                                     |                                           | Total operating expenses before selling, general and administrative expenses |        |        | 77,107 |         |       
|                                                                     |                                           |                                                                              |        |        |        |         |       
|Operating income before selling, general and administrative expenses |                                           | $                                                                            | 7,488  |        | $      | 6,647   |       
|                                                                     |                                           |                                                                              |        |        |        |         |       

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

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

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

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

55

---



Appalachia

|                                                                     |                                           | Year ended December 31,                                                      |        |        |        |        |       
|-------------------------------------------------------------------- | ----------------------------------------- | ---------------------------------------------------------------------------- | ------ | ------ | ------ | ------ | ------
|
|
|
|Revenue                                                              |                                           |                                                                              |        |        |        |        |       
|                                                                     | Unaffiliated                              |                                                                              | $      | 2,027  |        | $      | 1,686 
|                                                                     | Affiliated                                |                                                                              |        | 73,636 |        |        | 64,922
|                                                                     |                                           |                                                                              |        |        |        |        |       
|Total revenues                                                       |                                           |                                                                              | 75,663 |        |        | 66,608 |       
|                                                                     |                                           |                                                                              |        |        |        |        |       
|Operating expenses:                                                  |                                           |                                                                              |        |        |        |        |       
|                                                                     | Purchased product costs                   |                                                                              |        | 43,648 |        |        | 38,435
|                                                                     | Facility expenses                         |                                                                              |        | 13,997 |        |        | 19,360
|                                                                     | Depreciation                              |                                                                              |        | 3,573  |        |        | 3,187 
|                                                                     | Accretion of asset retirement obligations |                                                                              |        | 12     |        |        | 41    
|                                                                     |                                           |                                                                              |        |        |        |        |       
|                                                                     |                                           | Total operating expenses before selling, general and administrative expenses |        |        | 61,230 |        |       
|                                                                     |                                           |                                                                              |        |        |        |        |       
|Operating income before selling, general and administrative expenses |                                           | $                                                                            | 14,433 |        | $      | 5,585  |       
|                                                                     |                                           |                                                                              |        |        |        |        |       

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

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

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

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

56

---



Michigan

|                                                                   |                         | Year ended December 31,                                                      |        |       |        |        |      
|------------------------------------------------------------------ | ----------------------- | ---------------------------------------------------------------------------- | ------ | ----- | ------ | ------ | -----
|
|
|Revenues                                                           |                         | $                                                                            | 13,282 |       | $      | 12,479 |      
|Operating expenses:                                                |                         |                                                                              |        |       |        |        |      
|                                                                   | Purchased product costs |                                                                              |        | 3,435 |        |        | 3,030
|                                                                   | Facility expenses       |                                                                              |        | 5,721 |        |        | 6,080
|                                                                   | Depreciation            |                                                                              |        | 5,015 |        |        | 4,665
|                                                                   |                         |                                                                              |        |       |        |        |      
|                                                                   |                         | Total operating expenses before selling, general and administrative expenses |        |       | 14,171 |        |      
|                                                                   |                         |                                                                              |        |       |        |        |      
|Operating loss before selling, general and administrative expenses |                         | $                                                                            | (889   | )     | $      | (1,296 | )    
|                                                                   |                         |                                                                              |        |       |        |        |      

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

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

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

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

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

Gulf Coast

|                                                                     |                                   | Year ended December 31,                                                      |        |        |        |        |      
|-------------------------------------------------------------------- | --------------------------------- | ---------------------------------------------------------------------------- | ------ | ------ | ------ | ------ | -----
|
|
|Revenues                                                             |                                   | $                                                                            | 68,950 |        | $      | 13,832 |      
|Operating expenses:                                                  |                                   |                                                                              |        |        |        |        |      
|                                                                     | Facility expenses                 |                                                                              |        | 11,190 |        |        | 2,152
|                                                                     | Depreciation                      |                                                                              |        | 6,500  |        |        | 1,078
|                                                                     | Amortization of intangible assets |                                                                              |        | 7,803  |        |        | 1,295
|                                                                     |                                   |                                                                              |        |        |        |        |      
|                                                                     |                                   | Total operating expenses before selling, general and administrative expenses |        |        | 25,493 |        |      
|                                                                     |                                   |                                                                              |        |        |        |        |      
|Operating income before selling, general and administrative expenses |                                   | $                                                                            | 43,457 |        | $      | 9,307  |      
|                                                                     |                                   |                                                                              |        |        |        |        |      

57

---



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

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

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

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

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

Consolidated Financial Information

|                                                 |                                                  | Year ended December 31,        |         |         |         |         |        
|------------------------------------------------ | ------------------------------------------------ | ------------------------------ | ------- | ------- | ------- | ------- | -------
|
|
|Total segment operating income                   |                                                  | $                              | 141,803 |         | $       | 56,736  |        
|                                                 | Derivative gain (loss) not allocated to segments |                                |         | 5,632   |         |         | (1,851 
|                                                 | Depreciation not allocated to segments           |                                |         | (15     | )       |         |       
|                                                 | Selling, general and administrative              |                                |         | (44,185 | )       |         | (21,573
|                                                 |                                                  |                                |         |         |         |         |        
|                                                 |                                                  | Income from operations         |         |         | 103,235 |         |        
|Earnings (losses) from unconsolidated affiliates |                                                  |                                | 5,316   |         |         | (2,153  | )      
|Interest income                                  |                                                  |                                | 962     |         |         | 367     |        
|Interest expense                                 |                                                  |                                | (40,666 | )       |         | (22,469 | )      
|Amortization of deferred finance costs           |                                                  |                                | (9,094  | )       |         | (6,780  | )      
|Miscellaneous income                             |                                                  |                                | 11,100  |         |         | 78      |        
|                                                 |                                                  |                                |         |         |         |         |        
|                                                 |                                                  | Income before Texas Margin Tax |         | $       | 70,853  |         | $      
|                                                 | Texas Margin Tax                                 |                                |         | (769    | )       |         |       
|                                                 |                                                  |                                |         |         |         |         |        
|Net income                                       |                                                  | $                              | 70,084  |         | $       | 2,355   |        
|                                                 |                                                  |                                |         |         |         |         |        

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

58

---



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

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

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

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

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

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

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

59

---



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

East Texas

|                                                                     |                                           | Year ended December 31,                                                      |         |        |         |        |       
|-------------------------------------------------------------------- | ----------------------------------------- | ---------------------------------------------------------------------------- | ------- | ------ | ------- | ------ | ------
|
|
|Revenues                                                             |                                           | $                                                                            | 128,267 |        | $       | 39,737 |       
|Operating expenses:                                                  |                                           |                                                                              |         |        |         |        |       
|                                                                     | Purchased product costs                   |                                                                              |         | 81,030 |         |        | 21,474
|                                                                     | Facility expenses                         |                                                                              |         | 10,463 |         |        | 3,229 
|                                                                     | Depreciation                              |                                                                              |         | 4,836  |         |        | 1,489 
|                                                                     | Amortization of intangible assets         |                                                                              |         | 8,293  |         |        | 3,446 
|                                                                     | Accretion of asset retirement obligations |                                                                              |         | 33     |         |        | 13    
|                                                                     |                                           |                                                                              |         |        |         |        |       
|                                                                     |                                           | Total operating expenses before selling, general and administrative expenses |         |        | 104,655 |        |       
|                                                                     |                                           |                                                                              |         |        |         |        |       
|Operating income before selling, general and administrative expenses |                                           | $                                                                            | 23,612  |        | $       | 10,086 |       
|                                                                     |                                           |                                                                              |         |        |         |        |       

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

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

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

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

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

60

---



Oklahoma

|                                                                     |                                           | Year ended December 31,                                                      |         |         |         |         |        
|-------------------------------------------------------------------- | ----------------------------------------- | ---------------------------------------------------------------------------- | ------- | ------- | ------- | ------- | -------
|
|
|Revenues                                                             |                                           | $                                                                            | 214,043 |         | $       | 133,889 |        
|Operating expenses:                                                  |                                           |                                                                              |         |         |         |         |        
|                                                                     | Purchased product costs                   |                                                                              |         | 193,787 |         |         | 118,325
|                                                                     | Facility expenses                         |                                                                              |         | 4,927   |         |         | 3,659  
|                                                                     | Depreciation                              |                                                                              |         | 2,385   |         |         | 2,059  
|                                                                     | Accretion of asset retirement obligations |                                                                              |         | 63      |         |         |       
|                                                                     |                                           |                                                                              |         |         |         |         |        
|                                                                     |                                           | Total operating expenses before selling, general and administrative expenses |         |         | 201,162 |         |        
|                                                                     |                                           |                                                                              |         |         |         |         |        
|Operating income before selling, general and administrative expenses |                                           | $                                                                            | 12,881  |         | $       | 9,846   |        
|                                                                     |                                           |                                                                              |         |         |         |         |        

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

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

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

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

Other Southwest

|                                                                     |                                           | Year ended December 31,                                                      |         |        |         |        |       
|-------------------------------------------------------------------- | ----------------------------------------- | ---------------------------------------------------------------------------- | ------- | ------ | ------- | ------ | ------
|
|
|Revenues                                                             |                                           | $                                                                            | 107,712 |        | $       | 70,044 |       
|Operating expenses:                                                  |                                           |                                                                              |         |        |         |        |       
|                                                                     | Purchased product costs                   |                                                                              |         | 92,602 |         |        | 55,519
|                                                                     | Facility expenses                         |                                                                              |         | 4,990  |         |        | 3,694 
|                                                                     | Depreciation                              |                                                                              |         | 3,383  |         |        | 3,099 
|                                                                     | Amortization of intangible assets         |                                                                              |         | 68     |         |        | 194   
|                                                                     | Accretion of asset retirement obligations |                                                                              |         | 22     |         |        |      
|                                                                     |                                           |                                                                              |         |        |         |        |       
|                                                                     |                                           | Total operating expenses before selling, general and administrative expenses |         |        | 101,065 |        |       
|                                                                     |                                           |                                                                              |         |        |         |        |       
|Operating income before selling, general and administrative expenses |                                           | $                                                                            | 6,647   |        | $       | 7,538  |       
|                                                                     |                                           |                                                                              |         |        |         |        |       

61

---



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

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

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

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

Appalachia

|                                                                     |                                           | Year ended December 31,                                                      |        |        |        |        |       
|-------------------------------------------------------------------- | ----------------------------------------- | ---------------------------------------------------------------------------- | ------ | ------ | ------ | ------ | ------
|
|
|Revenues:                                                            |                                           |                                                                              |        |        |        |        |       
|                                                                     | Unaffiliated                              |                                                                              | $      | 1,763  |        | $      | 1,610 
|                                                                     | Affiliated                                |                                                                              |        | 64,845 |        |        | 59,026
|                                                                     |                                           |                                                                              |        |        |        |        |       
|Total revenues                                                       |                                           |                                                                              | 66,608 |        |        | 60,636 |       
|                                                                     |                                           |                                                                              |        |        |        |        |       
|Operating expenses:                                                  |                                           |                                                                              |        |        |        |        |       
|                                                                     | Purchased product costs                   |                                                                              |        | 38,435 |        |        | 30,031
|                                                                     | Facility expenses                         |                                                                              |        | 19,360 |        |        | 13,444
|                                                                     | Depreciation                              |                                                                              |        | 3,187  |        |        | 4,329 
|                                                                     | Impairment                                |                                                                              |        |       |        |        | 130   
|                                                                     | Accretion of asset retirement obligations |                                                                              |        | 41     |        |        |      
|                                                                     |                                           |                                                                              |        |        |        |        |       
|                                                                     |                                           | Total operating expenses before selling, general and administrative expenses |        |        | 61,023 |        |       
|                                                                     |                                           |                                                                              |        |        |        |        |       
|Operating income before selling, general and administrative expenses |                                           | $                                                                            | 5,585  |        | $      | 12,702 |       
|                                                                     |                                           |                                                                              |        |        |        |        |       

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

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

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

62

---



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

Michigan

|                                                                            |                         | Year ended December 31,                                                      |        |       |        |        |      
|--------------------------------------------------------------------------- | ----------------------- | ---------------------------------------------------------------------------- | ------ | ----- | ------ | ------ | -----
|
|
|Revenues                                                                    |                         | $                                                                            | 12,479 |       | $      | 15,633 |      
|Operating expenses:                                                         |                         |                                                                              |        |       |        |        |      
|                                                                            | Purchased product costs |                                                                              |        | 3,030 |        |        | 3,990
|                                                                            | Facility expenses       |                                                                              |        | 6,080 |        |        | 5,885
|                                                                            | Depreciation            |                                                                              |        | 4,665 |        |        | 4,580
|                                                                            |                         |                                                                              |        |       |        |        |      
|                                                                            |                         | Total operating expenses before selling, general and administrative expenses |        |       | 13,775 |        |      
|                                                                            |                         |                                                                              |        |       |        |        |      
|Operating income (loss) before selling, general and administrative expenses |                         | $                                                                            | (1,296 | )     | $      | 1,178  |      
|                                                                            |                         |                                                                              |        |       |        |        |      

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

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

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

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

Gulf Coast

|                                                                     |                                   | Year ended December 31,                                                      |        |       |       |  
|-------------------------------------------------------------------- | --------------------------------- | ---------------------------------------------------------------------------- | ------ | ----- | ----- | -
|
|
|
|Revenues                                                             |                                   | $                                                                            | 13,832 |       | $     | 
|Operating expenses:                                                  |                                   |                                                                              |        |       |       |  
|                                                                     | Facility expenses                 |                                                                              |        | 2,152 |       |  
|                                                                     | Depreciation                      |                                                                              |        | 1,078 |       |  
|                                                                     | Amortization of intangible assets |                                                                              |        | 1,295 |       |  
|                                                                     |                                   |                                                                              |        |       |       |  
|                                                                     |                                   | Total operating expenses before selling, general and administrative expenses |        |       | 4,525 |  
|                                                                     |                                   |                                                                              |        |       |       |  
|Operating income before selling, general and administrative expenses |                                   | $                                                                            | 9,307  |       | $     | 
|                                                                     |                                   |                                                                              |        |       |       |  

63

---



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

Consolidated Financial Information

|                                       |                                             | Year ended December 31,        |         |         |        |        |        
|-------------------------------------- | ------------------------------------------- | ------------------------------ | ------- | ------- | ------ | ------ | -------
|
|
|
|Total segment operating income         |                                             | $                              | 56,736  |         | $      | 41,350 |        
|                                       | Derivative losses not allocated to segments |                                |         | (1,851  | )      |        | (820   
|                                       | Selling, general and administrative         |                                |         | (21,573 | )      |        | (16,133
|                                       |                                             |                                |         |         |        |        |        
|                                       |                                             | Income from operations         |         |         | 33,312 |        |        
|Losses from unconsolidated affiliates  |                                             |                                | (2,153  | )       |        | (65    | )      
|Interest income                        |                                             |                                | 367     |         |        | 87     |        
|Interest expense                       |                                             |                                | (22,469 | )       |        | (9,236 | )      
|Amortization of deferred finance costs |                                             |                                | (6,780  | )       |        | (5,236 | )      
|Miscellaneous income                   |                                             |                                | 78      |         |        | 15     |        
|                                       |                                             |                                |         |         |        |        |        
|                                       |                                             | Income before Texas Margin Tax |         | $       | 2,355  |        | $      
|Texas Margin Tax (Note 14)             |                                             |                                |        |         |        |       |        
|                                       |                                             |                                |         |         |        |        |        
|Net income                             |                                             | $                              | 2,355   |         | $      | 9,962  |        
|                                       |                                             |                                |         |         |        |        |        

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

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

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

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

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

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

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Liquidity and Capital Resources

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

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

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

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

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

65

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

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

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

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

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

Cash Flow

December 31,2006

2005(in thousands)Net cash provided by operating activities

$
150,977

$
42,090Net cash used in investing activities


(119,338
)

(469,308
)Net cash provided by (used in) financing activities


(17,342
)

423,060


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

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

Net cash used in financing activities increased $440.4 million during the year ended December 31, 2006, compared to the year ended December 31, 2005. The increase
was due primarily to net proceeds from



additional long-term debt and private placements in 2005 to fund our 2005 acquisitions. Distributions to unitholders increased to $64.9 million in 2006 from $39.0 million in
2005.

Total Contractual Cash Obligations

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

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

---

Off-Balance Sheet Arrangements

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

Matters Influencing Future Results

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

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

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

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



transportation costs associated with the trucking are not expected to have material adverse effect on our results of operations or financial positions.

Seasonality

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

Effects of Inflation

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

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

Critical Accounting Policies and Estimates

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

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



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



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

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

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



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

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





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

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

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



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

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

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

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

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

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

The Partnership enters into revenue arrangements where it sells customer's gas and/or NGLs and depending on the nature of the arrangement acts as the principal or agent. Revenue from
such sales is recognized gross where the Partnership acts as the Principal, under EITF 99-19,




Reporting Revenue Gross as a Principal versus Net as an Agent, as the Partnership takes title to the gas and/or NGLs, has physical inventory risk and does not earn a fixed amount. Revenue is
recognized net when the Partnership earns a fixed amount and does not take ownership of the gas and/or NGLs.

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



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



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

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

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

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

|                                                                   |                                                                                                                                    | Year ended December 31, |       
|------------------------------------------------------------------ | ---------------------------------------------------------------------------------------------------------------------------------- | ----------------------- | ------
|
|
|Numerator for basic and diluted earnings per limited partner unit: |                                                                                                                                    |                         |       
|Net income                                                         |                                                                                                                                    | $                       | 70,084
|Less:                                                              |                                                                                                                                    |                         |       
|                                                                   | General partner's incentive distribution paid                                                                                      |                         |       
|                                                                   |                                                                                                                                    |                         |       
|Sub-total                                                          |                                                                                                                                    |                         | 58,783
|Plus:                                                              |                                                                                                                                    |                         |       
|                                                                   | Allocated depreciation expense attributable to the general partners contribution for construction of the Cobb Gas Extraction Plant |                         |       
|                                                                   | Participation plan allocation                                                                                                      |                         |       
|                                                                   |                                                                                                                                    |                         |       
|Net income before GP interest                                      |                                                                                                                                    |                         | 72,374
|Less:                                                              |                                                                                                                                    |                         |      
|                                                                   | General Partner's 2% interest                                                                                                      |                         |       
|                                                                   | Additional earnings allocated to general partners                                                                                  |                         |       
|                                                                   |                                                                                                                                    |                         |       
|Net income available to limited partners under EITF 03-6           |                                                                                                                                    | $                       | 70,927
|                                                                   |                                                                                                                                    |                         |       
|Denominator:                                                       |                                                                                                                                    |                         |       
|                                                                   | Denominator for basic earnings per limited partner unit-weighted average number of limited partner units                           |                         |       
|Effect of dilutive securities:                                     |                                                                                                                                    |                         |      
|                                                                   | Weighted-average of restricted units outstanding                                                                                   |                         |       
|                                                                   |                                                                                                                                    |                         |       
|                                                                   | Denominator for diluted earnings per limited partner unit-weighted average number of limited partner units                         |                         |       
|                                                                   |                                                                                                                                    |                         |       
|                                                                   |                                                                                                                                    |                         |      
|Basic net income per limited partner unit                          |                                                                                                                                    | $                       | 2.45  
|                                                                   |                                                                                                                                    |                         |       
|Diluted net income per limited partner unit                        |                                                                                                                                    | $                       | 2.44  
|                                                                   |                                                                                                                                    |                         |       



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

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

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

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

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



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

74

---



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

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

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

Recent Accounting Pronouncements

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

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

75

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

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

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

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

ITEM 7A.    Quantitative and Qualitative Disclosures About Market Risk

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



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

76

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

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

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

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

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

77

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

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

Fixed Swaps(1)

Contract Period

Fixed Price(4)

Fair ValueCrude390 Bbl/d

Jan-Dec 2007

$
68.46

$
473Crude600 Bbl/d

Jan-Dec 2007


64.77


(58
)Ethane50,000 Gal/d

Jan-Mar 2007


0.78


736$
1,151


Basis Swaps

Contract Period

Fair ValueNatural Gas14,000 MMBtu/d

Jan-Oct 2007

$
(33
)


Options (puts)(2)

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(3)

Contract Period

Floor(4)

Cap(4)

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


$
2,995Total current asset (liability) mark-to-market positions

$
4,120


78

---



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

Collars(3)

Contract Period

Floor(4)

Cap(4)

Fair 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
)$
1,397Total non-current asset (liability) mark-to-market positions

$
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

$
Current liability


91


728Noncurrent asset


2,759


Noncurrent liability


1,362





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

Fixed Swaps(1)

Contract Period

Price(2)Crude325 bbl/d (sale)

Jan-Dec 2007

$
62.11Crude550 bbl/d (sale)

Jan-Mar 2010


64.03Crude150 bbl/d (sale)

Mar-Dec 2007


62.40Crude2,000 bbl/d (sale)

Jan-Mar 2010


64.45




79

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

|Long-term Debt              |  | Interest Rate |  | Lending Limit |               | Due Date |                   | Outstanding at December 31, 2006
|--------------------------- |  | ------------- |  | ------------- | ------------- | -------- | ----------------- | --------------------------------
|Partnership Credit Facility |  | Variable      |  | $             | 250.0 million |          | December 29, 2010 |                                 
|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 approximately $0.3 million over a 12-month period.

80

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ITEM 8.    Financial Statements and Supplementary Data

Index to Consolidated Financial Statements



|Report of Deloitte & Touche LLP, Independent Registered Public Accounting Firm                                        
|----------------------------------------------------------------------------------------------------------------------
|Report of KPMG LLP, Independent Registered Public Accounting Firm                                                     
|Consolidated Balance Sheets at December 31, 2006 and 2005                                                             
|Consolidated Statements of Operations for the years ended December 31, 2006 (As restated), 2005 (As restated) and 2004
|Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2006, 2005 and 2004           
|Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 2006, 2005 and 2004       
|Consolidated Statements of Cash Flows for the years in the period ended December 31, 2006, 2005 and 2004              
|Notes to Consolidated Financial Statements for the years ended December 31, 2006, 2005 and 2004                       

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

81

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

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

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

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

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

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

/s/
DELOITTE & TOUCHE LLP

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

82

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

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

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

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

/s/ KPMG LLP

Denver,
Colorado
June 17, 2005

83

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MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands)

|                                                                                                  |                                                                                                                     | December 31,                             |         
|------------------------------------------------------------------------------------------------- | ------------------------------------------------------------------------------------------------------------------- | ---------------------------------------- | --------
|
|ASSETS                                                                                            |                                                                                                                     |                                          |         
|Current assets:                                                                                   |                                                                                                                     |                                          |         
|                                                                                                  | Cash and cash equivalents                                                                                           |                                          | $       
|                                                                                                  | Receivables, net of allowances of $118 and $151, respectively                                                       |                                          |         
|                                                                                                  | Receivables from affiliate                                                                                          |                                          |         
|                                                                                                  | Inventories                                                                                                         |                                          |         
|                                                                                                  | Fair value of derivative instruments                                                                                |                                          |         
|                                                                                                  | Other assets                                                                                                        |                                          |         
|                                                                                                  |                                                                                                                     |                                          |         
|                                                                                                  |                                                                                                                     | Total current assets                     |         
|                                                                                                  |                                                                                                                     |                                          |         
|Property, plant and equipment                                                                     |                                                                                                                     |                                          | 655,749 
|Less: Accumulated depreciation                                                                    |                                                                                                                     |                                          | (104,863
|                                                                                                  |                                                                                                                     |                                          |         
|                                                                                                  |                                                                                                                     | Total property, plant and equipment, net |         
|                                                                                                  |                                                                                                                     |                                          |         
|Other assets:                                                                                     |                                                                                                                     |                                          |         
|                                                                                                  | Investment in Starfish                                                                                              |                                          |         
|                                                                                                  | Investment in and advances to equity investee                                                                       |                                          |         
|                                                                                                  | Intangibles and other assets, net of accumulated amortization of $29,080 and $13,321 respectively                   |                                          |         
|                                                                                                  | Deferred financing costs, net of accumulated amortization of $5,326 and $4,424, respectively                        |                                          |         
|                                                                                                  | Fair value of derivative instruments                                                                                |                                          |         
|                                                                                                  | Other                                                                                                               |                                          |         
|                                                                                                  |                                                                                                                     |                                          |         
|                                                                                                  |                                                                                                                     | Total other assets                       |         
|                                                                                                  |                                                                                                                     |                                          |         
|                                                                                                  |                                                                                                                     | Total assets                             |         
|                                                                                                  |                                                                                                                     |                                          |         
|LIABILITIES AND CAPITAL                                                                           |                                                                                                                     |                                          |         
|Current liabilities:                                                                              |                                                                                                                     |                                          |         
|                                                                                                  | Accounts payable                                                                                                    |                                          | $       
|                                                                                                  | Payables to affiliate                                                                                               |                                          |         
|                                                                                                  | Accrued liabilities                                                                                                 |                                          |         
|                                                                                                  | Fair value of derivative instruments                                                                                |                                          |         
|                                                                                                  | Current portion of long-term debt                                                                                   |                                          |         
|                                                                                                  |                                                                                                                     |                                          |         
|                                                                                                  |                                                                                                                     | Total current liabilities                |         
|Long-term debt, net of current portion and original issue discount of $3,135 and $0, respectively |                                                                                                                     |                                          | 526,865 
|Deferred taxes                                                                                    |                                                                                                                     |                                          | 769     
|Fair value of derivative instruments                                                              |                                                                                                                     |                                          | 1,362   
|Other liabilities                                                                                 |                                                                                                                     |                                          | 1,360   
|                                                                                                  |                                                                                                                     |                                          |         
|                                                                                                  |                                                                                                                     | Total liabilities                        |         
|                                                                                                  |                                                                                                                     |                                          |         
|Commitments and contingencies (Note 17)                                                           |                                                                                                                     |                                          |         
|Capital:                                                                                          |                                                                                                                     |                                          |         
|                                                                                                  | General partner                                                                                                     |                                          |         
|                                                                                                  | Limited partners:                                                                                                   |                                          |         
|                                                                                                  | Common unitholders (31,166 and 22,139 units issued and outstanding at December 31, 2006 and 2005, respectively)     |                                          |         
|                                                                                                  | Subordinated unitholders (2,400 and 3,600 units issued and outstanding at December 31, 2006 and 2005, respectively) |                                          |         
|                                                                                                  |                                                                                                                     |                                          |         
|                                                                                                  |                                                                                                                     | Total capital                            |         
|                                                                                                  |                                                                                                                     |                                          |         
|                                                                                                  |                                                                                                                     | Total liabilities and capital            |         
|                                                                                                  |                                                                                                                     |                                          |         

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

84

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

|                                                                                                       |  | Year ended December 31, |        
|------------------------------------------------------------------------------------------------------ |  | ----------------------- | -------
|
|
|Revenues:                                                                                              |  |                         |        
|Unaffiliated parties                                                                                   |  | $                       | 550,643
|Affiliates                                                                                             |  |                         | 73,636 
|Derivative gain (loss)                                                                                 |  |                         | 5,632  
|                                                                                                       |  |                         |        
|Total revenues                                                                                         |  |                         | 629,911
|                                                                                                       |  |                         |        
|Operating expenses:                                                                                    |  |                         |        
|Purchased product costs                                                                                |  |                         | 376,237
|Facility expenses                                                                                      |  |                         | 60,112 
|Selling, general and administrative expenses                                                           |  |                         | 44,185 
|Depreciation                                                                                           |  |                         | 29,993 
|Amortization of intangible assets                                                                      |  |                         | 16,047 
|Accretion of asset retirement obligations                                                              |  |                         | 102    
|Impairments                                                                                            |  |                         |       
|                                                                                                       |  |                         |        
|Total operating expenses                                                                               |  |                         | 526,676
|                                                                                                       |  |                         |        
|Income from operations                                                                                 |  |                         | 103,235
|Other income (expense):                                                                                |  |                         |        
|Earnings (losses) from unconsolidated affiliates                                                       |  |                         | 5,316  
|Interest income                                                                                        |  |                         | 962    
|Interest expense                                                                                       |  |                         | (40,666
|Amortization of deferred financing costs and original issue discount (a component of interest expense) |  |                         | (9,094 
|Miscellaneous income, net                                                                              |  |                         | 11,100 
|                                                                                                       |  |                         |        
|Income before Texas Margin Tax                                                                         |  |                         | 70,853 
|Texas Margin Tax (Note 14)                                                                             |  |                         | (769   
|                                                                                                       |  |                         |        
|Net income                                                                                             |  | $                       | 70,084 
|                                                                                                       |  |                         |        
|Interest in net income:                                                                                |  |                         |        
|General partner                                                                                        |  | $                       | (843   
|                                                                                                       |  |                         |        
|Limited partners                                                                                       |  | $                       | 70,927 
|                                                                                                       |  |                         |        
|Net income per limited partner unit (see Note 2):                                                      |  |                         |        
|Basic                                                                                                  |  | $                       | 2.45   
|                                                                                                       |  |                         |        
|Diluted                                                                                                |  | $                       | 2.44   
|                                                                                                       |  |                         |        
|Weighted average units outstanding:                                                                    |  |                         |        
|Basic                                                                                                  |  |                         | 28,966 
|                                                                                                       |  |                         |        
|Diluted                                                                                                |  |                         | 29,098 
|                                                                                                       |  |                         |        
|Distributions declared per common unit                                                                 |  | $                       | 1.79   
|                                                                                                       |  |                         |        

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

85

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

|                     |                                                                                                         | Year ended December 31,
|-------------------- | ------------------------------------------------------------------------------------------------------- | -----------------------
|
|Net income           |                                                                                                         | $                      
|                     | Other comprehensive incomeunrealized gains on commodity derivative instruments accounted for as hedges |                        
|                     |                                                                                                         |                        
|Comprehensive income |                                                                                                         | $                      
|                     |                                                                                                         |                        

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

86

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

|                             |                                                                                                    | PARTNERS' CAPITAL |       |   |         |         |      
|---------------------------- | -------------------------------------------------------------------------------------------------- | ----------------- | ----- | - | ------- | ------- | -----
|
|
|
|
|Balance at December 31, 2003 |                                                                                                    | 5,628             |       | $ | 50,992  |         | 6,000
|                             | Issuance of units in secondary offerings, net of offering costs                                    |                   | 6,993 |   |         | 138,859 |      
|                             | Issuance of units in private placement, net of offering costs                                      |                   | 2,608 |   |         | 44,063  |      
|                             | Common units issued for vested restricted units, including contribution by MarkWest Energy GP, LLC |                   | 54    |   |         | 1,154   |      
|                             | Contributions by MarkWest Energy GP, LLC                                                           |                   |      |   |         |        |      
|                             | Participation Plan compensation expense allocated from MarkWest Hydrocarbon                        |                   |      |   |         |        |      
|                             | Distributions to partners                                                                          |                   |      |   |         | (14,192 | )    
|                             | Net income (loss)                                                                                  |                   |      |   |         | 6,607   |      
|                             | Other comprehensive income                                                                         |                   |      |   |         |        |      
|                             |                                                                                                    |                   |       |   |         |         |      
|Balance at December 31, 2004 |                                                                                                    | 15,283            |       | $ | 227,483 |         | 6,000
|                             | Issuance of units in private placement, net of offering costs                                      |                   | 4,438 |   |         | 97,518  |      
|                             | Common units issued for vested restricted units, including contribution by MarkWest Energy GP, LLC |                   | 18    |   |         | 432     |      
|                             | Contributions by MarkWest Energy GP, LLC                                                           |                   |      |   |         |        |      
|                             | Common unit registration costs                                                                     |                   |      |   |         | (45     | )    
|                             | Subordinated units converted to common units                                                       |                   | 2,400 |   |         | 496     |      
|                             | Participation Plan compensation expense allocated from MarkWest Hydrocarbon                        |                   |      |   |         |        |      
|                             | Distributions to partners                                                                          |                   |      |   |         | (24,866 | )    
|                             | Net income (loss)                                                                                  |                   |      |   |         | (136    | )    
|                             | Other comprehensive income                                                                         |                   |      |   |         |        |      
|                             |                                                                                                    |                   |       |   |         |         |      
|Balance at December 31, 2005 |                                                                                                    | 22,139            |       | $ | 300,882 |         | 3,600
|                             | Common units issued for vested restricted units                                                    |                   | 27    |   |         | 637     |      
|                             | Issuance of units in public offering, net of offering costs                                        |                   | 6,600 |   |         | 123,410 |      
|                             | Subordinated units converted to common units                                                       |                   | 2,400 |   |         | 203     |      
|                             | Contributions by MarkWest Energy GP, LLC                                                           |                   |      |   |         |        |      
|                             | Participation Plan compensation expense allocated from MarkWest Hydrocarbon                        |                   |      |   |         |        |      
|                             | Distributions to partners                                                                          |                   |      |   |         | (46,481 | )    
|                             | Net income (loss)                                                                                  |                   |      |   |         | 63,796  |      
|                             |                                                                                                    |                   |       |   |         |         |      
|Balance at December 31, 2006 |                                                                                                    | 31,166            |       | $ | 442,447 |         | 1,200
|                             |                                                                                                    |                   |       |   |         |         |      

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

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

|                                                                                                        |                                                                                   | Year ended December 31,                                   |       
|------------------------------------------------------------------------------------------------------- | --------------------------------------------------------------------------------- | --------------------------------------------------------- | ------
|
|Cash flows from operating activities:                                                                   |                                                                                   |                                                           |       
|Net income                                                                                              |                                                                                   | $                                                         | 70,084
|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                                          |                                                           |       
|                                                                                                        | Impairments                                                                       |                                                           |       
|                                                                                                        | Restricted unit compensation expense                                              |                                                           |       
|                                                                                                        | Participation Plan compensation expense                                           |                                                           |       
|                                                                                                        | Equity in (earnings) loss of unconsolidated affiliates                            |                                                           |       
|                                                                                                        | Distributions from equity investment                                              |                                                           |       
|                                                                                                        | Unrealized (gain) loss on derivative instruments                                  |                                                           |       
|                                                                                                        | Gain on sale of property, plant and equipment                                     |                                                           |       
|                                                                                                        | Loss on sale of equity investee                                                   |                                                           |       
|                                                                                                        | Deferred income taxes                                                             |                                                           |       
|                                                                                                        | Other                                                                             |                                                           |       
|Changes in operating assets and liabilities, net of working capital acquired:                           |                                                                                   |                                                           |       
|                                                                                                        | Receivables                                                                       |                                                           |       
|                                                                                                        | Receivables from affiliates                                                       |                                                           |       
|                                                                                                        | Inventories                                                                       |                                                           |       
|                                                                                                        | Other assets                                                                      |                                                           |       
|                                                                                                        | Accounts payable and accrued liabilities                                          |                                                           |       
|                                                                                                        | Payables to affiliates                                                            |                                                           |       
|                                                                                                        |                                                                                   |                                                           |       
|                                                                                                        |                                                                                   | Net cash provided by operating activities                 |       
|                                                                                                        |                                                                                   |                                                           |       
|Cash flows from investing activities:                                                                   |                                                                                   |                                                           |       
|                                                                                                        | Acquisitions                                                                      |                                                           |       
|                                                                                                        | Investment in Starfish                                                            |                                                           |       
|                                                                                                        | Capital expenditures                                                              |                                                           |       
|                                                                                                        | Payments on financing lease receivable                                            |                                                           |       
|                                                                                                        | Proceeds from sale of equity investee                                             |                                                           |       
|                                                                                                        | Proceeds from sale of property, plant and equipment                               |                                                           |       
|                                                                                                        |                                                                                   |                                                           |       
|                                                                                                        |                                                                                   | Net cash flows used in investing activities               |       
|                                                                                                        |                                                                                   |                                                           |       
|Cash flows from financing activities:                                                                   |                                                                                   |                                                           |       
|                                                                                                        | Proceeds from long-term debt                                                      |                                                           |       
|                                                                                                        | Payments of long-term debt                                                        |                                                           |       
|                                                                                                        | Proceeds from private placement of senior notes                                   |                                                           |       
|                                                                                                        | Payments for debt issuance costs, deferred financing costs and registration costs |                                                           |       
|                                                                                                        | Proceeds from private placements, net                                             |                                                           |       
|                                                                                                        | Proceeds from public unit offering, net                                           |                                                           |       
|                                                                                                        | Payments for deferred offering costs                                              |                                                           |       
|                                                                                                        | Contributions by MarkWest Energy GP, LLC                                          |                                                           |       
|                                                                                                        | Distributions to unitholders                                                      |                                                           |       
|                                                                                                        |                                                                                   |                                                           |       
|                                                                                                        |                                                                                   | Net cash flows provided by (used in) financing activities |       
|                                                                                                        |                                                                                   |                                                           |       
|                                                                                                        |                                                                                   |                                                           |       

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|Net increase (decrease) in cash                                       |  | $ | 14,297 |   | $ | (4,158 | ) | $ | 15,510 | 
|--------------------------------------------------------------------- |  | - | ------ | - | - | ------ | - | - | ------ | 
|Cash and cash equivalents at beginning of year                        |  |   | 20,105 |   |   | 24,263 |   |   | 8,753  | 
|                                                                      |  |   |        |   |   |        |  
|Cash and cash equivalents at end of year                              |  | $ | 34,402 |   | $ | 20,105 |   | $ | 24,263 | 
|                                                                      |  |   |        |   |   |        |  
|Supplemental disclosures of cash flow information:                    |  |   |        |   |   |        |   |   |        | 
|Cash paid during the year for interest, net of amounts capitalized    |  |   | 15,663 |   | $ | 22,112 |   | $ | 6,532  | 
|                                                                      |  |   |        |   |   |        |  
|Supplemental schedule of non-cash investing and financing activities: |  |   |        |   |   |        |   |   |        | 
|Construction projects in progress                                     |  | $ | (8,214 | ) | $ | (1,545 | ) | $ | 4,037  | 
|                                                                      |  |   |        |   |   |        |  
|Property, plant and equipment asset retirement obligation             |  | $ | 64     |   | $ | 561    |   | $ | 377    | 
|                                                                      |  |   |        |   |   |        |  
|Deferred offering costs payable                                       |  | $ |       |   | $ | 215    |   | $ |       | 
|                                                                      |  |   |        |   |   |        |  
|Accrued Private Placement Proceeds                                    |  | $ |       |   | $ | 5,000  |   | $ |       | 
|                                                                      |  |   |        |   |   |        |  
|Accrued amounts due to Javelina sellers and Starfish                  |  | $ |       |   | $ | 6,888  |   | $ |       | 
|                                                                      |  |   |        |   |   |        |  

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

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MARKWEST ENERGY PARTNERS, L.P.        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

MarkWest Energy Partners, L.P. was formed on January 25, 2002, as a Delaware limited partnership. The Partnership and its wholly owned subsidiary, MarkWest
Energy Operating Company, L.L.C. (the "Operating Company"), were formed to acquire, own and operate most of the assets, liabilities and operations of MarkWest Hydrocarbon, Inc.'s Midstream
Business (the "Midstream Business"). The Partnership is engaged in the gathering, processing and transmission of natural gas, the transportation, fractionation and storage of natural gas liquids, and
the gathering and transportation of crude oil. The Partnership is a processor of natural gas in the northeastern United States, processing gas from the Appalachian Basin, one of the country's oldest
natural gas producing regions, and from Michigan. Through nine acquisitions completed during 2003, 2004 and 2006, the Partnership has expanded its natural gas-gathering, processing and
transmission geographic coverage to the southwest United States. In addition, one of the Partnership's acquisitions has allowed it to enter into the Michigan crude oil transportation business. The
Partnership's principal executive office is located in Denver, Colorado.

2. Summary of Significant Accounting Policies



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

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 15,603,257 Common units and 600,000 Subordinated units.
For all periods presented, all references to the number of units and per unit net income and distribution amounts included in this report have been adjusted to give the effect to the unit split.



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



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

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



Property, plant and equipment 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


The
Partnership recognizes the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred, with an offsetting increase in the carrying
amount of the related long-lived asset. Over time, the liability is accreted to its future value, and the capitalized cost is depreciated over the useful life of the related asset. Upon
settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. The Partnership adopted FIN 47,Accounting for
Conditional Asset Retirement Obligations, on January 1, 2005. FIN 47 clarified the accounting for conditional asset retirement obligations under SFAS 143, Accounting for Asset Retirement
Obligations. A conditional asset retirement obligation is an unconditional legal obligation to perform an activity in
which the timing and / or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 requires an entity to recognize a liability for
a conditional asset retirement obligation if the amount can be reasonably estimated. Adopting FIN 47 had an immaterial impact on the Partnership.



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.

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The
Partnership's share of Starfish's income in 2006 was $5.3 million compared to a loss of $2.2 million in 2005.

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

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



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



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

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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 in Other assets, 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 method.



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

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



Management believes the carrying amount of financial instruments, including cash, accounts receivable, accounts payable, accrued expenses, and other financial
instruments approximates fair value because of the short-term maturity of these instruments. Management believes the carrying value of the Partnership's Credit Facility (Note 11)
approximates fair value due to its variable interest rates. The estimated fair value of the Senior Notes (Note 11) was approximately $499.8 million and $207.0 million at
December 31, 2006 and 2005, respectively, based on quoted market prices. Derivative instruments not designated as hedges (Note 12) are recorded at fair value, based on available market
information.

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



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

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

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

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

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

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

The Partnership enters into revenue arrangements where it sells customer's gas and/or NGLs and depending on the nature of the arrangement acts as the principal or agent. Revenue from
such sales is recognized gross where the Partnership acts as the Principal, underEITF 99-19, Reporting Revenue Gross as a Principal
versus Net as an Agent, as the Partnership takes title to the



gas and/or NGLs, has physical inventory risk and does not earn a fixed amount. Revenue is recognized net when the Partnership earns a fixed amount and does not take ownership of the gas and/or NGLs.

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



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

95

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



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.

MarkWest Hydrocarbon, Inc. ("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 Partnership's Board of Directors of the Partnership's General Partner is allocated equally.

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The Partnership is not a taxable entity for federal income tax purposes. As such, the Partnership does not directly pay federal income tax. The Partnership's
taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of income, is includable in the federal income tax returns of each partner. The
aggregate difference in the basis of the Partnership's net assets for financial and income tax purposes cannot be readily determined as the Partnership does not have access to information about each
partner's tax attributes related to the Partnership.

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

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



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



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

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

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The
following table sets forth the computation of basic and diluted earnings per limited partner unit, as adjusted for the February 28, 2007 two-for-one
unit split. The net income available to limited partners and the weighted average limited partner units outstanding have been adjusted for instruments considered common unit equivalents in 2006, 2005
and 2004:

|                                                                   |                                                                                                                                    | Year ended December 31, |       
|------------------------------------------------------------------ | ---------------------------------------------------------------------------------------------------------------------------------- | ----------------------- | ------
|
|
|Numerator for basic and diluted earnings per limited partner unit: |                                                                                                                                    |                         |       
|Net income                                                         |                                                                                                                                    | $                       | 70,084
|Less:                                                              |                                                                                                                                    |                         |       
|                                                                   | General partner's incentive distribution paid                                                                                      |                         |       
|                                                                   |                                                                                                                                    |                         |       
|Sub-total                                                          |                                                                                                                                    |                         | 58,783
|Plus:                                                              |                                                                                                                                    |                         |       
|                                                                   | Allocated depreciation expense attributable to the general partners contribution for construction of the Cobb Gas Extraction Plant |                         |       
|                                                                   | Participation plan allocation                                                                                                      |                         |       
|                                                                   |                                                                                                                                    |                         |       
|Net income before GP interest                                      |                                                                                                                                    |                         | 72,374
|Less:                                                              |                                                                                                                                    |                         |       
|                                                                   | General Partner's 2% interest                                                                                                      |                         |       
|                                                                   | Additional earnings allocated to general partners                                                                                  |                         |       
|                                                                   |                                                                                                                                    |                         |       
|Net income available to limited partners under EITF 03-6           |                                                                                                                                    | $                       | 70,927
|                                                                   |                                                                                                                                    |                         |       
|Denominator:                                                       |                                                                                                                                    |                         |       
|                                                                   | Denominator for basic earnings per limited partner unit-weighted average number of limited partner units                           |                         |       
|Effect of dilutive securities:                                     |                                                                                                                                    |                         |       
|                                                                   | Weighted-average of restricted units outstanding                                                                                   |                         |       
|                                                                   |                                                                                                                                    |                         |       
|                                                                   | Denominator for diluted earnings per limited partner unit-weighted average number of limited partner units                         |                         |       
|                                                                   |                                                                                                                                    |                         |       
|Basic net income per limited partner unit                          |                                                                                                                                    | $                       | 2.45  
|                                                                   |                                                                                                                                    |                         |       
|Diluted net income per limited partner unit                        |                                                                                                                                    | $                       | 2.44  
|                                                                   |                                                                                                                                    |                         |       



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

98

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and
principal-only strips are not subject to the requirements of SFAS 133; (c) establishes a requirement to evaluate beneficial interests in securitized financial assets to
identify interests that are freestanding derivatives or hybrid financial instruments that contain an embedded derivative requiring bifurcation; (d) clarifies that concentrations of credit risk
in the form of subordination are not embedded derivatives; and, (e) eliminates restrictions on a qualifying special-purpose entity's ability to hold passive derivative financial instruments
that pertain to beneficial interests that are or contain a derivative financial instrument. The standard also requires presentation within the financial statements that identifies those hybrid
financial instruments for which the fair value election has been applied and information on the income statement impact of the changes in fair value of those instruments. The Partnership is required
to apply SFAS 155 to all financial instruments acquired, issued or subject to a remeasurement event beginning January 1, 2007, although early adoption is permitted as of the beginning of
an entity's fiscal year. We do not believe the adoption of SFAS 155 will have a material impact on the consolidated financial statements of the Partnership.

In
June 2006 the FASB issued Interpretation No. 48,Accounting for Uncertainty in Income Taxes("FIN 48"). The
interpretation clarifies the accounting for uncertainty in income taxes recognized in a company's financial statements in accordance with Statement of Financial Accounting Standards
No. 109,Accounting for Income Taxes. Specifically, the pronouncement prescribes a "more likely than not" recognition threshold and a measurement
attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related
derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. The interpretation is effective for fiscal years beginning
after December 15, 2006. The Partnership is currently evaluating the potential impact of FIN 48 on the consolidated financial statements.

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

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

The Financial Accounting Standards Board ("FASB") has issued Statement No. 159,The Fair Value Option for Financial Assets and Financial
Liabilities, which permits an entity to measure certain financial assets and financial liabilities at fair value. The Statement's objective is to improve financial reporting by
allowing entities to mitigate volatility in reported earnings caused by the measurement of related

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



Certain prior period amounts have been reclassified to conform to the current period presentation. These reclassifications had no effect on net income.

3. Acquisitions



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 MMcfd. 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 25,400 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.

100

---





On March 31, 2005, the Partnership acquired a 50% non-operating membership interest in Starfish Pipeline Company, LLC, ("Starfish") from an
affiliate of Enterprise Products Partners L.P. for $41.7 million. The Partnership financed this by borrowing $40.0 million from its credit facility during the first quarter of 2005.
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 of the assets 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 gas processing plant assets,
located in East Texas, for approximately $240.7 million. The Partnership's consolidated financial statements include the results of operations of the Carthage gas processing plant from
July 30, 2004. The acquired assets consist of processing plants, gathering systems, a processing facility currently under construction and an NGL pipeline.

In
conjunction with the closing of the acquisition, the Partnership completed a private offering of 1,304,438 common units, at $34.50 per unit, representing approximately
$45.0 million in proceeds after transaction costs of approximately $0.9 million and including a contribution from the general partner of $0.9 million to maintain its ownership
interest. In addition, the Partnership amended and restated the credit facility, increasing the maximum lending limit from $140.0 million to $315.0 million. The credit facility included
a $265.0 million revolving facility and a $50.0 million term loan facility.



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

101

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

|                                 |                               |         |   |        |        | 2004 |        
|-------------------------------- | ----------------------------- | ------- | - | ------ | ------ | ---- | -------
|
|
|
|Acquisition Costs:               |                               |         |   |        |        |      |        
|                                 | Cash consideration            |         | $ | 15,000 |        | $    | 396,836
|                                 | Direct acquisition costs      |         |   |       |        |      | 2,009  
|                                 |                               |         |   |        |        |      |        
|                                 |                               | Totals: |   | $      | 15,000 |      | $      
|                                 |                               |         |   |        |        |      |        
|Allocation of acquisition costs: |                               |         |   |        |        |      |        
|                                 | Current assets                |         | $ |       |        | $    | 111,679
|                                 | Customer contracts            |         |   | 12,630 |        |      | 194,650
|                                 | Property, plant and equipment |         |   | 2,370  |        |      | 162,859
|                                 | Inventory                     |         |   |       |        |      |       
|                                 | Liabilities assumed           |         |   |       |        |      | (70,343
|                                 |                               |         |   |        |        |      |        
|                                 |                               | Totals: |   | $      | 15,000 |      | $      
|                                 |                               |         |   |        |        |      |        



The following table reflects the pro forma consolidated results of operations for the years ended December 31, 2005 and 2004, as though the Javelina and
Starfish acquisitions had occurred on January 1, 2005 and the East Texas acquisition had occurred on January 1, 2004. The unaudited pro forma results of operations for the Hobbs and
Santa Fe 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 February 2007 unit split.

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

4. Significant Customers and Concentration of Credit Risk

For the years ended December 31, 2006, 2005 and 2004, revenues from MarkWest Hydrocarbon totaled $74 million, $65 million and
$60 million, representing 13%, 13% and 20% of consolidated

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Partnership
revenues, respectively. Sales to MarkWest Hydrocarbon are made primarily from the Appalachia segment. As of December 31, 2006 and 2005 the Partnership had $4.7 million and
$7.9 million, respectively, of accounts receivable from MarkWest Hydrocarbon.

For
the year ended December 31, 2006 revenues from Targa Resources Partners, L.P. ("Targa") totaled $76 million, representing 13% of consolidated Partnership revenues.
Sales to Targa are made primarily from the East Texas segment. As of December 31, 2006 the Partnership had $3.0 million of accounts receivable from Targa.

For
the year ended December 31, 2006 revenues from ONEOK, Inc. ("ONEOK") totaled $63 million, representing 11% of consolidated Partnership revenues. Sales to ONEOK
are made primarily from the Oklahoma segment. As of December 31, 2006 the Partnership had no receivables from ONEOK.

For
the years ended December 31, 2005 and 2004 revenues from one other customer totaled $67 million and $60 million, representing 14% and 20% of consolidated
Partnership revenues, respectively. Sales to this customer were made primarily from the Oklahoma segment. As of December 31, 2005 the Partnership had $5.5 million of accounts receivable
from this customer.

5. Receivables and Other Current Assets

Receivables consist of the following (in thousands):

December 31,2006

2005Trade, net

$
68,692

$
100,894Other


17,434


9,144Total receivables

$
86,126

$
110,038


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

December 31,2006

2005Customer margin deposits

$


$
2,600Prepaid fuel


1,215


3,614Risk management premium


1,009


Prepaid insurance


391


599Prepaid equipment rental


283


Prepaid other


149


48$
3,047

$
6,861


103

---







In the third and fourth quarter 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 changes in fair value of the contracts are recorded as an
unrealized gain or loss.

6. 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


19,113


19,070NGL transportation facilities


5,326


4,433Land, building and other equipment


16,871


10,987Construction-in-progress


41,942


41,491655,749


567,094Accumulated depreciation


(104,863
)

(74,133
)Total property, plant and equipment, net

$
550,886

$
492,961


The
Partnership capitalizes interest on major projects during construction. For the years ended December 31, 2006 and 2005, the Partnership 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 $21.6 million.

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7. Intangible Assets

The Partnership'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 |                  
|Javelina   |        |                   | 195,137 |                  
|Oklahoma   |        |                   | 12,630  |                  
|Other      |        |                   |        |                  
|           |        |                   |         |                  
|           | Total: |                   | $       | 373,146          
|           |        |                   |         |                  

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

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

Year ending December 31:2007

$
16,7052008


16,7052009


16,7052010


16,7052011


16,705Thereafter


260,541Total

$
344,066


8. Other Long-Term Assets

Other long-term assets consist of the following (in thousands):

December 31,2006

2005Risk management premiums

$
717

$
Other


326


326$
1,043

$
326




In the third and fourth quarter 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

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contracts
are recorded as derivative instruments, so changes in fair value of the contracts are recorded as an unrealized gain or loss.

9. Accrued Liabilities

Accrued liabilities consist of the following (in thousands):

Year ended December 31,2006

2005Product and operations

$
8,653

$
5,967Customer obligations


203


3,380Professional services


1,133


1,736Taxes (other than income tax)


3,118


2,183Interest


13,935


3,233Javelina working capital adjustment





5,402Starfish contribution





1,486Construction in progress


10,866


2,652Deferred income


167


223Deferred lease obligation


2,344


Phantom unit liability


2,007


958Other


829


272Total accrued liabilities

$
43,255

$
27,492


10. Asset Retirement Obligation

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

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

Asset retirement obligation as of December 31, 2004

$
840Accrued liabilities


553Accretion expense


159Liabilities settled


(450
)Asset retirement obligation as of December 31, 2005


1,102Accrued liabilities


64Accretion expense


102Liabilities settled


Asset retirement obligation as of December 31, 2006

$
1,268


106

---



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

11. Debt

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

December 31,2006

2005Term loan, 8.75% interest, retired October 2006

$


$
365,000Revolving facility, 8.75% interest, due December 2010


30,000


14,000Senior 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


604,000Less: obligations due in one year





(2,738
)Total long-term debt

$
526,865

$
601,262




In July 2006 MarkWest Energy Partners, L.P. 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 Partnership 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. The Issuers have no assets or operations independent of this debt and their investments in guarantor subsidiaries. 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. Limitations under the indenture 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

107

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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.

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 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, when the exchange offer was completed.



In October 2004 MarkWest Energy Partners, L.P. and its wholly owned subsidiary, MarkWest Energy Finance Corporation (the "Issuers"),
co-issued $225.0 million in senior notes at a fixed rate of 6.875%, payable semi-annually in arrears on May 1 and November 1, and commencing on
May 1, 2005 (the "2014 Senior Notes"). 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. The notes are
senior unsecured obligations equal in right of payment with all of the Partnership's existing and future senior debt. The senior notes are senior in right of payment to all of the Partnership's future
subordinated debt but effectively junior in right of payment to its secured debt to the extent of the assets securing the debt, including the Partnership's obligations in respect of its Partnership
Credit Facility. The proceeds from these notes were used to pay down the Partnership's outstanding debt under its credit facility. The Issuers have no assets or operations independent of this debt and
their investments in guarantor subsidiaries. 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 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 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

108

---



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.

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. (the "Operating Company"), 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. In July 2006, using proceeds from debt and equity offerings, the Partnership
permanently reduced the borrowing capacity of the term loan to $45.9 million. In October 2006 the Partnership retired the remaining $45.9 million outstanding on the term loan
using a portion of the proceeds from the 2016 senior notes (see Note 16). 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
outstanding borrowing under the Partnership Credit Facility was 7.2%.

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

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



109

---





Both
the total debt and senior debt ratios contain adjustment clauses providing for greater flexibility during any Acquisition Adjustment Period.

These covenants are used to calculate the available borrowing capacity on a quarterly basis. The Partnership incurs a commitment fee on the unused portion of the credit facility at a
rate between 30.0 and 50.0 basis points based upon the ratio of Consolidated Senior Debt (as defined in the Partnership Credit Facility) to Consolidated EBITDA (as defined in the Partnership Credit
Facility. The revolver portion of the facility matures on December 29, 2010. The Partnership's Credit Facility also contains provisions requiring prepayments from certain Net Cash Proceeds (as
defined in the Partnership Credit Facility) received from certain triggering sales that have not been reinvested within one hundred eighty days. The Javelina Acquisition (see Note 3) was funded
through the fourth amended and restated credit agreement, which provided for a maximum lending limit of $500.0 million for a term of one year and was comprised of a revolving facility of
$100.0 million and a $400.0 million term loan. The fourth amended and restated credit agreement had terms similar to the new credit facility. In the fourth quarter of 2005 the
Partnership completed two private placement offerings to repay a portion of the borrowed funds. The Partnership was in compliance with all covenants as of December 31, 2006.

In
October 2004 the Operating Company, coincident with the issuance of the 2014 Senior Notes discussed below, entered into the third amended and restated credit agreement ("Old
Credit Facility"), which provided for a maximum lending limit of $200.0 million for a term of five years. The Old Credit Facility included a revolving facility of $200.0 million. The
borrowings under the Old Credit Facility carried interest at a variable rate based on one of two indices that included either (i) LIBOR plus an applicable margin, which was fixed at a rate of
2.75% for the first two quarters following the closing of the credit facility, or (ii) Base Rate (as defined for any day, a fluctuating rate per annum equal to the higher of (a) the
Federal Funds Rate plus 1/2of 1% or (b) the rate of interest in effect for such day as publicly announced from time to time by the administrative agent of the debt as its "prime
rate") plus an applicable margin, which margin is fixed at a rate of 2.00% for the first two quarters following the closing of the credit facility. After that period the applicable margin adjusted
quarterly based on the ratio of funded debt to EBITDA (as defined in the credit agreement).

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

Year ending December 31:2007

$
2008


2009


2010


30,0002011


Thereafter


500,000Total

$
530,000


110

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12. Derivative Financial Instruments



The Partnership utilizes a combination of fixed-price forward contracts, fixed-for-floating price swaps and options available in the
over-the-counter ("OTC") market, and futures contracts traded on the New York Mercantile Exchange ("NYMEX"). The Partnership enters into OTC swaps with financial institutions
and other energy company counterparties. Management conducts a standard credit review on counterparties and has agreements containing collateral requirements where deemed necessary. The Partnership
uses standardized agreements that allow for offset of positive and negative exposures. Some of the agreements may require a margin deposit.

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

The
Partnership has a committee comprised of the senior management team that oversees all of the risk management activity and use of derivative instruments.

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).

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 we largely expect our realized derivative gains and losses to be offset by increases or decreases in the value of
our physical sales, we will experience volatility in reported earnings due to the recording of unrealized gains and losses on our derivative positions that will have no offset. The volatility in any
given period related to unrealized gains or losses can be significant to the overall results of the Partnership, however, we ultimately expect those gains and losses to be offset when they become
realized.

111

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

Current asset (liability) mark-to-market positions (in thousands, except Fixed Price):

Fixed Swaps(1)

Contract Period

Fixed Price(4)



Fair ValueCrude390 Bbl/d

Jan-Dec 2007

$
68.46



$
473Crude600 Bbl/d

Jan-Dec 2007


64.77




(58
)Ethane50,000 Gal/d

Jan-Mar 2007


0.78




736$
1,151


Basis Swaps

Contract Period





Fair ValueNatural Gas14,000 MMBtu/d

Jan-Oct 2007





$
(33
)


Options (puts)(2)

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(3)

Contract Period

Floor(4)

Cap(4)

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


$
2,995Total current asset (liability) mark-to-market positions

$
4,120


112

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

Collars(3)

Contract Period

Floor(4)

Cap(4)

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
)$
1,397Total non-current asset (liability) mark-to-market positions

$
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

$
Current liability


91


728Non-current asset


2,759


Non-current liability


1,362





113

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13. Incentive Compensation Plans

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

Year ended December 31,2006

2005

2004MarkWest EnergyRestricted units

$
1,686

$
1,076

$
1,065MarkWest HydrocarbonGeneral partner interests


13,463


2,038


2,133Participation plan subordinated units


22


17


144Total compensation cost

$
15,171

$
3,131

$
3,342


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
total compensation expense not yet recognized as of December 31, 2006, related to non-vested restricted units is $1.8 million, with a weighted-average
remaining vesting period of 1.8 years. The actual compensation expense recognized may differ as expense under liability awards is affected by changes in the fair value of the units.



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.

Under
SFAS No. 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.

Restricted Units.A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit upon the vesting
of the phantom unit or, at the discretion of the Compensation Committee, cash equivalent to the value of a common unit. The restricted units vest over a service period of three to four years, although
vesting for certain awards accelerates 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.

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

Number of Units

Weighted-average
Grant-date Fair ValueNonvested at January 1, 2004

68,992

$
13.73Granted

55,800


21.01Vested

(54,906
)

12.73Forfeited

(10,886
)

18.62Nonvested at December 31, 2004

59,000


20.65Granted

40,278


24.74Vested

(18,200
)

18.95Forfeited

(3,350
)

21.25Nonvested at December 31, 2005

77,728


23.14Granted

81,886


24.35Vested

(26,986
)

22.25Forfeited

(7,428
)

22.75Nonvested at December 31, 2006

125,200


24.14


|                                                                                                                   |  | 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 and 2005, the Partnership received no proceeds for issuing restricted units, and there were no cash settlements. In 2004, 310
restricted units, at the Partnership's option were redeemed for cash.

Unit Options.The Compensation Committee has the authority to make grants of common units 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 us, the general partner, MarkWest Hydrocarbon or upon the achievement of specified financial objectives.

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

115

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MarkWest Hydrocarbon 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 vesting period or 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. At September 30, 2006, there were no subordinated
units available under this Participation Plan.

The
subordinated units are sold without any restrictions on transfer. Compensation expense is based on changes in the market value of the subordinated units. No subordinated units were
sold to employees or directors in 2006 or 2005. MarkWest Hydrocarbon reacquired no subordinated units in 2006 or 2005.

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 Mr. Semple'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.

As
the formula used to determine the sale and buy-back price is not based on an independent third-party valuation, coupled with the attributes of the
put-and-call provisions, these transactions are considered compensatory arrangements, similar to a stock appreciation right. 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

116

---



market
value of the Partnership's common units and the current quarterly distributions paid. On October 13, 2006, the Company completed the repurchase of a 0.5% interest in the general partner.

14. Texas Margin Tax

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

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

15. Employee Benefit Plan

All employees dedicated to, or otherwise principally supporting the Partnership are employees of MarkWest Hydrocarbon, and substantially all of these employees
are participants in MarkWest
Hydrocarbon's defined contribution benefit plan. Costs related to this plan allocated to the Partnership were $0.9 million, $0.9 million and $0.2 million for the years ended
December 31, 2006, 2005 and 2004, respectively. The plan is discretionary, with annual contributions determined by MarkWest Hydrocarbon's Board of Directors.

16. Partners' Capital

As of December 31, 2006, partners' capital consists of 31,166,138 common limited partner units, representing a 94% partnership interest; 1,200,000
subordinated limited partner units, representing a 4% partnership interest; and a 2% general partner interest. MarkWest Hydrocarbon and its subsidiaries, in the aggregate, own a
17% interest in the Partnership consisting of 3,738,992 common limited partner units, 1,200,000 subordinated limited partner units and a 2% general partner interest.

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

The
Partnership has the ability to issue an unlimited number of units to fund immediately accretive acquisitions. An immediately accretive acquisition is one that, in the general
partner's good faith determination, would have resulted in an increase to the amount of operating surplus generated by the Partnership on a per-unit basis with respect to each of the four
most recently completed quarters on a pro forma basis. During 2006, 2005 and 2004, the Partnership consummated a total of five acquisitions, aggregating approximately $698.5 million, certain of
which were subsequently funded partially by equity offerings.

117

---



The
Partnership Agreement contains specific provisions for the allocation of net income and losses to each of the partners for purposes of maintaining their respective partner capital
accounts. Per the Partnership Agreement, compensation expense under the Participation Plan allocated to the Partnership by MarkWest Hydrocarbon is allocated entirely to the general partner (See
Note 2).



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



During the Subordination Period (as defined), before any distributions of available cash from operating surplus may be made on the subordinated units, the common
unitholders have the right to receive distributions of available cash in an amount equal to the minimum quarterly distribution of $0.50 per quarter per common unit, plus any arrearages in the payment
of the minimum quarterly distribution on the common units from prior quarters.

The
Subordination Period ends on the first day of any quarter beginning after June 30, 2009, when certain financial tests are met. Additionally, a portion of the subordinated
units may convert earlier into common units on a one-for-one basis if additional financial tests or financial goals are met. The earliest possible date by which some of the
subordinated units could be converted into common units was June 30, 2005. As a result of achieving those goals in May 2005, 1,200,000 subordinated units were converted into common units
on August 15, 2005, November 15, 2005, August 15, 2006, and November 15, 2006. When the subordination period ends, any remaining subordinated units will convert into common
units on a one-for-one basis, and the common unit holders will no longer be entitled to arrearages.



During the subordination period, the quarterly distributions of available cash will be made in the following manner:



118

---







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





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

If
for any quarter:



then,
the Partnership will distribute any additional available cash for that quarter among the unitholders and the general partner in the manner described in the following paragraph.

The
general partner is entitled to incentive distributions if the quarterly distribution amount exceeds the target levels specified below:

|                               |  |                            |  | Marginal Percentage Interest in Distributions |  
|------------------------------ |  | -------------------------- |  | --------------------------------------------- | -
|
|Minimum Quarterly Distribution |  | $0.25                      |  | 98                                            | %
|First Target Distribution      |  | up to $0.275               |  | 98                                            | %
|Second Target Distribution     |  | above $0.275 up to $0.3125 |  | 85                                            | %
|Third Target Distribution      |  | above $0.3125 up to $0.375 |  | 75                                            | %
|Thereafter                     |  | above $0.375               |  | 50                                            | %

119

---





In
each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate payment of any cumulative minimum quarterly
distribution. The Partnership is currently distributing at a rate in excess of $0.375 per unit.

The
quarterly cash distributions applicable to 2006, 2005 and 2004, were as follows:

|Quarter Ended      |  | Record Date      |  | Payment Date      |  | Amount Per Unit
|------------------ |  | ---------------- |  | ----------------- |  | ---------------
|December 31, 2006  |  | February 8, 2007 |  | February 14, 2007 |  | $              
|September 30, 2006 |  | November 3, 2006 |  | November 14, 2006 |  | $              
|June 30, 2006      |  | August 7, 2006   |  | August 14, 2006   |  | $              
|March 31, 2006     |  | May 5, 2006      |  | May 15, 2006      |  | $              
|December 31, 2005  |  | February 8, 2006 |  | February 14, 2006 |  | $              
|September 30, 2005 |  | November 8, 2005 |  | November 14, 2005 |  | $              
|June 30, 2005      |  | August 9, 2005   |  | August 15, 2005   |  | $              
|March 31, 2005     |  | May 10, 2005     |  | May 16, 2005      |  | $              
|December 31, 2004  |  | February 2, 2005 |  | February 11, 2005 |  | $              
|September 30, 2004 |  | November 3, 2004 |  | November 12, 2004 |  | $              
|June 30, 2004      |  | July 30, 2004    |  | August 13, 2004   |  | $              
|March 31, 2004     |  | April 30, 2004   |  | May 14, 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 15,603,257 Common units and
600,000 Subordinated units Partnership units. For all periods presented, all references to the number of units and per unit net income and distribution amounts included in this report have been
adjusted to give the effect for the unit split.



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

120

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proceeds.
The net proceeds of $24.9 million, and the $0.5 million contributed by the general partner to maintain its 2% interest, resulted in total net proceeds associated with the
private placement of $25.4 million.



The Partnership sold 3,288,130 common units to certain accredited investors at $22.105 per common unit, for gross proceeds of $72.7 million. Offering costs
of $0.1 million reduced the aggregate gross proceeds of $72.7 million to $72.6 million of net proceeds. The net proceeds of $72.6 million, and the $1.5 million
contributed by the general partner to maintain its 2% interest, resulted in total net proceeds associated with the private placement of $74.1 million.



The Partnership priced its offering of 4,314,790 common units at $21.705 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 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.

17. Commitments and Contingencies



In the ordinary course of its business MarkWest Energy Partners is subject to a variety of risks and disputes normal to its business and as a party to various
legal proceedings. We maintain insurance

121

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policies
in amounts and with coverage and deductibles as we believe are reasonable and prudent. However, we cannot assure either that the insurance companies will promptly honor their policy
obligations or that the coverage or levels of insurance will be adequate to protect us from all material expenses related to future claims for property loss or business interruption to the
Partnership; or for third-party claims of personal and property damage; or that the coverages or levels of insurance it currently has will be available in the future at economical prices.

In
2005 MarkWest Hydrocarbon, the Partnership, several of its affiliates, and an unrelated co-defendant, were served with three lawsuits, which in 2006 were
consolidated into a single action 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
Partnership notified its general liability insurance carriers of the incident and the lawsuits in a timely manner and coordinated its legal defense with the insurers. As of
February 1, 2007, all of the claims in the litigation were fully settled, with the MarkWest's insurance policies and its co-defendant and its separate insurance policy, 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 Partnership for certain expenses related to the
pipeline incident. These include the Partnership's internal expenses and costs incurred for damage to, and loss of use of the pipeline, equipment and products; the extra transportation costs incurred
for transporting the liquids while the pipeline was out of service; the reduced volumes of liquids that could be processed; and the costs of complying with the OPS Corrective Action Order (hydrostatic
testing, repair/replacement and other pipeline integrity assurance measures). These expenses and costs have been expensed as incurred and any potential recovery from the All-Risks Property
and Business Interruption insurance carriers will be treated as "other income" if and when it is received. Following initial discovery, the Partnership was granted leave of the Court to

122

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amend
its complaint to add a bad faith claim, and a claim for punitive damages. The Partnership has not provided for a receivable for any of the claims in this action because of the uncertainty as to
whether and how much the Partnership will ultimately recover under the policies. Discovery in the action is continuing. The Partnership has also asserted that the cost of pipeline testing, replacement
and repair are subject to an equitable sharing arrangement with the pipeline owner, pursuant to the terms of the pipeline lease agreement.

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

With
regard to the Partnership's Javelina facility, MarkWest Javelina is a party with numerous other defendants to several lawsuits brought by various plaintiffs who had residences or
businesses located near the Corpus Christi industrial area, an area which included the Javelina gas processing plant, and several petroleum, petrochemical and metal processing and refining operations.
These suits,Victor Huff v. ASARCO Incorporated, et al. (Cause No. 98-01057-F, 214th Judicial Dist. Ct.,
County of Nueces, Texas, original petition filed in March 3, 1998);Hipolito Gonzales et al. v. ASARCO Incorporated, et al., (Cause
No. 98-1055-F, 214th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in 1998);Jason and Dianne Gutierrez,
individually and as representative of the estate of Sarina Galan Gutierrez(Cause No. 05-2470-A, 28th Judicial District, severed
May 18, 2005, from 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 Partnership is a party to various other legal actions. While it is not possible to predict the outcome of the legal actions with certainty,
management is of the opinion that appropriate provision and accruals for potential losses associated with all legal actions have been made in the financial statements. In the opinion of management,
none of these actions, either individually or in the aggregate, will have a material adverse effect on the Partnership's financial condition, liquidity or results of operations.

123

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The Partnership has various non-cancelable operating lease agreements for equipment expiring at various times through fiscal year 2015. Annual rent
expense under these operating leases was $8.0 million, $5.9 million and $3.3 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 ending December 31,2007

$
8,8962008


5,0122009


2,4642010


1,5832011


1,5952012 and thereafter


5,139$
24,689


18. Related Party Transactions

Affiliated revenues in the consolidated statements of operations consist of service fees and NGL product sales. Concurrent with the closing of the IPO, the
Partnership entered into several contracts with MarkWest Hydrocarbon. Specifically, the Partnership entered into:



Under
the Services Agreement with MarkWest Hydrocarbon, MarkWest Hydrocarbon continues to provide centralized corporate functions such as accounting, treasury, engineering, information

124

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technology,
insurance and other services. The Partnership reimburses MarkWest Hydrocarbon monthly for the selling, general and administrative expenses. For the years ended December 31, 2006,
2005 and 2004, MarkWest Hydrocarbon charged approximately $18.0 million, $10.9 million and $8.7 million, respectively, for these expenses.

The
Partnership also reimburses MarkWest Hydrocarbon for the salaries and employee benefits, such as 401(k) and health insurance, of plant operating personnel as well as other direct
operating expenses. For the years ended December 31, 2006, 2005 and 2004, these costs totaled $18.1 million, $14.6 million and $9.1 million, respectively, and are included
in facility expenses. The Partnership has no employees.

In
Michigan, the Partnership assumed the Midstream Business's existing third-party contracts. As a result, the Partnership gathers and processes gas directly for those third parties. The
Partnership receives 100% of all fees and percent-of-proceeds consideration for the first 10,000 Mcf/d gathered in Michigan. MarkWest Hydrocarbon retains a 70% net profit
interest in the gathering and processing income earned on Michigan pipeline throughput in excess of 10,000 Mcf/d, calculated quarterly. For years ended December 31, 2006, 2005 and 2004,
MarkWest Hydrocarbon's net profit interest was $0.0 million, $0.0 million and $0.5 million, respectively, which amounts are included in facility expenses.

19. Subsequent Event

On December 7, 2006, the Partnership filed a Form S-4 exchange offer registration statement related to the Senior Notes (see
Note 11). The registration became effective January 23, 2007. An interest penalty was assessed at 0.5% between the dates of January 8, 2007 and February 26, 2007.

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.

125

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20. Segment Information

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

|Segment         |  | Related Legal Entity                                                                                                                                      |  | Products and services                                     
|--------------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----------------------------------------------------------
|Southwest       |  |                                                                                                                                                           |  |                                                           
|East Texas      |  | MarkWest Energy East Texas Gas Company, L.P.
MarkWest Pipeline Company, L.P.                                                                              |  | Gathering, processing, pipeline, fractionation and storage
|Oklahoma        |  | MarkWest Western Oklahoma Gas Company, L.L.C.
Santa Fe Gathering, L.L.C                                                                                   |  | Gathering and processing                                  
|Other Southwest |  | MarkWest Power Tex L.P.
MarkWest Pinnacle L.P.
MarkWest PNG Utility L.P.
MarkWest Texas PNG Utility L.P.
MarkWest Blackhawk L.P.
MarkWest New Mexico L.P. |  | Gathering and pipeline                                    
|Gulf Coast      |  |                                                                                                                                                           |  |                                                           
|Gulf Coast      |  | MarkWest Javelina Company
MarkWest Javelina Pipeline Company
MarkWest Javelina Pipeline Holding Company, L.P.
MarkWest Javelina Holding Company, L.P.     |  | Gathering, processing and pipeline                        
|Northeast       |  |                                                                                                                                                           |  |                                                           
|Appalachia      |  | MarkWest Energy Appalachia, L.L.C.                                                                                                                        |  | Processing, pipelines, fractionation and storage          
|Michigan        |  | Basin Pipeline, L.L.C.
West Shore Processing Company, L.L.C.
Matrex, LLC
MarkWest Michigan Pipeline Company, L.L.C.                                       |  | Gathering, processing and crude oil transportation        

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

126

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The
table below presents information about operating income for the reported segments for the three years ended December 31, 2006, 2005 and 2004 (in thousands).

Year ended December 31, 2006:

|                                                                                                                               |                      | East
Texas |         | Oklahoma |   | Other
Southwest |         | Appalachia |        | Michigan |   | Gulf Coast |        | Total
|------------------------------------------------------------------------------------------------------------------------------ | -------------------- | ---------- | ------- | -------- | - | --------------- | ------- | ---------- | ------ | -------- | - | ---------- | ------ | -----
|Revenues:                                                                                                                      |                      |            |         |          |   |                 |         |            |        |          |   |            |        |      
|                                                                                                                               | Unaffiliated parties |            | $       | 174,279  |   | $               | 207,510 |            | $      | 84,595   |   | $          | 2,027  |      
|                                                                                                                               | Affiliated parties   |            |         |         |   |                 |        |            |        |         |   |            | 73,636 |      
|                                                                                                                               |                      |            |         |          |   |                 |         |            |        |          |   |            |        |      
|Total Revenues                                                                                                                 |                      |            | 174,279 |          |   | 207,510         |         |            | 84,595 |          |   | 75,663     |        |      
|Purchased product costs                                                                                                        |                      |            | 91,637  |          |   | 170,168         |         |            | 67,349 |          |   | 43,648     |        |      
|Facility expenses                                                                                                              |                      |            | 15,683  |          |   | 7,883           |         |            | 5,638  |          |   | 13,997     |        |      
|Depreciation                                                                                                                   |                      |            | 7,783   |          |   | 3,007           |         |            | 4,100  |          |   | 3,573      |        |      
|Amortization                                                                                                                   |                      |            | 8,244   |          |   |                |         |            |       |          |   |           |        |      
|Accretion                                                                                                                      |                      |            | 44      |          |   | 26              |         |            | 20     |          |   | 12         |        |      
|                                                                                                                               |                      |            |         |          |   |                 |         |            |        |          |   |            |        |      
|Operating income (loss) before selling, general and administrative expenses and depreciation expense not allocated to segments |                      | $          | 50,888  |          | $ | 26,426          |         | $          | 7,488  |          | $ | 14,433     |        | $    
|                                                                                                                               |                      |            |         |          |   |                 |         |            |        |          |   |            |        |      
|Capital expenditures                                                                                                           |                      | $          | 23,508  |          | $ | 34,114          |         | $          | 12,669 |          | $ | 2,315      |        | $    
|Capital expenditures not allocated to segments                                                                                 |                      |            |         |          |   |                 |         |            |        |          |   |            |        |      
|                                                                                                                               |                      |            |         |          |   |                 |         |            |        |          |   |            |        |      
|Capital expenditures                                                                                                           |                      |            |         |          |   |                 |         |            |        |          |   |            |        |      
|                                                                                                                               |                      |            |         |          |   |                 |         |            |        |          |   |            |        |      
|Assets attributable to segments                                                                                                |                      | $          | 331,485 |          | $ | 126,421         |         | $          | 72,068 |          | $ | 51,020     |        | $    
|Investment in Starfish                                                                                                         |                      |            |         |          |   |                 |         |            |        |          |   |            |        |      
|Fair value of derivative instruments                                                                                           |                      |            |         |          |   |                 |         |            |        |          |   |            |        |      
|Leasehold Improvements(1)                                                                                                      |                      |            |         |          |   |                 |         |            |        |          |   |            |        |      
|                                                                                                                               |                      |            |         |          |   |                 |         |            |        |          |   |            |        |      
|Total Assets                                                                                                                   |                      |            |         |          |   |                 |         |            |        |          |   |            |        |      
|                                                                                                                               |                      |            |         |          |   |                 |         |            |        |          |   |            |        |      

---

127

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Year ended December 31, 2005:

|                                                                            |                      | East
Texas |         | Oklahoma |   | Other
Southwest |         | Appalachia |         | Michigan |   | Gulf Coast |        | Total
|--------------------------------------------------------------------------- | -------------------- | ---------- | ------- | -------- | - | --------------- | ------- | ---------- | ------- | -------- | - | ---------- | ------ | -----
|Revenues:                                                                   |                      |            |         |          |   |                 |         |            |         |          |   |            |        |      
|                                                                            | Unaffiliated parties |            | $       | 128,267  |   | $               | 214,043 |            | $       | 107,712  |   | $          | 1,686  |      
|                                                                            | Affiliated parties   |            |         |         |   |                 |        |            |         |         |   |            | 64,922 |      
|                                                                            |                      |            |         |          |   |                 |         |            |         |          |   |            |        |      
|Total Revenues                                                              |                      |            | 128,267 |          |   | 214,043         |         |            | 107,712 |          |   | 66,608     |        |      
|Purchased product costs                                                     |                      |            | 81,030  |          |   | 193,787         |         |            | 92,602  |          |   | 38,435     |        |      
|Facility expenses                                                           |                      |            | 10,463  |          |   | 4,927           |         |            | 4,990   |          |   | 19,360     |        |      
|Depreciation                                                                |                      |            | 4,836   |          |   | 2,385           |         |            | 3,383   |          |   | 3,187      |        |      
|Amortization                                                                |                      |            | 8,293   |          |   |                |         |            | 68      |          |   |           |        |      
|Accretion                                                                   |                      |            | 33      |          |   | 63              |         |            | 22      |          |   | 41         |        |      
|                                                                            |                      |            |         |          |   |                 |         |            |         |          |   |            |        |      
|Operating income (loss) before selling, general and administrative expenses |                      | $          | 23,612  |          | $ | 12,881          |         | $          | 6,647   |          | $ | 5,585      |        | $    
|                                                                            |                      |            |         |          |   |                 |         |            |         |          |   |            |        |      
|Capital expenditures                                                        |                      | $          | 46,088  |          | $ | 11,937          |         | $          | 7,765   |          | $ | 4,611      |        | $    
|Assets attributable to segments                                             |                      | $          | 324,231 |          | $ | 75,576          |         | $          | 59,178  |          | $ | 55,436     |        | $    
|Investment in Starfish                                                      |                      |            |         |          |   |                 |         |            |         |          |   |            |        |      
|                                                                            |                      |            |         |          |   |                 |         |            |         |          |   |            |        |      
|Total Assets                                                                |                      |            |         |          |   |                 |         |            |         |          |   |            |        |      
|                                                                            |                      |            |         |          |   |                 |         |            |         |          |   |            |        |      

Year ended December 31, 2004:

|                                                                     |                      | East
Texas |         | Oklahoma |   | Other
Southwest |         | Appalachia |        | Michigan |   | Gulf Coast |        | Total
|-------------------------------------------------------------------- | -------------------- | ---------- | ------- | -------- | - | --------------- | ------- | ---------- | ------ | -------- | - | ---------- | ------ | -----
|Revenues:                                                            |                      |            |         |          |   |                 |         |            |        |          |   |            |        |      
|                                                                     | Unaffiliated parties |            | $       | 39,737   |   | $               | 133,889 |            | $      | 70,044   |   | $          | 1,610  |      
|                                                                     | Affiliated parties   |            |         |         |   |                 |        |            |        |         |   |            | 59,026 |      
|                                                                     |                      |            |         |          |   |                 |         |            |        |          |   |            |        |      
|Total Revenues                                                       |                      |            | 39,737  |          |   | 133,889         |         |            | 70,044 |          |   | 60,636     |        |      
|Purchased product costs                                              |                      |            | 21,474  |          |   | 118,325         |         |            | 55,519 |          |   | 30,031     |        |      
|Facility expenses                                                    |                      |            | 3,229   |          |   | 3,659           |         |            | 3,694  |          |   | 13,444     |        |      
|Depreciation                                                         |                      |            | 1,489   |          |   | 2,059           |         |            | 3,099  |          |   | 4,329      |        |      
|Amortization                                                         |                      |            | 3,446   |          |   |                |         |            | 194    |          |   |           |        |      
|Impairment                                                           |                      |            |        |          |   |                |         |            |       |          |   | 130        |        |      
|Accretion                                                            |                      |            | 13      |          |   |                |         |            |       |          |   |           |        |      
|                                                                     |                      |            |         |          |   |                 |         |            |        |          |   |            |        |      
|Operating income before selling, general and administrative expenses |                      | $          | 10,086  |          | $ | 9,846           |         | $          | 7,538  |          | $ | 12,702     |        | $    
|                                                                     |                      |            |         |          |   |                 |         |            |        |          |   |            |        |      
|Capital expenditures                                                 |                      | $          | 19,343  |          | $ | 2,917           |         | $          | 3,899  |          | $ | 2,856      |        | $    
|Assets attributable to segments                                      |                      | $          | 298,451 |          | $ | 64,433          |         | $          | 59,071 |          | $ | 51,088     |        | $    

128

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

|                                                                                                                                                              |  | Year ended December 31, |        
|------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----------------------- | -------
|
|Total segment revenue                                                                                                                                         |  | $                       | 624,279
|Derivative gain (loss) not allocated to segments                                                                                                              |  |                         | 5,632  
|                                                                                                                                                              |  |                         |        
|Total revenue                                                                                                                                                 |  | $                       | 629,911
|                                                                                                                                                              |  |                         |        
|Total segment operating income before derivative gain (loss), selling, general and administrative expenses and depreciation expense not allocated to segments |  | $                       | 141,803
|Derivative gain (loss) not allocated to segments                                                                                                              |  |                         | 5,632  
|Depreciation expense not allocated to segments                                                                                                                |  |                         | (15    
|Selling, general and administrative expenses not allocated to segments                                                                                        |  |                         | (44,185
|                                                                                                                                                              |  |                         |        
|Income (loss) from operations                                                                                                                                 |  |                         | 103,235
|Earnings (losses) from unconsolidated affiliates                                                                                                              |  |                         | 5,316  
|Interest income                                                                                                                                               |  |                         | 962    
|Interest expense                                                                                                                                              |  |                         | (40,666
|Amortization of deferred financing costs                                                                                                                      |  |                         | (9,094 
|Miscellaneous income                                                                                                                                          |  |                         | 11,100 
|                                                                                                                                                              |  |                         |        
|Income before Texas Margin Tax                                                                                                                                |  |                         | 70,853 
|Texas Margin Tax                                                                                                                                              |  |                         | (769   
|                                                                                                                                                              |  |                         |        
|Net income                                                                                                                                                    |  | $                       | 70,084 
|                                                                                                                                                              |  |                         |        

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21. Quarterly Results of Operations (Unaudited)

The following summarizes the Partnership's quarterly results of operations (in thousands):

|                                             |         | Three months ended
|-------------------------------------------- | ------- | ------------------
|
|
|Revenue                                      |         | $                 
|Income from operations                       |         |                   
|Net income                                   |         |                   
|Limited partner's share of net income (loss) |         |                   
|Net income per limited partner unit:         |         |                   
|                                             | Basic   |                   
|                                             | Diluted |                   

|                                             |         | Three months ended |       
|-------------------------------------------- | ------- | ------------------ | ------
|
|
|Revenue                                      |         | $                  | 98,747
|Income from operations                       |         | $                  | 8,451 
|Net income (loss)                            |         | $                  | 4,265 
|Limited partner's share of net income (loss) |         | $                  | 4,346 
|Net income (loss) per limited partner unit:  |         |                    |       
|                                             | Basic   |                    | $     
|                                             | Diluted |                    | $     

22. Valuation and Qualifying Accounts

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

December 31,2006

2005

2004Balance at beginning of period

$
151

$
211

$
80Charged to costs and expenses


118


42


211Other charges(1)


(151
)

(102
)

(80
)Balance at end of period

$
118

$
151

$
211




23. Restatement of Consolidated Financial Statements

Subsequent to the issuance of the Partnership's 2006 consolidated financial statements, the Partnership determined that certain revenue transactions in the 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 Partnership 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 Partnership has restated its consolidated financial statements for the years ended December 31, 2006 and 2005.

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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
|------------------------ |  | ---------------------------- | ------- | ----------------------------
|
|Unaffiliated revenues    |  | $                            | 496,684 |                             
|Revenues                 |  |                              | 575,952 |                             
|Purchased product costs  |  |                              | 322,278 |                             
|Total operating expenses |  |                              | 472,717 |                             

This restatement has the effect of increasing the amounts included in the revenue line item "Unaffiliated 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 partners' capital or the consolidated
balance sheets.

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ITEM 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

On September 20, 2005, the Partnership engaged Deloitte & Touche LLP as the Registrant's independent registered public accounting firm for the year
ending December 31, 2005, and to perform procedures related to the financial statements included in the Partnership's quarterly reports on Form 10-Q, beginning with the
quarter ended September 30, 2005. The Audit Committee made the decision to engage Deloitte & Touche and that decision was then approved, adopted and ratified by the Partnership's Board
of Directors. The Partnership 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 Partnership 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 Partnership's 2005 Form 10-K, material weaknesses existed in the Partnership'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

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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:



133

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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:



134

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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 Partnership 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.

135

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

Management of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in
Rule 13a-15(f) under the Exchange Act. The Partnership's internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America and
includes those policies and procedures that:



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 Partnership included in this Annual Report on
Form 10-K/A, has issued an attestation report on management's assessment of the effectiveness of the Partnership's internal control over financial reporting as of
December 31, 2006. The report, which expresses

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unqualified opinion on management's assessment and an adverse opinion on the effectiveness of the Partnership's 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 of
MarkWest Energy GP, L.L.C.
Denver, Colorado

We have audited management's assessment, included in the accompanying Management's Report on Internal Control Over Financial Reporting, that MarkWest Energy Partners, L.P. and subsidiaries (the
"Partnership") did not maintain effective internal control over financial reporting as of December 31, 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 Partnership's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over
financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Partnership's internal control over financial reporting based on
our audit.

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

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing
similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and
procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the



transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect
on the financial statements.

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

A material weakness is a 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 in our audit of the consolidated financial statements as of and for the year ended
December 31, 2006, of the Partnership and this report does not affect our report on such financial statements.

In our opinion, management's assessment that the Partnership did not maintain effective internal control over financial reporting as of December 31, 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 Partnership 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 Partnership and our report dated March 6, 2007 (November 2, 2007 as to the effects of the restatement discussed in Note 23) 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

Management of MarkWest Energy Partners, L.P.

MarkWest Energy GP, L.L.C., as our general partner, manages our operations and activities on our behalf. Our general partner is not elected by our unitholders and
will not be subject to reelection on a regular basis in the future. Unitholders do not directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to
our unitholders, although such duty is limited under our Partnership Agreement. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets),
except for indebtedness or other obligations that are made specifically non-recourse to it. Whenever possible, however, our general partner intends to incur indebtedness or other
obligations that are non-recourse.

Three
members of the board of directors of our general partner serve on a Conflicts Committee to review those matters that the board believes may involve conflicts of interest. The
Conflicts Committee determines if the resolution of the conflict of interest is fair and reasonable to us. Committee members may not be officers or employees of our general partner or directors,
officers or employees of its affiliates and must meet the independence standards to serve on an audit committee of a board of directors established by the American Stock Exchange, as well as certain
other requirements. Any matters approved by the Conflicts Committee are conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of
any duties it may owe us or our unitholders. The current members of the Conflicts Committee are Keith E. Bailey, Charles K. Dempster and William P. Nicoletti.

Three
members of the board of directors of our general partner serve on the Audit Committee that reviews our external financial reporting, recommends engagement of our independent
auditors and reviews procedures for internal auditing and the adequacy of our internal accounting controls. Three members of the board of directors of our general partner serve on the Compensation
Committee, which oversees compensation decisions for the officers of our general partner as well as the compensation plans described below under the headings "Non-Competition,
Non-Solicitation and Confidentiality Agreement and Severance Plan" and "Long-Term Incentive Plan," which is included herein by reference. The members of the Compensation and
Audit Committees for 2005 and 2006 were Keith E. Bailey, Charles K. Dempster and William P. Nicoletti.

Some
officers of our general partner spend a substantial amount of time managing the business and affairs of MarkWest Hydrocarbon and its other affiliates. These officers may face a
conflict regarding the allocation of their time between our business and the other business interests of MarkWest Hydrocarbon. Our general partner directs its officers to devote as much time to the
management of our business and affairs as is necessary for the proper conduct of our business and affairs.

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

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

|Name                 |  | Age |  | Position with our General Partner                    |  | Director Since
|-------------------- |  | --- |  | ---------------------------------------------------- |  | --------------
|John M. Fox          |  | 66  |  | Chairman of the Board of Directors                   |  | 2002          
|Keith E. Bailey      |  | 64  |  | Director                                             |  | 2005          
|Charles K. Dempster  |  | 64  |  | Director                                             |  | 2002          
|Donald C. Heppermann |  | 64  |  | Director                                             |  | 2002          
|William A. Kellstrom |  | 65  |  | Director                                             |  | 2002          
|William P. Nicoletti |  | 61  |  | Director                                             |  | 2002          
|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            
|Richard A. Ostberg   |  | 41  |  | Vice President, Risk and Compliance                  |  | NA            
|Andrew L. Schroeder  |  | 48  |  | Vice President, Finance and Treasurer                |  | NA            
|David L. Young       |  | 47  |  | Senior Vice President, Corporate Services            |  | 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.

Keith E. Baileyhas served as a member of the board of directors of our general partner since January 2005. Mr. Bailey was
formerly the Chairman, President and Chief Executive Officer of The Williams Companies, Inc. ("Williams"). Commencing in 1973, Mr. Bailey served in various capacities with Williams and
its subsidiaries, including President and Chairman of Williams Pipe Line, Chairman of Wiltel Communications, President of Williams Natural Gas, and Executive Vice President and Chief Financial Officer
of Williams. Also, Mr. Bailey served on the Williams board of directors from 1988 until his retirement in 2002, including eight years as Chairman. 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. He currently serves on the boards of directors of Apco Argentina Inc., Associated Electric &
Gas Insurance Services Limited (Aegis) and Integrys Energy Group Inc. Mr. Bailey holds a bachelor's degree in mechanical engineering from the Missouri School of Mines and Metallurgy.

Charles K. Dempsterhas served as a member of the board of directors of our general partner since December 2002.
Mr. Dempster has more than 30 years of experience in the natural gas and power industry. He held various management and executive positions with Enron Corporation and its predecessors
between 1969 and 1986, focusing on natural gas supply, transmission and distribution. From 1986 through 1992, Mr. Dempster served as President of Reliance Pipeline Company and Executive Vice
President of Nicor Oil and Gas Corporation, oil and natural gas midstream and exploration subsidiaries of Nicor Inc. in Chicago. In 1993, he was appointed President of Aquila Energy
Corporation, a wholly owned midstream, pipeline and energy-trading subsidiary of Utilicorp, Inc. Mr. Dempster retired in 2000 as Chairman and Chief Executive Officer of Aquila Energy
Company.

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Mr. Dempster
holds a bachelor's degree in civil engineering from the University of Houston and attended graduate business school at the University of Nebraska.

Donald C. 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. He also serves as Chairman
of the Finance
Committee. Prior to joining MarkWest Hydrocarbon and the general partner of MarkWest Energy, Mr. Heppermann was a private investor and career executive in the energy industry with
responsibilities in operations, finance, business development and strategic planning. From 1990 to 1997, Mr. Heppermann served as President and Chief Operating Officer for InterCoast Energy
Company, an unregulated subsidiary of Mid American Energy Company. From 1987 to 1990, Mr. Heppermann was Vice President of Finance for Pinnacle West Capital Corporation, the holding company for
Arizona Public Service Company. From 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.

William P. Nicolettihas served as a member of the Board of Directors of our general partner since its inception in May 2002.
Mr. Nicoletti is Managing Director of Nicoletti & Company Inc., a private banking firm formed in 1991. Previously, he was a Managing Director and head of Energy Investment Banking
for PaineWebber Incorporated and E.F Hutton & Company Inc. Mr. Nicoletti is a director and Chairman of the Audit Committee of Kestrel Heat LLC, the general partner of Star Gas
Partners, L.P. He is also a director of SPI Petroleum LLC. Mr. Nicoletti is a graduate of Seton Hall University and received an MBA from Columbia University Graduate School of Business.

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

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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 and
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 spent four years 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 & 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 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.

Richard A. Ostberg,Vice President Risk and Compliance, was appointed as the Vice President of Risk and Compliance of MarkWest Hydrocarbon
and the general partner of MarkWest Energy in

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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, Treasurer and Assistant Secretary, has served in these positions 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.

David L. Young,Senior Vice President, Corporate Services, was appointed to that position in of 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.

Audit Committee Financial Expert

Each of the individuals serving on our Audit Committee satisfies the standards for independence of the AMEX and the SEC as they relate to audit committees. Our
board of directors believes each of the members of the Audit Committee is financially literate. In addition, our board of directors has determined that Mr. Bailey is financially sophisticated
and qualifies as an "audit committee financial expert" within the meaning of the regulations of the SEC.

Audit Committee Pre-Approval Policy

The Audit Committee pre-approves all audit and permissible non-audit services provided by the independent 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, CAO 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

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the
board of directors. A copy of our Code of Business Conduct and Ethics is available free of charge in print to any unitholder who sends a request to the office of the Secretary of MarkWest Energy
Partners, L.P. at 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 general partner's directors, executive officers, and persons who own more
than 10% of any class of our equity securities registered under Section 12 of the Exchange Act, to file with the SEC initial reports of ownership and reports of changes in ownership in such
securities. SEC regulations also require directors, executive officers and greater than 10% unitholders to furnish us with copies of all Section 16(a) reports they file.

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

Mr. Semple,
a Director and Chief Executive Officer of the General Partner, filed two late reports, which each covered one transaction resulting in a net increase of 3,030 units.

Mr. Ivey,
who retired as Chief Financial Officer of the General Partner on October 1, 2006, filed two late reports, which covered a total of three transactions resulting in
net increase of 242 units.

Ms. Marle,
a Vice President of the General Partner, filed one late report, which covered one transaction resulting in a decrease of 246 units.

Mr. Nickerson,
a Senior Vice President of the General Partner, filed one late report, which covered one transaction resulting in a decrease of 646 units.

Mr. Schroeder,
a Vice President of the General Partner, filed one late report, which covered one transaction resulting in a decrease of 208 units.

Mr. Young,
a Senior Vice President of the General Partner, filed one late report, which covered three transactions resulting in a net increase of 728 units.

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

ITEM 11.    Executive Compensation

COMPENSATION DISCUSSION AND ANALYSIS

Introduction

Like most publicly traded limited partnerships, we have no direct officers or employees. Both our General Partner and the General Partner's majority owner,
MarkWest Hydrocarbon, have commonly appointed executive officers. However, these executives are solely employed by MarkWest Hydrocarbon, and are compensated by MarkWest Hydrocarbon. The General
Partner has entered into a Services Agreement with MarkWest Hydrocarbon for it 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 MarkWest Hydrocarbon for an allocated portion of its employees' and of the common executives' base and incentive compensation.
Further, due to the relatively greater amount of cash flow and income generated by the Partnership, the Partnership funds

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a
proportional share of the short-term cash incentive pool available for the MarkWest Hydrocarbon employees, including the common executive officers. Accordingly, both the MarkWest
Hydrocarbon and the General Partner's Compensation Committees and Boards of Directors are involved in the determination of executive and employee compensation. The compensation of the 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

Committee Members and Independence

The Compensation Committee consists of three members of the board of directors of our general partner, Charles K. Dempster (chairman), William Nicoletti and Keith
E. Bailey. The Compensation Committee is charged with overseeing the compensation of the Partnership's directors and executives, and with administering the Partnership's incentive-compensation plans,
including its equity-based plan, the MarkWest Energy Partners, L.P. Long-Term 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.

Role of Committee

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 Partnership 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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Committee Meetings

Our Compensation Committee meets as often as necessary to perform its duties and responsibilities. The Compensation Committee held four meetings during fiscal
2006, and the chairman of our 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:



Compensation Philosophy

General 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 a 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 Partnerships'
financial plans and strategic objectives, and to provide opportunities for increased compensation based on extraordinary performance by our employees, including our NEOs.

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Pay for Performance and Alignment with Long Term Goals

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, Partnership performance and achievement of strategic
goals, including increasing unitholder 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 unitholders, by creating a strong and direct
link between executive compensation and unitholder return over a multiple year performance cycle. 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. 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 MarkWest Hydrocarbon membership interests in
the Partnership's General Partner. This opportunity for General Partner ownership was provided in order 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.

Base Compensation to Reflect Position and Responsibility and Competitiveness within Industry

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.

Overall Philosophy

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.

Compensation Setting Process

Coordination with MarkWest Hydrocarbon

As stated above, neither we, nor our General Partner have any direct employees, but we have commonly appointed executive officers with MarkWest Hydrocarbon. These
executive officers perform management services for the Partnership pursuant to a Services Agreement between MarkWest Hydrocarbon and our General Partner. Under the Services Agreement, we reimburse
MarkWest Hydrocarbon for that portion of these executive officers' time and compensation devoted to the Partnership's business and affairs. Accordingly, our Compensation Committee participates with
MarkWest Hydrocarbon in the determination of the executives' base and incentive compensation and participates in an allocated portion of the funding of short term incentive cash compensation payments
as well as the long term equity awards provided to the executives.

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Management's Role in the 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
Partnership 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.

Committee ConsultantsBenchmarking

To evaluate all areas of executive compensation, the Compensation Committee seeks the additional input of outside compensation consultants and available
comparative information. In 2006, the MarkWest Hydrocarbon Compensation Committee engaged Towers Perrin as a compensation consultant, primarily to provide and analyze peer group data to assist
MarkWest Hydrocarbon's and our Compensation Committees 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.

149

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Setting Total Compensation Levels and Targets

To ensure 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 Partnership 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.

Setting Performance Objectives

The Partnership's annual and five year business plans and strategic objectives are presented by management at the Partnership'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 Partnership's annual business plan. In establishing the compensation plan, our Compensation Committee then utilizes the primary financial objectives from the adopted
business plan, distributable 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; general and administrative expense
management; and reaching top quartile distribution and yield performance as compared to MLP pipeline peer group.

Annual Evaluation

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 NEOs 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.

Other Compensation

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.

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Elements of Executive Compensation

Total 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

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

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 Partnership. The NEOs incentive awards are based upon four key performance metrics:
1) the Partnership's distributable 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

Short-Term Cash Incentive Plan Compensation

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.

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Long-Term Equity Incentive Program

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.

Participation Plan

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 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." The MarkWest Hydrocarbon Board has determined at this time to cease any further sales of GP Interests.

Due
to the differences in each of the NEOs individual level of 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.

Allocation among Compensation Elements

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 NEOs 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

152

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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 TargetChief 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

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.

Long-Term Equity Incentive Awards

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.

Other Compensation Components

Severance Plan

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

153

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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.

Employment Agreements

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

CEO 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.

Indemnification Agreements

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 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.

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Retirement Plans

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.

Change in Control Agreements

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.

Perquisites

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

Internal Pay Equity

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.

Tax Deductibility of Compensation

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.

Option Grants

Although permitted under the 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 Partnership's Annual Report on Form 10-K/A for the year ended
December 31, 2006.

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 Partnership's Annual Report on Form 10-K/A for the year ended
December 31, 2006.

|Submitted by: |  | Charles K. Dempster
William Nicoletti
Keith E. Bailey
Members of the Compensation Committee
|------------- |  | -------------------------------------------------------------------------------------------

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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 MWP
3,088 MWE                                                |  | 

                                                                |  | 

    
|James G. Ivey
Chief Financial Officer (Retired)                    |  | 1/31/06
1/31/06                 |  | 1/26/06
1/25/06                   |  | 
            |  | 
            |  | 
             |  | 
        |  | 
        |  | 
        |  | 2,026 MWP
1,874 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 MWP
10,726 MWE
2,500 MWP
5,000 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 MWP
1,942 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 MWP
1,578 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 MWP
11,520 MWE                                               |  | 

                                                                |  | 

    

---

157

---





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. 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):

|                                                                   |  |                             |  |           |  |     |  |      |                          |  |                                                    | Stock Awards
|------------------------------------------------------------------ |  | --------------------------- |  | --------- |  | --- |  | ---- | ------------------------ |  | -------------------------------------------------- | ------------
|
|
|
|
|
|
|
|
|
|Frank M. Semple
resident and Chief Executive Officer               |  | 12,100                      |  |          |  | N/A |  | $    | 8.41                     |  | 11/3/2013                                          |             
|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 |  | $$$  | 6.58
8.45
5.75           |  | 7/26/2010
12/7/2010
8/1/2011                       |             
|John C. Mollenkopf
Senior Vice President, Chief Operations Officer |  | 867
1,044
1,044
2,408
2,469 |  | 



 |  | N/A |  | $$$$ | 7.89
4.04
6.58
8.45
5.75 |  | 12/10/2008
11/30/2009
7/26/2010
12/7/2010
8/1/2011 |             
|C. Corwin Bromley
Senior Vice President, General Counsel           |  | 2,420                       |  |          |  | N/A |  | $    | 12.05                    |  | 9/27/2014                                          |             

---

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

158

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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           |  | 
           |  | 
         

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                                 

159

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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                              

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 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  

---

160

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PERFORMANCE GRAPH

GRAPHIC

Source:
FactSet.

---

161

---





ITEM 12.    Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

The following table sets forth the beneficial ownership of units as of February 15, 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; and by all 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
%




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
%




ITEM 13.    Certain Relationships and Related Transactions, and Director Independence

MarkWest Hydrocarbon controls our operations through its ownership of our general partner, as well as a significant limited partner ownership interest in us
through its ownership of a majority of our subordinated units. As of March 1, 2007, affiliates of MarkWest Hydrocarbon, in the aggregate, owned a 15% interest in the Partnership, consisting of
3,738,992 common units, 1,200,000 subordinated units and a 2% general partner interest.

Distributions and Payments to our General Partner and its Affiliates

Our general partner owns the 2% general partner interest and all of the incentive distribution rights. Our general partner is entitled to receive incentive
distributions if the amount we distribute with respect to any quarter exceeds levels specified in our Partnership Agreement. Under the quarterly incentive distribution provisions, generally our
general partner is entitled to 13% of amounts we distribute in excess of $0.55 per unit, 23% of the amounts we distribute in excess of $0.625 per unit and 48% of amounts we distribute in excess of
$0.75 per unit.

Agreements with MarkWest Hydrocarbon

We entered into various agreements with MarkWest Hydrocarbon on May 24, 2002, the closing of our initial public offering. Specifically, we entered into:



164

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Effective
January 1, 2004, we entered into a Services Agreement whereby MarkWest Hydrocarbon, Inc. will act in a management capacity rendering
day-to-day business operations and administrative services to the Partnership.

These
agreements were not the result of arm's-length negotiations.

Omnibus Agreement

Concurrently with the closing of our initial public offering, we entered into an agreement with MarkWest Hydrocarbon, our general partner and the Operating
Company that governs potential competition and indemnification obligations among us and the other parties to the agreement.

Services.Pursuant to the Omnibus Agreement, we have designated each current or future employee of MarkWest Hydrocarbon who
fulfills a job function on our behalf as our agent, with full power and authority to perform such job function.

Non-Competition Provisions.MarkWest Hydrocarbon agreed, and caused its affiliates to agree, for so long as
MarkWest Hydrocarbon controls the general partner, not to engage in, whether by acquisition, construction or otherwise, the business of processing natural gas and transporting, fractionating and
storing NGLs. This restriction will not apply to:



License Provisions.Pursuant to the Omnibus Agreement, MarkWest Hydrocarbon granted us nontransferable, nonexclusive,
royalty-free right to use the "MarkWest" name and mark.

The
Omnibus Agreement may not be amended without the concurrence of the Conflicts Committee. The Omnibus Agreement, other than the indemnification provisions, will terminate if:



165

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Gas-Processing Agreement

At the closing of our initial public offering, we entered into a Gas-Processing Agreement with MarkWest Hydrocarbon that governs the parties'
obligations with respect to the processing of natural gas at our Kenova, Boldman and Cobb processing plants.

Gas-Processing Services.Under the Gas-Processing Agreement, until 2012 and on a
year-to-year basis thereafter, MarkWest Hydrocarbon has agreed to:



We
have agreed to:



As
compensation for providing these services, MarkWest Hydrocarbon pays us a monthly gas-processing fee based on the natural gas volumes delivered at our Kenova, Boldman and
Cobb processing plants. A portion of this gas-processing fee is adjusted on each anniversary of the effective date to reflect changes in the Producers Price Index for Oil and Gas Field
Services.

Indemnification Provisions.Under the Gas-Processing Agreement, MarkWest Hydrocarbon has agreed to indemnify us
from any and all losses we incur arising from MarkWest Hydrocarbon facilities or its possession and control of the natural gas (except to the extent caused by our gross negligence or willful conduct).
MarkWest Hydrocarbon will be in possession and control of the natural gas until it is delivered to one of our processing facilities and after our operating company redelivers the residue gas to
MarkWest Hydrocarbon.

We
have agreed to indemnify MarkWest Hydrocarbon from any and all losses incurred by MarkWest Hydrocarbon arising from our facilities or our possession and control of the natural gas
(except to the extent caused by MarkWest Hydrocarbon's gross negligence or willful conduct). We will be in possession and control of the natural gas after it is delivered to one of our processing
facilities and until we redeliver the residue gas to MarkWest Hydrocarbon.

We
will also pay MarkWest Hydrocarbon a penalty of $5,000 per day (unless MarkWest Hydrocarbon can establish actual damages in excess of $5,000 per day) if we fail to process the natural

166

---



gas
at any of our processing plants to meet the agreed specifications, or interrupt the NGL production process, unless the reason for the failure or interruption is:



If
we interrupt processing at any of our processing plants for any reason for 30 consecutive days without making a good-faith effort to resume processing as soon as
reasonably possible, or, if after notification from MarkWest Hydrocarbon, we are otherwise in default of any of the terms of the Gas-Processing Agreement for 25 days, then MarkWest
Hydrocarbon, in its sole discretion and in addition to any other available legal or equitable remedies, may:



Pipeline Liquids Transportation Agreement

At the closing of our initial public offering, we entered into a Pipeline Liquids Transportation Agreement with MarkWest Hydrocarbon that governs the parties'
obligations with respect to the transportation of mixed NGLs to our Siloam fractionation facility.

Transportation Services.Under this Transportation Agreement, until 2012 and on a year-to-year basis
thereafter, MarkWest Hydrocarbon delivers, at specified locations, all NGLs acquired from our Kenova processing facility, and any NGLs it desires to deliver from our Boldman extraction facility, or
from other extraction plants or sources in the Appalachian region.

We
maintain and operate our pipeline system, at our sole risk and expense, to transport all of the NGLs that MarkWest Hydrocarbon delivers from our extraction facilities to our Siloam
fractionation facility.

In
return, MarkWest Hydrocarbon pays us a monthly transportation fee based on the number of gallons of NGLs transported to our Siloam fractionation facility. A portion of this fee is
adjusted on January 1 of each year to reflect changes in the Producers Price Index for Oil and Gas Field Services. Under the agreement, MarkWest Hydrocarbon will incur all incidental losses
incurred at our facilities, or the losses or gains due to variations in measurement equipment.

Indemnification Provisions.Under the Transportation Agreement, MarkWest Hydrocarbon has agreed to indemnify us from any and
all losses we incur arising from MarkWest Hydrocarbon facilities or its possession and control of the NGLs (except to the extent caused by our gross negligence or willful conduct). MarkWest
Hydrocarbon will be in possession and control of the NGLs until they are delivered to our pipeline system.

We
have agreed to indemnify MarkWest Hydrocarbon from any and all losses incurred by MarkWest Hydrocarbon arising from our facilities or our possession and control of the NGLs (except to
the extent caused by MarkWest Hydrocarbon's gross negligence or willful conduct). We will be in possession and control of the NGLs after they are delivered to our pipeline system.

167

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Fractionation, Storage and Loading Agreement

At the closing of our initial public offering, we entered into a Fractionation, Storage and Loading Agreement with MarkWest Hydrocarbon that governs the parties'
obligations with respect to the unloading and fractionation of NGLs, and the storage of the NGL products at our Siloam facility.

Services.Under the Fractionation, Storage and Loading Agreement, until 2012 and on a year-to-year
basis thereafter, MarkWest Hydrocarbon has agreed to deliver, at specified locations, all of the mixed NGLs produced at our Kenova, Boldman or Cobb processing plants for fractionation at our Siloam
fractionation facility.

We
have agreed to:



As
compensation for providing our fractionating, loading and above ground storage services, MarkWest Hydrocarbon pays us a monthly fractionation fee based on the gallons delivered to us
for fractionation. As compensation for our storage of the NGL products in underground storage caverns, MarkWest Hydrocarbon pays us an annual storage fee. As compensation for unloading any NGLs that
MarkWest Hydrocarbon delivers to us by railcar, MarkWest Hydrocarbon pays us a monthly fee based on the gallons unloaded. A portion of each of the above fees is adjusted on January 1 of each
year to reflect changes in the Producers Price Index for Oil and Gas Field Services. Under the agreement, MarkWest Hydrocarbon incurs all incidental losses incurred at our facilities, or the losses or
gains due to variations in measurement equipment.

Indemnification Provisions.Under the Fractionation, Storage and Loading Agreement, MarkWest Hydrocarbon has agreed to
indemnify us from any and all losses we incur arising from MarkWest Hydrocarbon facilities or its possession and control of the NGLs or NGL products (except to the extent caused by our gross
negligence or willful conduct). MarkWest Hydrocarbon will be in possession and control of the NGLs until they are delivered to our Siloam facility, and of the NGL products after we load them into
transportation facilities provided by MarkWest Hydrocarbon.

We
have agreed to indemnify MarkWest Hydrocarbon from any and all losses incurred by MarkWest Hydrocarbon arising from our facilities or our possession and control of the NGLs or NGL
products (except to the extent caused by MarkWest Hydrocarbon's gross negligence or willful conduct). We will be in possession and control of the NGLs after they are delivered to our Siloam facility
and of the NGL products until we load them into transportation facilities provided by MarkWest Hydrocarbon.

168

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Natural Gas Liquids Purchase Agreement

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

Purchase and Sale.Under the Natural Gas Liquids Purchase Agreement, until 2012, we have agreed to commit to deliver to
MarkWest Hydrocarbon all of the NGL products produced from the NGLs we acquire under the Maytown Agreement, together with such other NGLs to be sold at our facility. MarkWest Hydrocarbon has agreed to
receive and purchase all of these NGL products.

As
consideration for the sale of NGL products, MarkWest Hydrocarbon pays us a monthly fee equal to the Net Sales Price per gallon (determined under the Maytown Agreement), times the
number of gallons of NGL products contained in our NGLs.

Indemnification Provisions.Under the Natural Gas Liquids Purchase Agreement, MarkWest Hydrocarbon has agreed to indemnify us
from any and all losses we incur arising from MarkWest Hydrocarbon facilities or its possession and control of the NGL products (except to the extent caused by our gross negligence or willful
misconduct). As between the parties, MarkWest Hydrocarbon will be in possession and control of the NGL products after they are delivered to MarkWest Hydrocarbon at the designated delivery point.

We
have agreed to indemnify MarkWest Hydrocarbon from any and all losses incurred by MarkWest Hydrocarbon arising from our facilities or our possession and control of the NGL products
(except to the extent caused by MarkWest Hydrocarbon's gross negligence or willful misconduct). As between the parties, we will be in possession and control of the NGL products until we deliver them
to MarkWest Hydrocarbon at the designated delivery point.

Services Agreement

MarkWest Hydrocarbon agreed to act in a management capacity rendering day-to-day operational, business and asset management, accounting,
personnel and related administrative services to the Partnership.

The
Partnership is obligated to reimburse MarkWest Hydrocarbon for all documented expenses incurred on behalf of the Partnership and which are expressly designated as reasonably
necessary.

Relationship of Directors of our General Partner with MarkWest Hydrocarbon

William P. Nicoletti, who serves as a member of our general partner's board of directors, is also a member of the board of directors of Star Gas LLC, the general
partner of Star Gas Partners, L.P., a retail propane and heating oil master limited partnership. Star Gas' propane division is a significant customer of MarkWest Hydrocarbon and accounted for
approximately 11% of its revenues for the year ended December 31, 2004. The propane division of Star Gas Partners, L.P. was purchased by another entity in December 2004 and, therefore,
Star Gas Partners, L.P. will not be a related party for the year ending December 31, 2005 or 2006.

Keith
E. Bailey, who also serves as a member of our general partner's board of directors, is a member of the board of directors of Aegis, an insurance company. Aegis provides insurance
to MarkWest Hydrocarbon, Inc. and the Partnership as a named insured under MarkWest Hydrocarbon's policy.

169

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Transactions with Management and Others

In September 2006 the Partnership 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 Partnership from October 2 through October 31, 2006, and received compensation in the amount of $19,850. Pursuant
to the Separation Agreement, the Partnership 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 claims against the Partnership and provided non-compete and non-solicitation covenants
for the eighteen-month period of separation payments referenced above.

ITEM 14.    Principal Accountant Fees and Expenses

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

Year ended December 31,2006

2005(2)Audit fees

$
2,177

$
2,555Audit-related fees(1)


345


526Tax fees





All other fees





Total accounting fees and services

$
2,522

$
3,081




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

170

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PART IV

ITEM 15.    Exhibits, And Financial Statement Schedules





171

---





Schedule ASignificant Subsidiary Financial StatementsStarfish Pipeline Company, LLC

Starfish Pipeline Company, LLC
Consolidated Financial Statements
December 31, 2006 and 2005

172

---





Starfish Pipeline Company, LLC  Index  December 31, 2006 and 2005



|Consolidated Financial Statements
|---------------------------------
|Report of Independent Auditors   
|Balance Sheets                   
|Statements of Income             
|Statements of Members' Capital   
|Statements of Cash Flows         
|Notes to Financial Statements    

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Report of Independent Auditors

To
the Board of Directors and Members of
Starfish Pipeline Company, LLC

In
our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of members' capital and of cash flows present fairly, in all material
respects, the financial position of Starfish Pipeline Company, LLC and its subsidiaries (the "Company") at December 31, 2006 and 2005, and the results of their operations and their cash flows
for the years then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the
United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management,
and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As
described in Note 3 to the financial statements, the Company has significant transactions and relationships with affiliated entities.

PricewaterhouseCoopers
LLP

Houston,
Texas
March 6, 2007

174

---



Starfish Pipeline Company, LLC        Consolidated Balance Sheets        December 31, 2006 and 2005

|(in thousands of dollars)                            |                                                               | 2006                                   |         | 2005 
|---------------------------------------------------- | ------------------------------------------------------------- | -------------------------------------- | ------- | -----
|Assets                                               |                                                               |                                        |         |      
|Current assets                                       |                                                               |                                        |         |      
|                                                     | Cash and cash equivalents                                     |                                        | $       | 2,846
|                                                     | Transportation receivables, net of allowance (Note 2)         |                                        |         | 7,416
|                                                     | Accrued other receivables (Note 4)                            |                                        |         | 1,347
|                                                     | Other receivables from related parties                        |                                        |         | 251  
|                                                     | Gas imbalance and gas imbalance net under recoveries (Note 2) |                                        |         | 1,511
|                                                     | Other assets                                                  |                                        |         | 363  
|                                                     |                                                               |                                        |         |      
|                                                     |                                                               | Total current assets                   |         |      
|Pipelines, plant and equipment, net (Note 5)         |                                                               |                                        | 133,443 |      
|                                                     |                                                               |                                        |         |      
|                                                     |                                                               | Total assets                           |         | $    
|                                                     |                                                               |                                        |         |      
|Liabilities and Members' Capital                     |                                                               |                                        |         |      
|Current liabilities                                  |                                                               |                                        |         |      
|                                                     | Accounts payable, trade                                       |                                        | $       | 286  
|                                                     | Other payables to related parties                             |                                        |         | 3,045
|                                                     | Gas imbalances (Note 2)                                       |                                        |         | 322  
|                                                     | Accrued expenses                                              |                                        |         | 2,339
|                                                     | Current obligation under capital lease                        |                                        |         | 1,073
|                                                     |                                                               |                                        |         |      
|                                                     |                                                               | Total current liabilities              |         |      
|Obligation under capital lease, less current portion |                                                               |                                        | 5,388   |      
|Asset retirement obligation (Note 7)                 |                                                               |                                        | 5,936   |      
|Regulatory liability (Note 7)                        |                                                               |                                        | 9,349   |      
|                                                     |                                                               |                                        |         |      
|                                                     |                                                               | Total liabilities                      |         |      
|Members' capital                                     |                                                               |                                        | 119,439 |      
|                                                     |                                                               |                                        |         |      
|                                                     |                                                               | Total liabilities and members' capital |         | $    
|                                                     |                                                               |                                        |         |      

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

175

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Starfish Pipeline Company, LLC        Consolidated Statements of Income        Years Ended December 31, 2006 and 2005

|(in thousands of dollars)        |                               | 2006 |        | 2005   |  
|-------------------------------- | ----------------------------- | ---- | ------ | ------ | -
|Operating revenues               |                               |      |        |        |  
|Transportation                   |                               | $    | 28,736 |        | $
|Dehydration and other            |                               |      | 3,342  |        |  
|                                 |                               |      |        |        |  
|                                 | Total revenues                |      |        | 32,078 |  
|                                 |                               |      |        |        |  
|Operating expenses               |                               |      |        |        |  
|Operating and maintenance        |                               |      | 12,578 |        |  
|Administrative and general       |                               |      | 1,922  |        |  
|Depreciation and amortization    |                               |      | 7,786  |        |  
|Accretion and regulatory expense |                               |      | 602    |        |  
|                                 |                               |      |        |        |  
|                                 | Total operating expenses, net |      |        | 22,888 |  
|                                 |                               |      |        |        |  
|                                 | Net operating income (loss)   |      |        | 9,190  |  
|                                 |                               |      |        |        |  
|Other income (expense)           |                               |      |        |        |  
|Interest expense                 |                               |      | (504   | )      |  
|Interest income                  |                               |      | 269    |        |  
|Other income                     |                               |      | 546    |        |  
|                                 |                               |      |        |        |  
|                                 | Total other income (expenses) |      |        | 311    |  
|                                 |                               |      |        |        |  
|                                 | Net income (loss)             |      | $      | 9,501  |  
|                                 |                               |      |        |        |  

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

176

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Starfish Pipeline Company, LLC        Consolidated Statements of Members' Capital        Years Ended December 31, 2006 and 2005

|(in thousands of dollars)     |  | Enterprise/
MarkWest |        | Enbridge |   | Total  |  
|----------------------------- |  | -------------------- | ------ | -------- | - | ------ | -
|
|Balances at December 31, 2004 |  | $                    | 36,819 |          | $ | 36,819 |  
|Contributions                 |  |                      | 1,486  |          |   | 1,486  |  
|Distributions                 |  |                      | (2,653 | )        |   | (2,654 | )
|Net income                    |  |                      | (434   | )        |   | (434   | )
|                              |  |                      |        |          |   |        |  
|Balances at December 31, 2005 |  |                      | 35,218 |          |   | 35,217 |  
|Contributions                 |  |                      | 19,751 |          |   | 19,752 |  
|Distributions                 |  |                      |       |          |   |       |  
|Net income                    |  |                      | 4,751  |          |   | 4,750  |  
|                              |  |                      |        |          |   |        |  
|Balances at December 31, 2006 |  | $                    | 59,720 |          | $ | 59,719 |  
|                              |  |                      |        |          |   |        |  

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

177

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Starfish Pipeline Company, LLC        Consolidated Statements of Cash Flows        Years Ended December 31, 2006 and 2005

|(in thousands of dollars)                                                               |                                  | 2006                                      |                                           | 2005   |       
|--------------------------------------------------------------------------------------- | -------------------------------- | ----------------------------------------- | ----------------------------------------- | ------ | ------
|Cash flows from operating activities                                                    |                                  |                                           |                                           |        |       
|Net income (loss)                                                                       |                                  | $                                         | 9,501                                     |        | $     
|Adjustments to reconcile net income (loss) to net cash provided by operating activities |                                  |                                           |                                           |        |       
|                                                                                        | Depreciation and amortization    |                                           |                                           | 7,786  |       
|                                                                                        | Accretion and regulatory expense |                                           |                                           | 602    |       
|                                                                                        | Provision for bad debts          |                                           |                                           | (1,422 | )     
|                                                                                        | Changes in working capital       |                                           |                                           |        |       
|                                                                                        |                                  | Transportation receivables                |                                           |        | 473   
|                                                                                        |                                  | Other receivables from related parties    |                                           |        | 1,235 
|                                                                                        |                                  | Gas imbalance net under recoveries        |                                           |        | 2,717 
|                                                                                        |                                  | Accrued other receivable and other assets |                                           |        | (1,440
|                                                                                        |                                  | Accounts payable and accrued liabilities  |                                           |        | (2,454
|                                                                                        |                                  | Gas imbalances                            |                                           |        | (6,002
|                                                                                        |                                  | Other payables to related parties         |                                           |        | 2,623 
|                                                                                        |                                  |                                           |                                           |        |       
|                                                                                        |                                  |                                           | Net cash provided by operating activities |        |       
|                                                                                        |                                  |                                           |                                           |        |       
|Cash flows from investing activities                                                    |                                  |                                           |                                           |        |       
|Capital expenditures                                                                    |                                  |                                           | (28,525                                   | )      |       
|Acquisition of assets                                                                   |                                  |                                           | (22,747                                   | )      |       
|Proceeds from disposition of assets                                                     |                                  |                                           |                                          |        |       
|                                                                                        |                                  |                                           |                                           |        |       
|                                                                                        |                                  |                                           | Net cash used in investing activities     |        |       
|                                                                                        |                                  |                                           |                                           |        |       
|Cash flows from financing activities                                                    |                                  |                                           |                                           |        |       
|Contribution from members                                                               |                                  |                                           | 39,503                                    |        |       
|Distribution to members                                                                 |                                  |                                           |                                          |        |       
|Capital lease payments                                                                  |                                  |                                           | (578                                      | )      |       
|                                                                                        |                                  |                                           |                                           |        |       
|                                                                                        |                                  |                                           | Net cash used in financing activities     |        |       
|                                                                                        |                                  |                                           |                                           |        |       
|                                                                                        |                                  |                                           | Increase in cash and cash equivalents     |        |       
|Cash and cash equivalents                                                               |                                  |                                           |                                           |        |       
|Beginning of year                                                                       |                                  |                                           | 1,574                                     |        |       
|                                                                                        |                                  |                                           |                                           |        |       
|End of year                                                                             |                                  | $                                         | 2,846                                     |        | $     
|                                                                                        |                                  |                                           |                                           |        |       

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

178

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Business

Starfish Pipeline Company, LLC ("Starfish" or the "Company") was formed on December 8, 2000, under the provisions of the Delaware Limited Liability Company
Act. Starfish was owned 50% each by Enterprise Products Operating, LP ("Enterprise") and Shell Gas Transmission, LLC ("Shell"), an affiliate of Shell Oil Company ("SOC"). In January 2001,
Starfish acquired 100% of Stingray Pipeline Company, LLC ("Stingray"), West Cameron Dehydration, LLC ("West Cameron") and Triton Gathering, LLC ("Triton", previously East Breaks Gathering Company,
LLC) from Deepwater Holdings, LLC, an affiliate of the El Paso Corporation. The purchase price was $50,200,000, which was allocated based on the fair value of the net assets acquired. Since the
estimated fair value of the net assets was in excess of the purchase price, no goodwill was recorded. On December 31, 2004, SOC sold its interest in Shell to Enbridge Holdings (Offshore) L.L.C.
("Enbridge"), an affiliate of Enbridge (U.S.) Inc. Therefore, as of December 31, 2004, SOC was no longer an affiliate. Subsequent to the sale, Shell was renamed Enbridge Offshore (Gas
Transmission) L.L.C. On March 31, 2005, with an effective date of January 1, 2005, Enterprise sold its interest in Starfish to MarkWest Energy Partners L.P. ("MarkWest"). Therefore, as
of January 1, 2005, Enterprise was no longer an affiliate.

Stingray
operates a regulated natural gas pipeline system (the "Stingray System") engaged in the transmission of natural gas in the Louisiana and Texas offshore areas. The Stingray
System consists of (i) 361 miles of 6 to 36-inch diameter pipeline that transports natural gas from the High Island Offshore System, or HIOS, West Cameron, East Cameron,
Garden Banks and Vermilion lease areas in the Gulf of Mexico to onshore transmission systems in Louisiana, (ii) 43 miles of 16 to 20-inch diameter pipeline connecting
platforms and leases in the Garden Banks Block 191 and 72 areas to the Stingray System, and (iii) 13 miles of 16-inch diameter pipeline connecting the GulfTerra Energy
Partners L.P., formerly known as El Paso Energy Partners L.P., platform at East Cameron Block 373 to the Stingray System at East Cameron Block 338.

West
Cameron operates an unregulated natural gas dehydration facility that provides interruptible dehydration service to offshore platform operators connected to the Stingray System. The
facility is located at Stingray station 701 in Holly Beach, Louisiana.

Triton
is an unregulated gathering system that includes 18 laterals, which are connected to the Stingray System, and located in the Garden Banks, East Cameron, Vermilion, and West
Cameron areas of the Gulf of Mexico. This includes the Gunnison lateral completed in December 2003 and the West Cameron 62 Lateral purchased from El Paso in May 2006.

Starfish
has no employees and receives all administrative and operating support through contractual arrangements with affiliated companies. These services and agreements are outlined in
Note 3, Related Party Transactions.

Agreements
between the member companies address the allocation of income and capital contributions and distributions amongst the respective members' capital accounts.

The
terms of the agreements include, but are not limited to, the following:



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2. Significant Accounting Policies



The consolidated financial statements include the accounts of the Company and its subsidiaries. All intercompany transactions and balances have been eliminated in
consolidation.



The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that
affect the reported amounts of certain assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the related reported amounts of revenue
and expenses during the reporting period. Such estimates and assumptions include those made in areas of FERC regulations, fair value of financial instruments, future cash flows associated with assets,
useful lives for depreciation and potential environmental liabilities. Actual results could differ from those estimates. Management believes that the estimates are reasonable.

Development
and production of natural gas in the service area of the pipeline and dehydration facilities are subject to, among other factors, prices for natural gas and federal and state
energy policy, none of which are within Starfish's control.



The Stingray System is an interstate pipeline subject to regulation by the Federal Energy Regulatory Commission ("FERC"). Stingray has accounting policies that
conform to generally accepted accounting principles in the United States of America, as applied to regulated enterprises and are in accordance with the accounting requirements and ratemaking practices
of the FERC.

Stingray
follows the regulatory accounting principles prescribed under Statement of Financial Accounting Standards ("SFAS") No. 71,Accounting for the
Effects of Certain Types of Regulation.If Stingray discontinued the application of SFAS No. 71, due to an increased level of competition and discounting in its
market area, adjustments and reversals of regulatory assets and liabilities would be necessary.



All highly liquid investments with maturity of three months or less when purchased are considered to be cash equivalents.



Allowances have been established for losses on accounts, which may become uncollectible. Collectibility is reviewed regularly and the allowance is adjusted as
necessary, primarily under the specific identification method. The allowance was $0 and $1,421,567 at December 31, 2006 and 2005, respectively.

180

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The
Company recognized provisions for bad debts of $1,421,567 in 2005 relating to imbalance disputes with shippers which has been resolved in 2006.



Pipelines, plant and equipment consist primarily of natural gas pipeline assets and related facilities that are recorded at cost. The regulated portion of the
pipeline assets includes an Allowance for Funds Used During Construction ("AFUDC"). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by FERC. The
pipeline and related facilities are depreciated
on the straight-line method over 100 years. The dehydration facility is depreciated based on a useful life of 40 years. The laterals are depreciated based on a useful life of
10 years. Routine maintenance and repair costs are expensed as incurred while additions, improvements and replacements are capitalized.

Leased
property and equipment are capitalized, as appropriate, and the present value of the related lease payments is recorded as a liability. Amortization of capitalized lease assets is
computed on a straight-line method over the term of the lease and recorded as a component of depreciation expense. Improvements to leased properties are amortized over their useful lives
or the lease period, whichever is shorter.

Starfish
records depreciation using the group method of depreciation which is commonly used by pipelines, utilities and similar entities. Under the group method, upon the disposition of
property, plant and equipment, the cost less net proceeds is typically charged to accumulated depreciation and no gain or loss on disposal is recognized. However, when a separately identifiable group
of assets, such as a stand-alone pipeline system is sold, Starfish will recognize a gain or loss in the Consolidated Statements of Income for the difference between the cash received and the net book
value of the assets sold.



Starfish evaluates its assets for impairment when events or circumstances indicate that the carrying values may not be recovered. These events include market
declines that are believed to be other than temporary, changes in the manner in which Starfish intends to use a long-lived asset and adverse changes in the legal or business environment,
such as adverse actions by regulators. When an event occurs, Starfish evaluates the recoverability of its carrying value based on its long-lived assets' ability to generate future cash
flows on an undiscounted basis. If impairment is indicated Starfish will adjust the carrying value of assets downward.



Effective January 1, 2003, Starfish adopted SFAS No. 143,Accounting for Asset Retirement
Obligations. SFAS No. 143, issued in June 2001, requires the recording of liabilities equal to the fair value of asset retirement obligations and corresponding
additional asset costs. The obligations included are those for which there is a legal obligation as a result of existing or enacted law, statute or contract. Over time, the liability would be accreted
to its present value, and the capitalized cost would be depreciated over the useful life of the related asset. Upon settlement of the liability, an entity would either settle the obligation for its
recorded amount or recognize a gain or loss. Starfish's assets are under the jurisdiction of the Department of Transportation and the Minerals Management Service ("MMS"). The MMS requires the ultimate
abandonment of offshore facilities when they are no longer in use or when suspension for future utilization cannot be justified. Stingray and Triton recorded asset

181

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retirement
obligations for several of their laterals during FAS 143 implementation in 2003. Starfish did not recognize any asset retirement obligations for its remaining assets because these
were determined to be part of the main trunk-line system or laterals with long term usage potential, and due to current reserve estimates and expanding production in the deepwater of the
Gulf of Mexico, the date of abandonment could not be reasonably estimated. FIN 47 provides specific guidance regarding when an asset retirement obligation is reasonably estimable including when
sufficient information is available to apply an expected present value technique. The Company's implementation of FIN 47 did not have a material impact effect on these financial statements.

Costs
related to the retirement of the Stingray System are provided for in the rates charged to shippers, as allowed by the FERC. The amounts charged to shippers for the costs related to
the retirement of the Stingray System differ from the period costs recognized in accordance with SFAS No. 143, and therefore, result in a difference in the timing of recognition of period costs
for financial reporting and rate-making purposes. The Company recognizes a regulatory asset or liability for differences in the timing of recognition of the period costs associated with
asset retirement obligations for financial reporting and rate-making purposes.



Starfish is treated as a tax partnership under the provisions of the Internal Revenue Code. Accordingly, the accompanying financial statements do not reflect a
provision for income taxes since Starfish's results of operations and related credits and deductions will be passed through to and taken into account by its members in computing their respective tax
liabilities.



Revenue from pipeline transportation of hydrocarbons is recognized upon receipt of the hydrocarbons into the pipeline system. Revenue from dehydration services is
recognized at the time the service is performed.



In the course of providing transportation services to customers, Stingray may receive different quantities of gas from shippers than the quantities delivered on
behalf of those shippers. These transactions result in imbalances (gains and losses), which are settled in-kind each month through a fuel gas and unaccounted-for gas tracking
mechanism, negotiated cash-outs between parties, or are subject to a cash-out procedure included in Stingray's tariff. Gas imbalances represent natural gas volumes owed to or
due from Stingray's customers. Gas imbalances and gas imbalance over (under) recoveries are valued at an average monthly index price, which was $6.6100 per Dth for the month of December 2006
and $12.5475 per Dth for the month of December 2005.

Stingray's
tariff, Section 11.5, states that subsequent to the end of the twelve month billing period ending November 30 of each year, Stingray shall compare the revenues
and costs under the cash-out procedures and shall refund, within 60 days, the gas imbalance net over recoveries to firm and interruptible transportation customers on a
pro-rata basis in accordance with the transportation revenues Stingray received during that billing period. If the revenues received are less than the costs incurred, then Stingray shall
carry forward the gas imbalance net under recoveries and may offset such net under recoveries against any future net over recoveries that may occur.

182

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Starfish records environmental liabilities at their undiscounted amounts when environmental assessments indicate that remediation efforts are probable and the
costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations, and include estimates of
associated legal costs. As of December 31, 2006, Starfish had no liabilities recognized for environmental costs.



The reported amounts of financial instruments such as cash and cash equivalents, receivables, and current liabilities approximate fair value because of their
short maturities.



Certain reclassifications have been made in the prior year consolidated financial statements to conform to the 2006 financial statement presentation. These
reclassifications have no impact on net income.

3. Related Party Transactions



There were no transportation revenues derived from related parties in 2006 and 2005. All transactions were at rates pursuant to the appropriate FERC tariff or
contractual agreements. There were no affiliate receivables or payables relating to transportation and gas imbalances at December 31, 2006 and 2005.



Starfish has no employees. Operating, maintenance and general and administrative services are provided to Starfish under service agreements with an Enbridge
affiliate in 2006 and 2005. Substantially all operating and administrative expenses were incurred through services provided under these agreements. At December 31, 2006 and 2005, respectively,
Starfish had affiliate payables of $3,044,796 and $421,447 and affiliates receivables of $251,378 and $0, relating to these agreements.



At December 31, 2005, Starfish had an affiliate receivable of $1,486,000 due from MarkWest for a capital contribution. Starfish received the contribution
in January 2006.

4. Accrued Other Receivables

Stingray operates an on-shore separation facility and charges the owners a fee for normal operations and any direct cost relating to repairs and
maintenance of the facility. Included in accrued other receivables is $1,288,531 and $63,959 related to these activities in 2006 and 2005, respectively.

183

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5. Pipelines, Plant and Equipment

Pipelines, plant and equipment at December 31, 2006 and 2005, is comprised of the following:

(in thousands of dollars)

2006

2005Regulated pipelines and equipment

$
47,585

$
49,273Regulated pipeline under capital lease


9,778


9,778Unregulated pipelines and equipment


66,312


43,211Dehydration facilities


4,349


4,542Construction in progress


32,865


3,656Asset retirement cost (regulated pipelines)


2,027


2,181162,916


112,641Accumulated depreciation


29,473


22,905$
133,443

$
89,736


6. Capital Lease

Stingray leases a 36-inch pipeline from Natural Gas Pipeline Company of America ("NGPL"), an affiliate of Kinder Morgan, Inc.,
that connects Stingray's pipeline system to onshore Louisiana. In June 1999, the lease agreement with NGPL was extended for an additional 14 years beginning December 1, 1999,
through November 30, 2013, with an option to purchase the asset at the expiration of the lease. Accordingly, Stingray accounts for this lease as a capital lease. The present value of the lease
payments under the capital lease is recorded as other current and noncurrent liabilities in the accompanying balance sheet.

Future
minimum lease payments under capital leases are as follows:

(in thousands of dollars)Year Ended December 31,2007

$
1,0732008


1,0732009


1,0732010


1,0732011


1,073Thereafter


3,129Total minimum lease payments


8,494Less: Amount representing interest


(2,033
)Present value of net minimum lease payments, including current maturities of $1,073

$
6,461


184

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7. Asset Retirement Obligation

Activity related to the Company's asset retirement obligation ("ARO") during the year ended December 31, 2006 and 2005, is as follows:

(in thousands of dollars)

2006

2005Balance of ARO as of January 1

$
5,593

$
5,277Liabilities incurred during period


19


Liabilities settled during period





Accretion expense


324


316Balance of ARO as of December 31

$
5,936

$
5,593


For
the years ended December 31, 2006 and 2005, the Company recognized depreciation expense related to its asset retirement cost ("ARC") of $512,500 and $223,000, respectively.

The
rate case filed by Stingray with the FERC (Docket No. RP99166) decreased the amount the Company could charge in their rates ("Negative Salvage") for asset retirement
obligations. Beginning in 2003, the Negative Salvage the Company was allowed to recover was 0.25% of the total value of the Stingray System (approximately $697,000 per year). The Company recognized
regulatory expense of approximately $278,045 and $363,000 during the year ended December 31, 2006 and 2005, respectively. Activity related to the Company's regulatory liability during the year
ended December 31, 2006 and 2005, is as follows:

(in thousands of dollars)

2006

2005Balance of regulatory liability as of January 1

$
9,180

$
8,817Negative Salvage recovered


675


697Current period ARO accretion (Stingray's System)


(248
)

(252
)Current period ARC depreciation (Stingray's System)


(258
)

(82
)Balance of regulatory liability as of December 31

$
9,349

$
9,180


8. Regulatory Matters



The FERC has jurisdiction over Stingray with respect to transportation of gas, rates and charges, construction of new facilities, extension or abandonment of
service facilities, accounts and records, depreciation and amortization policies and certain other matters.

An
annual charge totaling $226,948 and $337,079 was paid to the FERC for fiscal years 2006 and 2005, respectively. This charge, to be recovered from customers through rates, was recorded
as a regulatory
asset and will be amortized over twelve months. During 2006 and 2005, respectively, $304,518 and $318,082 was recorded as amortization expense.

9. Commitments and Contingencies

In the ordinary course of business, Starfish and its subsidiaries are subject to various laws and regulations including regulations of the FERC. In the opinion of
management, compliance with existing laws and regulations will not materially affect the financial position or results of operations of Starfish.

185

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Various
legal actions, which have arisen in the ordinary course of business, are pending with respect to the assets of the Starfish. Management believes that the ultimate disposition of
these actions, either individually or in aggregate, will not have a material adverse effect on the financial position, the results of operations or cash flows of Starfish.

10. Impact of Hurricane Rita

In September 2005, Hurricane Rita ("Rita") caused substantial damage to both onshore and offshore facilities, resulting in loss of revenues and significant
capital and maintenance expenditures. Onshore refurbishments were primarily complete as of December 31, 2005, and the majority of offshore refurbishments were completed as of
December 31, 2006. As the company is self insured, total expenditures of approximately $30,407,000 have been incurred as of December 31, 2006.

11. Supplemental Cash Flow Disclosures

Noncash financing and investing activities include:

During
2006 and 2005, respectively, $19,000 and $0 of fixed asset additions were recognized due to recording of an asset retirement obligation.

The
members agreed on December 19, 2005 to provide capital contributions in the amount of $2,972,000. As of December 31, 2005, a receivable in the amount of $1,486,000, was
due from MarkWest. Starfish received the contribution in January 2006.

12. Business and Credit Concentrations

For the year ended December 31, 2006, four customers accounted for approximately 51% of revenues and 23% of transportation receivables. For the year ended
December 31, 2005, two customers accounted for approximately 29% of revenues and 13% of transportation receivables.

186

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|Exhibit Number |  | Description                                                                                                                                                                                                                                                                                                       
|-------------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|2.1(2)         |  | Purchase Agreement dated as of March 24, 2003, among PNG Corporation, Energy Spectrum Partners LP, MarkWest Texas GP, L.L.C., MW Texas Limited, L.L.C. and MarkWest Energy Partners, L.P.                                                                                                                         
|2.2(2)         |  | Plan of Merger entered into as of March 28, 2003, by and among MarkWest Blackhawk L.P., MarkWest Pinnacle L.P., MarkWest PNG Utility L.P., MarkWest Texas PNG Utility L.P., Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG Transmission
Company, PNG Utility Company and Bright Star Gathering, Inc.
|2.3(3)         |  | Asset Purchase-and-Sale Agreement dated as of November 18, 2003, by and between American Central Western Oklahoma Gas Company, L.L.C., MarkWest Western Oklahoma Gas Company, L.L.C. and American Central Gas Technologies, Inc.                                                                                  
|2.4(4)         |  | Purchase and Sale Agreement, dated as of November 7, 2003, by and between Shell Pipeline Company, LP and Equilon Enterprises L.L.C., dba Shell Oil Products US, and MarkWest Michigan Pipeline Company, L.L.C.                                                                                                    
|2.5(8)         |  | Asset Purchase and Sale Agreement and addendum, thereto, dated as of July 1, 2004, by and between American Central Eastern Texas Gas Company Limited Partnership, ACGC Gathering Company, L.L.C. and MarkWest Energy East Texas Gas Company's
L.P.                                                                
|2.6(15)        |  | Purchase and Sale Agreement effective as of January 1, 2005 between MarkWest Energy Partners L.P. and Enterprise Products Operating L.P.                                                                                                                                                                          
|2.7(16)        |  | 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.                                                                                                                                                          
|2.8(16)        |  | 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.                                                                                                    
|2.9(16)        |  | 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 Limited Partnership of MarkWest Energy Partners, L.P.                                                                                                                                                                                                                                              
|3.2(5)         |  | Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P., dated as of May 24, 2002.                                                                                                                                                                                                
|3.3(1)         |  | Certificate of Formation of MarkWest Energy Operating Company, L.L.C.                                                                                                                                                                                                                                             
|3.4(5)         |  | Amended and Restated Limited Liability Company Agreement of MarkWest Energy Operating Company, L.L.C., dated as of May 24, 2002.                                                                                                                                                                                  
|3.5(1)         |  | Certificate of Formation of MarkWest Energy GP, L.L.C.                                                                                                                                                                                                                                                            
|3.6(5)         |  | Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C., dated as of May 24, 2002.                                                                                                                                                                                                 
|3.7(12)        |  | Amendment No. 1 to Amended and Restated Limited Partnership Agreement MarkWest Energy Partners, L.P.                                                                                                                                                                                                              
|3.8(23)        |  | Amendment No. 2 to Amended and Restated Limited Partnership Agreement MarkWest Energy Partners, L.P.                                                                                                                                                                                                              
|               |  |                                                                                                                                                                                                                                                                                                                   

187

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|3.9(28)  |  | Amendment No. 3 to Amended and Restated Limited Partnership Agreement MarkWest Energy Partners, L.P.                                                                                                                                                                                                                                                                                                                                                                                                                                             
|-------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.1(6)   |  | Purchase Agreement dated as of June 13, 2003, by and among MarkWest Energy Partners, L.P. and Tortoise Capital Advisors, LLC as attorney-in-fact for the Purchasers.                                                                                                                                                                                                                                                                                                                                                                             
|4.2(6)   |  | Registration Rights Agreement dated as of June 13, 2003, by and among MarkWest Energy Partners, L.P. and Tortoise Capital Advisors, LLC as attorney-in-fact for the Purchasers.                                                                                                                                                                                                                                                                                                                                                                  
|4.3(8)   |  | Unit Purchase Agreement dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and MarkWest Energy GP, L.L.C. and each of Kayne Anderson Energy Fund II, L.P., and MarkWest Energy GP, L.L.C. and each of Kayne Anderson Energy
Fund II, L.P., Kayne Anderson Capital Income Partners, L.P., Kayne Anderson MLP Fund, L.P., Kayne Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR RV Performance Master Trust, Tortoise Energy Infrastructure
Corporation and Energy Income and Growth Fund as Purchasers.
|4.4(8)   |  | Registration Rights Agreement dated as of July 29, 2004, among MarkWest Energy Partners, L.P., and each of Kayne Anderson Energy Fund II, L.P., Kayne Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR RV
Performance Master Trust, Tortoise Energy Infrastructure Corporation and Energy Income and Growth Fund.                                                                                                                                                                                                   
|4.5(10)  |  | Purchase Agreement dated October 19, 2004, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein.                                                                                                                                                                                                                                                                                                                                                     
|4.6(10)  |  | Registration Rights Agreement dated October 25, 2004, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein.                                                                                                                                                                                                                                                                                                                                          
|4.7(10)  |  | Indenture dated as of October 25, 2004, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee.                                                                                                                                                                                                                                                                                                                                          
|4.8(10)  |  | Form of 6.875% Series A Senior Notes due 2014 with attached notation of Guarantees (incorporated by Reference to Exhibits A and D of Exhibit 4.7 hereto)                                                                                                                                                                                                                                                                                                                                                                                         
|4.9(17)  |  | Registration Rights Agreement, dated as of November 9, 2005                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|4.10(17) |  | Unit Purchase Agreement, dated as of November 9, 2005                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|4.11(18) |  | Registration Rights Agreement, dated as of December 23, 2005                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|4.12(18) |  | Unit Purchase Agreement, dated as of December 23, 2005                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|4.13(24) |  | 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.                                             
|4.14(24) |  | 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.                                                                                                                                                                                                                                                                                                                                 
|         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  

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|4.15(24) |  | 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.                                                                                                                                                                                        
|-------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.16(25) |  | 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 as the Initial Purchaser.                                                                                                                   
|10.1(5)  |  | Credit Agreement dated as of May 20, 2002, among MarkWest Energy Operating Company, L.L.C (as the Borrower), MarkWest Energy Partners, L.P. (as a Guarantor), Bank of America (as Administrative Agent), and Lenders Party Hereto $60,000,000 Senior
Credit Facility, and Banc of America Securities, L.L.C. as sole lead arranger and book manager.        
|10.2(3)  |  | Amended and Restated Credit Agreement dated as of December 1, 2003, among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Bank One, NA, as
Syndication Agent, Fortis Capital Corp., as Documentation Agent, to the $140,000,000 Senior Credit Facility.
|10.3(5)  |  | Contribution, Conveyance and Assumption Agreement dated as of May 24, 2002, by and among MarkWest Energy Partners, L.P.; MarkWest Energy Operating Company, L.L.C.; MarkWest Energy GP, L.L.C.; MarkWest Michigan, Inc.; MarkWest Energy
Appalachia, L.L.C.; West Shore Processing Company, L.L.C.; Basin Pipeline, L.L.C.; and MarkWest Hydrocarbon, Inc.  
|10.4(5)  |  | MarkWest Energy Partners, L.P. Long-Term Incentive Plan.                                                                                                                                                                                                                                                                                                    
|10.5(5)  |  | First Amendment to MarkWest Energy Partners, L.P. Long-Term Incentive Plan.                                                                                                                                                                                                                                                                                 
|10.6(5)  |  | Omnibus Agreement dated of May 24, 2002, among MarkWest Hydrocarbon, Inc.; MarkWest Energy GP, L.L.C.; MarkWest Energy Partners, L.P.; and MarkWest Energy Operating Company, L.L.C.                                                                                                                                                                        
|10.7(5)+ |  | Fractionation, Storage and Loading Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                            
|10.8(5)+ |  | Gas Processing Agreement dated as of May 24, 2002, by and between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                                         
|10.9(5)+ |  | Pipeline Liquids Transportation Agreement dated as of May 24, 2002, by and between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                        
|10.10(5) |  | Natural Gas Liquids Purchase Agreement dated as of May 24, 2002, by and between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                           
|10.11+   |  | Gas Processing Agreement (Maytown) dated as of May 28, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                                            
|10.12+   |  | Amendment to Gas Processing Agreement (Maytown) dated as of March 26, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                             
|10.13(7) |  | Services Agreement dated January 1, 2004 between MarkWest Energy GP, L.L.C. and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                                                                  
|         |  |                                                                                                                                                                                                                                                                                                                                                             

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|10.14(8)   |  | Second Amended and Restated Credit Agreement dated as of July 30, 2004 among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis Capital
Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe Generale, as Documentation Agent to the $315,000,000 Senior Credit Facility.                                                                                                                                                                                                                           
|---------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.15(8)   |  | First Amendment to the Second Amended and Restated Credit Agreement dated as of August 20, 2004, among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative
Agent, Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe Generale, as Documentation Agent.                                                                                                                                                                                                                                            
|10.16(11)  |  | Third Amended and Restated Credit Agreement dated as of October 25, 2004 among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Bank One, N.A.,
as Syndication Agent, Fortis Capital Corp., as Documentation Agent, U.S. Bank National Association, as Documentation Agent, Societe Generale, as Documentation Agent, and Wachovia Bank, National Association, as Documentation Agent, RBC Capital Markets
and J.P. Morgan Securities Inc., as Lead Arrangers and Joint Bookrunners, to the $200,000,000 Senior Credit Facility.  
|10.17(13)D |  | MarkWest Hydrocarbon, Inc. 1997 Severance Plan                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|10.18(14)D |  | Executive Employment Agreement effective November 1, 2003 between MarkWest Hydrocarbon, Inc. and Frank Semple.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|10.19(19)  |  | Fourth Amended and Restated Credit Agreement, dated as of November 1, 2005, among MarkWest Energy Operating Company, L.L.C., 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.                                                    
|10.20(20)  |  | Fifth amended and restated credit agreement dated as of December 29, 2005, among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Bank One, N.A.,
as Syndication Agent, Forties Capital Corp., as Documentation Agent, U.S. Bank National Association, as Documentation Agent, Society General, as Documentation Agent, and Wachovia Bank, National Association, as Documentation Agent, RBC Capital Markets
and J.P. Morgan Securities Inc., as Lead Arrangers and Joint Bookrunners, to the $615,000,000 Senior Credit Facility.
|10.21(26)  |  | Office Lease Agreement, dated April 19, 2006, by and between Park Central Property LLC, the landlord, and MarkWest Energy Partners, L.P., the tenant.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|10.22(27)  |  | 2006 Long Term Incentive Plan and Target Percentages.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|           |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       

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|10.23(29) |  | Form of Indemnification Agreement between MarkWest Energy Partners, LLP 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.
|--------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|16.1(22)  |  | Changes in registrants certifying accountants. MarkWest Energy Partners, L.P. dismissed KPMG LLP as the Partnership's independent registered public accounting firm and engaged Deloitte & Touche LLP as its new independent registered public
accounting firm.                                                                                                                                                                                                                                                                                                                                                                                                                             
|21.1(29)  |  | List of subsidiaries                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|23.1*     |  | Consent of KPMG LLP                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|23.2*     |  | Consent of Deloitte & Touche LLP                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|23.3*     |  | Consent of PricewaterhouseCoopers LLP                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|31.1*     |  | Chief Executive Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|31.2*     |  | Chief Financial Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|32.1*     |  | Certification of Chief Executive Officer of the General Partner pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|32.2*     |  | Certification of Chief Financial Officer of the General Partner pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   

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192

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SIGNATURES

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

|                       |  | MarkWest Energy Partners, L.P.
        (Registrant)
|---------------------- |  | ---------------------------------------------------
|                       |  | By:                                                
|                       |  | Its                                                
|Date: 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 Energy GP, L.L.C., the General Partner of MarkWest Energy Partners, L.P., 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 Senior Vice President & 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/KEITH E. BAILEYKeith E. Bailey Director                                                                                                    
|Date: November 2, 2007 |  | By: | /s/CHARLES K. DEMPSTERCharles K. Dempster Director                                                                                            
|Date: November 2, 2007 |  | By: | /s/DONALD C. HEPPERMANNDonald C. Heppermann Director                                                                                          
|                       |  |     |                                                                                                                                               

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|Date: November 2, 2007 |  | By: | /s/WILLIAM A. KELLSTROMWilliam A. Kellstrom Director
|---------------------- |  | --- | ----------------------------------------------------
|Date: November 2, 2007 |  | By: | /s/WILLIAM P. NICOLETTIWilliam P. Nicoletti Director

194

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