Use these links to rapidly review the documentMarkWest Hydrocarbon, Inc. Form 10-K Table of Contents ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

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FORM 10-K

|ý | Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2001.
|- | ---------------------------------------------------------------------------------------------------------------------------------

|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 1-11566

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

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

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

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

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

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

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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 or any amendment to this
Form 10-K. o

The
aggregate market value of voting common stock held by non-affiliates of the registrant on February 28, 2002 was $31,159,230.

The
number of shares outstanding of the registrant's common stock as of February 28, 2002, was 8,515,719.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of this Report (Items 10, 11, 12 and 13) is incorporated by reference from the registrant's proxy
statement to be filed pursuant to Regulation 14A with respect to the 2002 annual meeting of stockholders.

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MarkWest Hydrocarbon, Inc.  Form 10-K  Table of Contents



|         |                                         |                                              |                                                                                       | Page
|-------- | --------------------------------------- | -------------------------------------------- | ------------------------------------------------------------------------------------- | ----
|PART I   |                                         |                                              |                                                                                       |     
|         | Items 1. and 2. Business and Properties |                                              | 4                                                                                    
|         |                                         | General Development of Business              |                                                                                       | 4   
|         |                                         | Financial Information about Segments         |                                                                                       | 6   
|         |                                         | Narrative Description of Business            |                                                                                       | 6   
|         |                                         | Gathering, Processing and Marketing          |                                                                                       | 6   
|         |                                         | Exploration and Production                   |                                                                                       | 11  
|         |                                         | Seasonality                                  |                                                                                       | 16  
|         |                                         | Competition                                  |                                                                                       | 17  
|         |                                         | Operational Risks and Insurance              |                                                                                       | 17  
|         |                                         | Government Regulation                        |                                                                                       | 17  
|         |                                         | Environmental Matters                        |                                                                                       | 19  
|         |                                         | Employee Safety                              |                                                                                       | 20  
|         |                                         | Employees                                    |                                                                                       | 20  
|         |                                         | Financial Information about Geographic Areas |                                                                                       | 20  
|         |                                         | Forward-Looking Information                  |                                                                                       | 20  
|         | Item 3.                                 |                                              | Legal Proceedings                                                                     |     
|         | Item 4.                                 |                                              | Submission of Matters to a Vote of Security Holders                                   |     
|PART II  |                                         |                                              |                                                                                       |     
|         | Item 5.                                 |                                              | Market for the Registrant's Common Equity and Related Stockholder Matters             |     
|         | Item 6.                                 |                                              | Selected Financial Data                                                               |     
|         | Item 7.                                 |                                              | Management's Discussion and Analysis of Financial Condition and Results of Operations |     
|         | Item 7A.                                |                                              | Quantitative and Qualitative Disclosures About Market Risk                            |     
|         | Item 8.                                 |                                              | Financial Statements and Supplementary Data                                           |     
|         | Item 9.                                 |                                              | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure  |     
|PART III |                                         |                                              |                                                                                       |     
|         | Item 10.                                |                                              | Directors and Executive Officers of the Registrant                                    |     
|         | Item 11.                                |                                              | Executive Compensation                                                                |     
|         | Item 12.                                |                                              | Security Ownership of Certain Beneficial Owners and Management                        |     
|         | Item 13.                                |                                              | Certain Relationships and Related Transactions                                        |     
|PART IV  |                                         |                                              |                                                                                       |     
|         | Item 14.                                |                                              | Exhibits, Financial Statement Schedules, and Reports on Form 8-K                      |     

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|Glossary of Terms                                                            
|-----------------------------------------------------------------------------
|Bbls                                                                         
|Bcf                                                                          
|Btu                                                                          
|EBITDA                                                                       
|Mcf                                                                          
|Mcfe                                                                         
|Mcf/d                                                                        
|Mcfe/d                                                                       
|MMBtu                                                                        
|MMBtu/d                                                                      
|MMcf                                                                         
|MMcf/d                                                                       
|NGLs                                                                         
|One barrel of oil or NGLs is the energy equivalent of six Mcf of natural gas.

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PART I

In this report, unless the context requires otherwise, references to we, us, our, MarkWest or the Company are intended to mean MarkWest
Hydrocarbon, Inc., and its consolidated subsidiaries.

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

a.)  General Development of Business

MarkWest was founded in 1988 as a partnership and later incorporated in Delaware. We completed our initial public offering in 1996. Our principal executive office
is located at 155 Inverness Drive West, Suite 200, Englewood, Colorado 80112-5000. Our telephone number is (303) 290-8700. Englewood, Colorado is a suburb of
Denver. In addition, we have an NGL marketing office in Columbus, Ohio; a gas marketing and Appalachia producer relations office in Pittsburgh, Pennsylvania; and a Canadian exploration and production
office in Calgary, Alberta, Canada.

We
operate through two business segments: (a) gathering, processing and marketing (GPM or midstream); and (b) exploration and production of natural gas (E&P).

Gathering, Processing and Marketing

In our GPM segment, we are engaged in the gathering and processing of natural gas and the transportation, fractionation and storage of natural gas liquids (NGLs)
for the benefit of natural gas producers and pipeline companies. Additionally, we purchase and market third-party natural gas and NGLs as part of our gas marketing business. We are the largest
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, from Michigan and from Alberta, Canada. Our GPM assets include:

Appalachia



Michigan



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Canada



Since
MarkWest's inception in 1988, we have increased the size of our GPM asset base through expansions and strategic acquisitions. For example, we recently completed a
$33.1 million expansion of our Appalachian infrastructure that included increasing the capacity of one of our gas processing plants by 40,000 Mcf/d and almost doubling the capacity of our
fractionator. This expansion also included the acquisition and construction of additional gas processing facilities and other marketing assets. As a result of this expansion, we were able to increase
our processing volumes in Appalachia from 171,000 Mcf/d in 1999 to 276,000 Mcf/d in 2001 and our fractionation volumes from 113 million gallons in 1999 to 155 million gallons in 2001.

On
January 31, 2002, MarkWest Energy Partners, L.P., a newly formed limited partnership created to own and operate most of our gathering, processing, transportation,
storage, and fractionation assets in Appalachia and Michigan, filed a registration statement on Form S-1 with the Securities and Exchange Commission for an initial public offering.
The partnership currently anticipates offering to the public approximately 40% of the limited partner interests in the partnership. We and certain of our affiliates will own the general partner of the
partnership, as well as the remaining 60% of the limited partner interests in the form of subordinated units. The rights of the holders of subordinated units to receive distributions of cash from the
partnership are subordinated to the rights of the public unitholders to receive such distributions. Any proceeds we receive from the offering and related debt financing will be used to reduce our
outstanding debt. For financial reporting purposes, the results of operations of MarkWest Energy Partners, L.P. will be consolidated with our operating results. The completion of the offering
is subject to numerous conditions, including market conditions, and we can provide no assurance that it will be successfully completed. A registration statement relating to the proposed offering has
been filed with the Securities and Exchange Commission but has not yet become effective. The securities may not be sold, nor may offers to buy be accepted prior to the time the registration statement
becomes effective. The information contained in this Form 10-K with respect to this offering shall not constitute an offer to sell or a solicitation of an offer to buy these
securities.

Exploration and Production

Our exploration and production business includes development, exploration, acquisition and production primarily of natural gas. Our E&P segment produces natural
gas in the Rocky Mountains of southern Colorado and northern New Mexico (San Juan Basin), Michigan and, as a result of our August 2001 acquisition, Alberta, Canada. We focus on
low-risk exploitation of natural gas in existing, proven fields rather than "grass roots" exploration. Our E&P assets include:

Rocky Mountains



Michigan



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Canada



Strategy and Other Matters

Our strategy is to grow by (a) increasing the volumes of natural gas processed and volumes of NGLs produced and marketed, and (b) by increasing our
natural gas production. In our gathering, processing and marketing segment, we focus on geographic core areas where natural gas production is expected to increase, providing opportunities for
reinvestment. This focus allows us to capitalize on our infrastructure for the benefit of our customers and our shareholders. We also use exploration to enhance our gas processing business. In our
exploration and production segment, we focus on lower-risk exploitation rather than exploration. We will continue to pursue future exploration projects associated with attractive gathering
and processing opportunities for multiyear development projects.

During
the past three years, our midstream segment has accounted for a significant portion of our overall revenues: 92%, 98%, and 98% for 2001, 2000, and 1999, respectively. E&P has
accounted for the residual 8%, 2%, and 2%, respectively. These statistics are not good indicators of the growth and importance of each of our business segments for two reasons. The first is that our
gas marketing operations are a high dollar, low margin business established to supplement our GPM operations. For the three years ended December 31, 2001, 2000, and 1999, gas marketing
accounted for 38%, 42%, and 32%, respectively, of the total GPM revenues but only accounted for 4%, 1%, and 1% of the GPM gross margin (revenue less cost of sales). The other factor that impacts the
overall percentages of segment revenues to total revenues is our income mix. Several years ago, we were predominantly a processing margin based company, meaning that our income was based on the
difference between the selling price of NGLs and the cost of the replacement natural gas. This resulted in a variable margin. When NGL prices were high, relative to natural gas prices, our margin
tended to expand whereas when natural gas prices were high, relative to NGL prices, the margin tended to contract. This margin business has declined significantly over the past three years so that now
it represents only about one-third of our overall gross margin (down from 85% about five years ago).

Additionally,
with the growth in our exploration and production segment, we have effectively created a natural hedge against natural gas price fluctuations. In 2002, we plan to produce
natural gas volumes roughly equivalent to our consumption volumes in our GPM segment. For example, as natural gas prices increase, our E&P segment's operating income will increase, however our GPM
margins will be reduced, and vice versa.

b.)  Financial Information about Segments

Note 13 of the accompanying Notes to Consolidated Financial Statements contains financial information about our business segments.

c.)    Narrative Description of Business

Our business activities are segregated into two segments: (a) gathering, processing and marketing, and (b) exploration and production of natural
gas.

Gathering, Processing and Marketing

Our gathering, processing and marketing operations include the gathering and processing of natural gas and the transportation, fractionation and storage of NGLs
for natural gas producers and pipeline companies, as well as the marketing of NGLs and, to a smaller extent, natural gas. Our

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midstream operations are currently concentrated in two core areas and we are expanding into a third area. We are the largest gas processor in the northeastern United States and we process the gas or
fractionate the NGLs delivered by substantially all of the producers who deliver gas into two of the three largest gathering systems in Appalachia. We also operate in western Michigan. In
December 2001, we acquired a gathering system and compressor facility in Alberta, Canada, as well. This acquisition, along with additional capital expenditures for new gathering lines and
additional compression capabilities, will service and facilitate the expansion of our newly acquired E&P operations in Alberta, Canada.

Appalachia

The majority of the assets of our GPM segment are located in the Appalachian basin, a large natural gas producing region in the United States characterized by
long-lived reserves, modest decline rates and natural gas with high NGL content. Natural gas and NGLs produced in Appalachia typically command premium pricing given Appalachia's location
in the northeast United States where historical demand for natural gas and NGL products, particularly propane, has significantly exceeded both local production and interstate pipeline capacity during
peak winter periods. This factor has enabled NGL suppliers in Appalachia (principally MarkWest, Marathon Ashland Petroleum LLC and Dominion
Transmission, Inc.) to price their products (particularly propane) at a premium to Gulf Coast spot prices, especially during winter, the highest demand period.

While
drilling levels have declined in the past year due to lower natural gas prices, we believe that the higher relative prices for natural gas and NGLs encourage continued development
of natural gas production in the region as compared to other regions. Approximately 2,500 drilling permits for gas wells were issued in 2001 in Kentucky and West Virginia, while total production in
these two states grew approximately 38% from 1996 to 2000.

We
recently completed an expansion of our Appalachian infrastructure, which collectively increased our total natural gas design processing capacity by 72,000 Mcf/d, allowing us to grow
production from 310,000 gallons per day in 1999 to 425,000 gallons per day in 2001. Production for the first nine months of 2001 was 409,000 gallons per day and production for the last three months
was 472,000 gallons per day.

We
own and operate five gas processing facilities, one fractionation plant, an NGL pipeline and three propane terminals in Appalachia. Certain information concerning our Appalachian GPM
assets is summarized in the following tables:

|                              |  |                   |  |      |  |               |  | Year Ended December 31, 2001 | 
|----------------------------- |  | ----------------- |  | ---- |  | ------------- |  | ---------------------------- | 
|
|Boldman Extraction Plant(1)   |  | Pike County, KY   |  | 1991 |  | 70,000 Mcf/d  |  | 46,000                       | 
|Cobb Extraction Plant(2)      |  | Kanawha County,WV |  | 1968 |  | 35,000 Mcf/d  |  | 24,000                       | 
|Kenova Extraction Plant(3)    |  | Wayne County, WV  |  | 1996 |  | 160,000 Mcf/d |  | 122,000                      | 
|Kermit Dewpoint Control Plant |  | Mingo County, WV  |  | 2001 |  | 32,000 Mcf/d  |  | 30,000                       | 
|Maytown Extraction Plant      |  | Floyd County, KY  |  | 2000 |  | 55,000 Mcf/d  |  | 54,000                       | 
|Siloam Fractionation Plant(4) |  | South Shore, KY   |  | 1957 |  | 600,000 Gal/d |  | N/A                          | 

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|Storage and
Transmission Facilities |  | Location                            |  | Year
Constructed |  | Length
in
Miles |  | Design
Throughput
Capacity
(Gal/d) |  | Storage
Capacity
(Gal) |  | Sales for
the Year
Ended
December 31,
2001
(Gal)(4)
|----------------------------------- |  | ----------------------------------- |  | ---------------- |  | --------------- |  | ---------------------------------- |  | ---------------------- |  | ---------------------------------------------------
|Siloam Fractionation Storage        |  | South Shore, KY                     |  | 1957             |  | N/A             |  | N/A                                |  | 14,000,000             |  | 152,000,000                                        
|Terminal and Storage                |  | Lynchburg, VA                       |  | 1993             |  | N/A             |  | N/A                                |  | 270,000                |  | 8,400,000                                          
|Terminal and Storage                |  | Church Hill, TN                     |  | 1995             |  | N/A             |  | N/A                                |  | 240,000                |  | 2,700,000                                          
|Terminal and Storage                |  | Lordstown, OH                       |  | 2000             |  | N/A             |  | N/A                                |  | 160,000                |  | 6,100,000                                          
|Kenova to Siloam pipeline           |  | Wayne County, WV to South Shore, KY |  | 1957             |  | 36              |  | 831,000                            |  | N/A                    |  | N/A                                                
|Maytown to Kenova pipeline(5)       |  | Lincoln County to Wayne County, WV  |  | 1976             |  | 100             |  | 160,000                            |  | N/A                    |  | N/A                                                

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Our Kenova, Boldman, Cobb, Maytown and Kermit plants extract NGLs from natural gas for further separation at our Siloam fractionator. NGLs
recovered at our Boldman facility are sent to Maytown via tanker trucks. NGLs from Kenova and Maytown (including the NGLs from Boldman) are transported to our Siloam fractionator via pipeline. NGLs
from our Cobb and Kermit facilities are transported to Siloam via tanker trucks.

Our
Siloam fractionation plant receives substantially all of its extracted NGLs via pipeline or tanker truck from our five Appalachian processing plants, with the balance received from
tanker truck and rail car deliveries from other third-party NGL sources. The extracted NGLs are then separated into NGL products, including propane, isobutane, normal butane and natural gasoline. The
typical composition of the NGL throughput in our Appalachian operations has been approximately 64% propane, 18% normal butane, 6% isobutane, and 12% natural gasoline. We do not currently produce and
sell any ethane.

In
addition to processing and NGL marketing, we terminal and store NGLs in a number of NGL storage complexes in the central and eastern United States and also own and operate propane
terminals in Virginia, Tennessee and Ohio.

In
Appalachia, we have entered into operating agreements with Columbia Gas Transmission Corporation (Columbia Gas) with respect to natural gas delivered into its transmission facilities
upstream of our Kenova, Boldman and Cobb facilities. Under the terms of these operating agreements, Columbia Gas has agreed to use reasonable, diligent efforts to supply these facilities with
consistent volumes of natural gas shipped by Columbia Gas on behalf of the Appalachian producers. The initial terms of our agreements with Columbia Gas run through December 31, 2015, with
automatic annual renewals thereafter.

Our
operating agreements with Columbia Gas require us to enter into contracts with the natural gas producers whose production will be processed in our Kenova, Boldman and Cobb
facilities. We have contractual commitments with approximately 200 such producers in Appalachia. These contracts generally expire in 2009, with Columbia Natural Resources, Inc.'s (Columbia
Resources) contract expiring in 2015. Our largest producers include Columbia Resources and Equitable Production Company (Equitable). Under the provisions of our contracts with the Appalachian
producers, the

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producers have committed all of the natural gas they deliver into Columbia Gas' transmission facilities upstream of our Kenova, Boldman and Cobb facilities for processing.

Also
in Appalachia, we are a party to a gas processing agreement with Equitable relating to processing services at our Maytown processing plant and the transportation, fractionation and
marketing of the NGLs extracted there. Under this agreement, we earn a fee for processing, transportation and fractionation services, as well as a percentage of the proceeds from the sale of NGL
products produced. The initial term of this contract runs through January 1, 2015.

As
compensation for providing processing services to the Appalachian producers at our Kenova, Boldman, and Cobb facilities, we earn both a fee and the NGLs produced. In return, we are
required to replace, in dry natural gas, the Btu value of the NGLs extracted. This Btu replacement obligation is referred to in the industry as a keep-whole arrangement. In
keep-whole arrangements, our principal cost is the replacement of the Btus extracted from the gas stream in the form of NGLs or consumed as fuel during processing with dry gas of an
equivalent Btu content. Except in rare cases, the value of the NGLs extracted is greater than the cost of replacing those Btus with dry gas, resulting in positive operating margins under these
contracts. In the event natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, the cost of keeping the producer "whole" results in operating losses. This latter pricing
environment existed from December 2000 to February 2001 and adversely impacted our operating results, which were partially offset by favorable hedge positions.

We
now use our natural gas production to hedge our cost of natural gas under these keep-whole arrangements. In August 2001, we gained significant additional natural
gas production with our acquisition of two Canadian natural gas producers. See "Exploration and Production, Canada" below. We believe that our current natural gas production should be sufficient to
provide a hedge against the natural gas cost in our keep-whole obligations, even in a pricing environment similar to that experienced in late 2000 and early 2001. Our expected 2002 natural
gas production is approximately equal to the quantity of natural gas that we expect to return to producers under our keep-whole contracts. In addition, we are making a conscious effort to
increase fee-based GPM contract volumes.

If
the initial public offering of MarkWest Energy Partners, L.P. is completed, the partnership will perform gathering, processing, transportation, fractionation and storage services for
us for a fee pursuant to the terms of our operating agreements with the partnership. Under those agreements, we will retain all the benefits and associated risks of our keep-whole
contracts with producers. Our NGL and gas marketing operations are not being contributed to MarkWest Energy Partners, L.P.

In
2001, we sold 152 million gallons of our Siloam production through the marketing operations of our GPM segment. We ship NGL products from Siloam by truck, rail and barge. We
also ship propane from our Siloam facility, as well as propane purchased from third parties, to our wholesale propane terminals and to third-party facilities for sale to customers. Our marketing
customers include propane retailers, refineries, petrochemical plants and NGL product resellers. Most marketing sales contracts have terms of one year or less, are made on best efforts basis and are
priced in reference to Mt. Belvieu index prices or plant posting prices. In addition to our NGL product sales, our marketing operations are also responsible for the purchase of natural gas delivered
for the account of producers pursuant to its keep-whole processing contracts.

We
strive to maximize the value of our NGL output by marketing directly to our customers. We minimize the use of third-party brokers and instead support a direct marketing staff focused
on multistate and independent dealers. Additionally, we use our own trailer and railcar fleet, as well as our own terminals and owned and leased storage facilities, to enhance supply reliability to
our customers. All of these efforts have allowed us to maintain premium pricing for the majority of our NGL products compared to Gulf Coast spot prices. Our sales of NGL products are based on spot
prices at the time the NGL products are sold or are hedged. Spot market prices are based upon prices and volumes negotiated for short terms, typically 30 days. As market conditions permit, we
hedge our price risk as

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described in Item 7A and Note 8 in the Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

In
1998, we started a natural gas marketing group to provide, primarily in Appalachia, more services to natural gas producers, source new gas for our facilities, minimize our replacement
Btu cost, and assist with our business development efforts. Our natural gas marketing operations are fundamentally high dollar, low margin business established to supplement our GPM operations.
Consequently, a significant percentage of our overall revenues stem from gas marketing, but the contribution to our gross margin is modest. For the years ended December 31, 2001, 2000, and
1999, 38%, 42%, and 32%, respectively, of gathering, processing and marketing revenue stemmed from gas marketing. However, the gas marketing gross margin (revenue less cost of sales) as a percent of
GPM gross margin was just 4%, 1%, and 1%, respectively.

Expansion Projects in Appalachia

We recently completed a $33.1 million expansion of our Appalachian infrastructure, which included:



As
a result of this expansion, we have increased our production of NGLs from 113 million gallons per year in 1999 to approximately 155 million gallons per year in 2001.

Michigan

Our operations in western Michigan consist of a pipeline and processing plant. Our gas gathering pipeline gathers and transports sour gas (includes sulfur)
produced by third parties in Oceana, Mason and Manistee Counties for sulfur removal at a treatment plant that is owned and operated by Shell Offshore, Inc. (Shell). Our gathering pipeline
serves approximately 30 wells and 13 producers in this three county area. Our Fisk processing plant is also operated by Shell and is located adjacent to its treatment plant. The Fisk plant processes
all of the natural gas gathered by our gathering pipeline and produces propane and butane-natural gasoline mix.

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Certain information concerning our Michigan GPM assets is summarized in the following table:

|                                    |  |                                         |  |      |     |        |  | Year Ended December 31, 2001
|----------------------------------- |  | --------------------------------------- |  | ---- | --- | ------ |  | ----------------------------
|
|
|90-mile sour gas gathering pipeline |  | Manistee, Mason and Oceana Counties, MI |  | 1996 | (1) | 35,000 |  | 8,800                       
|Fisk Gas Plant                      |  | Manistee County, MI                     |  | 1998 |     | 35,000 |  | 8,800                       

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We currently process natural gas in western Michigan under a number of third-party agreements containing both fee and
percent-of-proceeds components. Under these agreements, production from all of the acreage adjacent to our pipeline and processing facility is dedicated to our gathering and
processing facilities. Under the fee component of these agreements, which represent approximately two-thirds of our gross margin in Michigan, producers pay us a fee to transport and treat
their gas. Under the percent-of-proceeds component, we retain a portion of the proceeds from the sale of the NGLs as compensation for the processing services provided. Our
propane and butane-natural gasoline production is usually sold at the plant.

We
believe there will continue to be increased development in this region of Michigan in part because 3D seismic technology may serve to significantly improve drilling success rates. For
example, we recently used 3D seismic to identify and drill two successful wells that commenced production in early 2002. We are currently sponsoring two additional 3D seismic programs for the
evaluation of additional drilling opportunities in the area served by our pipeline.

Our
GPM assets in Michigan are among the assets that we plan to contribute to MarkWest Energy Partners, L.P. in connection with its initial public offering.

Canada

Our Canadian midstream operation is in its infancy. Our Canadian acquisition in August 2001 provided us with the opportunity to create a gathering,
processing and marketing operation not only for our own natural gas volumes but also for third-party producers. We acquired a compressor station in late December 2001 and it has been connected
to a gathering system we had already begun constructing. The compressor station we acquired includes six miles of pipelines and compression facilities that was expanded to 10,000 Mcf/d in early 2002.
The gathering system, that is now nearly complete, will include 23 miles of pipelines that gather 17,000 Mcf/d and includes dehydration and compression facilities. The gathering system will serve
seven townships and allow rapid connection of new gas wells to the sales line as we continue our growth in this area. This new system is part of a larger strategy of building a gathering system that
we anticipate growing to a capacity of 32,000 Mcf/d by year-end 2002, allowing our E&P segment and third-party volumes to grow in tandem as we ramp up our production of natural gas.
Including our initial investment, this project is expected to require US$7 million in total capital investment by the end of 2002.

Our
GPM assets in Canada are not among the assets that we plan to contribute to MarkWest Energy Partners, L.P. in connection with its initial public offering.

Exploration and Production

Our E&P activities are concentrated in central and southeastern Alberta, Canada, in the Rocky Mountains of southern Colorado and northern New Mexico (San Juan
Basin), and Michigan.

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Canada

We acquired our operations in Canada in August 2001 for US$50 million. Our focus in Canada is on the development and production of natural gas in
southeast and central Alberta. The majority of existing wells are approximately 3,000 to 3,500 feet deep, with relatively high initial production rates. We have budgeted US$10 million for
drilling 40 net wells in 2002 and conducting additional seismic analysis.

Between
the date of the acquisition, August 2001, and the end of the year, we drilled and completed sixteen gross wells in Canada. During the third quarter, we drilled and
completed nine gross wells at a cost of US$1.6 million. We drilled and cased seven additional gross wells during the fourth quarter at a cost of US$1.8 million. At the end of the year,
five additional wells remained unconnected. As a result of this drilling program, our February 2002 production rate increased to more than 20,200 Mcfe/d compared to our average 2001 production rate of
13,500 Mcfe/d since the date of the acquisition.

Our
business strategy will continue to focus on land positions with high working interests and operatorship in geographic regions of Alberta that offer potential for
multi-zone natural gas production.

Rocky Mountains

We have focused our exploration and production business in the San Juan Basin. In January 2001, our acquisition of additional coal bed methane properties
and gathering systems in New Mexico's San Juan Basin added another 1,200 Mcf/d of production. This acquisition, along with our 2001 capital expenditure program of $3.0 million, increased our
average net natural gas produced for the year 2001 to 5,800 Mcf/d from 3,300 Mcf/d in 2000. Our 2001 year end production exit rate was more than 6,200 Mcf/d.

Michigan

In eastern Michigan, we contracted with a producer to provide gas processing services for a long-dormant sour (contains sulfur) gas formation. We also
have a 25% working interest in the field. In
the first phase of the project, completed in third quarter 2000, we have successfully recompleted the Sims 1-7 well, constructed a well facility, modified an existing gas plant and
constructed a pipeline. The Au Gres project continued to grow with the recompletion of the second well that was connected in the third quarter of 2001. A third well is currently in progress.
    Prior to the Sims 1-7, these wells never produced from this formation due to the lack of infrastructure.

In
western Michigan, we have a 10% to 15% working interest in two new wells that began production in March 2002. We will also earn a shut-in well through construction
of a gathering line. A 3-D seismic program now underway in western Michigan, adjacent to our pipeline, is expected to add more drilling sites and interest in that area.

Reserves

Cawley, Gillespie & Associates, Inc., and Gilbert, Laustsen Jung Associates Ltd., independent reservoir engineers, have reviewed our
estimates of United States and Canadian proved reserves, respectively, projected future production and estimated future net revenues from production of proved reserves. The estimates were based upon a
review of production histories and other geologic, economic,

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ownership and engineering data provided by or available to us. The following table sets forth our natural gas and liquid reserves for the years ended December 31, 2001, 2000 and 1999:

|                                                                                                                       |                        | United States  |        |        |        |       
|---------------------------------------------------------------------------------------------------------------------- | ---------------------- | -------------- | ------ | ------ | ------ | ------
|
|
|
|Estimated proved reserves                                                                                              |                        |                |        |        |        |       
|                                                                                                                       | Natural gas (MMcf)     |                |        | 32,720 |        |       
|                                                                                                                       | Oil and liquids (MBbl) |                |        |       |        |       
|                                                                                                                       |                        | Total MMcfe(2) |        |        | 32,720 |       
|Proved developed reserves (MMcfe)(3)                                                                                   |                        |                | 22,114 |        |        | 22,804
|Natural gas price as of December 31 ($/Mcf)                                                                            |                        | $              | 2.30   |        | $      | 8.56  
|Oil and liquids price as of December 31 ($/Bbl)                                                                        |                        | $              |       |        | $      | 32.34 
|Present value of estimated future net revenues before future income taxes, discounted at 10%                           |                        | $              | 16,122 |        | $      | 97,953
|Present value of price hedges not included in above future net revenues, before future income taxes, discounted at 10% |                        | $              |       |        | $      |      

---

Proved reserves at year-end 2001 were 71 Bcfe of natural gas compared to 35 Bcfe at year-end 2000. The SEC
pre-tax net present value of the proved reserves at year end 2001, discounted at 10% (pre-tax PV10), was $58.9 million compared to $98.0 million reported at
year-end 2000. The 2001 present value
does not include $7.8 million of pre-tax PV10 value due to price hedges in place at December 31, 2001. The 2000 present value reflects the high pricing environment in
existence at year-end 2000. Reserve values were calculated according to SEC guidelines based on constant prices and costs using year-end NYMEX Henry Hub spot market index of
$2.65 per MMBtu adjusted to El Paso/San Juan index of $2.39 per Mcfe and $2.19 per Mcfe for Canada for 2001 and $9.52 per Mcfe and $8.56 per Mcfe, respectively, for 2000.

To
accomplish uniformity in the reporting of reserves for comparison purposes, the SEC requires that the pre-tax PV10 of future net revenues be calculated using a spot
year-end pricing and costs, with no future escalation of these factors. Because these assumptions are not intended to be predictions of future commodity prices or costs, the calculated
values are not intended to be indicative of the market value of these assets.

There
are uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors
beyond our control. The reserve data presented represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of gas that cannot be measured. The
accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates made by different engineers often vary from one
another. Additionally, results of drilling, testing and production subsequent to the date of any estimate may justify revision of the estimate, either upward or downward, and such revision may be
material. Accordingly, reserve estimates often differ from the quantities of gas reserves and the present value of those reserves are based upon certain assumptions, including prices, future
production levels and cost, that may not prove correct over time.

13

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See
related information in Note 17 of the accompanying Notes to Consolidated Financial Statements included elsewhere in this Form 10-K.

Production

The following table sets forth information regarding net oil and natural gas production, average sales prices and other production information. Average sales
prices for natural gas, oil and liquids are inclusive of hedging gains and losses for the years ended December 31, 2001, 2000 and 1999.

|                                            |                         | United States  |      |      |       |     
|------------------------------------------- | ----------------------- | -------------- | ---- | ---- | ----- | ----
|
|
|
|Quantities produced and sold                |                         |                |      |      |       |     
|                                            | Natural gas (MMcf)      |                |      | 984  |       |     
|                                            | Oil and liquids (MBbl)  |                |      |     |       |     
|                                            |                         | Total MMcfe(2) |      |      | 984   |     
|                                            |                         | Average Mcfe/d |      |      | 2,700 |     
|Average sales price                         |                         |                |      |      |       |     
|                                            | Natural gas ($/Mcf)     |                | $    | 1.83 |       | $   
|                                            | Oil and liquids ($/Bbl) |                |      |     |       | $   
|Average production (lifting) costs ($/Mcfe) |                         | $              | 0.70 |      | $     | 1.26

---

Productive Wells

The following table sets forth information regarding the number of productive wells in which we held a working interest at December 31, 2001.

|              |                | Productive Wells(1)
|------------- | -------------- | -------------------
|
|
|United States |                |                    
|              | San Juan Basin |                    
|              | Michigan       |                    
|              |                |                    
|              |                | Total              
|Canada        |                |                    
|              | Alberta        |                    
|              |                |                    
|Total wells   |                | 188                
|              |                |                    

---

14

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Drilling and Recompletion Activity

The following table sets forth our gross and net interest in exploration and developmental wells drilled and wells recompleted during the periods indicated.

|                  |                 | United States     |       |     |     |     
|----------------- | --------------- | ----------------- | ----- | --- | --- | ----
|
|
|Gross wells(2)    |                 |                   |       |     |     |     
|                  | Development     |                   |       |     |     |     
|                  |                 | Natural gas       |       | 1   |     | 1   
|                  |                 | Oil               |       |    |     |    
|                  |                 | Non-productive(3) |       |    |     |    
|                  |                 |                   |       |     |     |     
|                  |                 |                   | Total |     | 1   |     
|                  |                 |                   |       |     |     |     
|                  | Exploratory     |                   |       |     |     |     
|                  |                 | Natural gas       |       |    |     | 1   
|                  |                 | Oil               |       |    |     |    
|                  |                 | Non-productive    |       | 3   |     | 4   
|                  |                 |                   |       |     |     |     
|                  |                 |                   | Total |     | 3   |     
|                  |                 |                   |       |     |     |     
|                  | Recompletion(5) |                   |       |     |     |     
|                  |                 | Natural gas       |       | 9   |     | 8   
|                  |                 | Oil               |       |    |     |    
|                  |                 | Non-productive    |       |    |     |    
|                  |                 |                   |       |     |     |     
|                  |                 |                   | Total |     | 9   |     
|                  |                 |                   |       |     |     |     
|Total gross wells |                 | 13                |       | 14  |     | 18  
|                  |                 |                   |       |     |     |     
|Net wells(4)      |                 |                   |       |     |     |     
|                  | Development     |                   |       |     |     |     
|                  |                 | Natural gas       |       | 0.2 |     | 0.5 
|                  |                 | Oil               |       |    |     |    
|                  |                 | Non-productive    |       |    |     |    
|                  |                 |                   |       |     |     |     
|                  |                 |                   | Total |     | 0.2 |     
|                  |                 |                   |       |     |     |     
|                  | Exploratory     |                   |       |     |     |     
|                  |                 | Natural gas       |       |    |     | 0.3 
|                  |                 | Oil               |       |    |     |    
|                  |                 | Non-productive    |       | 0.3 |     | 1.6 
|                  |                 |                   |       |     |     |     
|                  |                 |                   | Total |     | 0.3 |     
|                  |                 |                   |       |     |     |     
|                  | Recompletion    |                   |       |     |     |     
|                  |                 | Natural gas       |       | 5.7 |     | 3.9 
|                  |                 | Oil               |       |    |     |    
|                  |                 | Non-productive    |       |    |     |    
|                  |                 |                   |       |     |     |     
|                  |                 |                   | Total |     | 5.7 |     
|                  |                 |                   |       |     |     |     
|Total net wells   |                 | 6.2               |       | 6.3 |     | 10.9
|                  |                 |                   |       |     |     |     

---

15

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Acreage

The following table sets forth the leasehold acreage held by MarkWest at December 31, 2001.

|              |                | Developed Acreage(1) |        | Undeveloped Acreage(2)
|------------- | -------------- | -------------------- | ------ | ----------------------
|
|United States |                |                      |        |                       
|              | San Juan Basin |                      | 12,560 |                       
|              | Michigan       |                      | 2,148  |                       
|              |                |                      |        |                       
|              |                | Total                |        | 14,708                
|              |                |                      |        |                       
|Canada        |                |                      |        |                       
|              | Alberta        |                      | 56,487 |                       
|              |                |                      |        |                       
|Total Acreage |                | 71,195               |        | 51,887                
|              |                |                      |        |                       

---

We have a number of farm-in agreements in Canada where we are able to earn additional leasehold acreage through drilling and 3D
seismic programs. These agreements would allow us to earn up to an additional 58,805 gross and 46,536 net acres through the years 2003.

Factors Affecting our Operations

Seasonality

A substantial portion of our GPM revenues and, as a result, our GPM gross margins, remains dependent upon the volume and sales price of NGL products, particularly
propane. The volume and sales price of NGL products fluctuate with the winter weather conditions and other supply and demand determinants. The strongest demand for propane and the highest propane
sales margins generally occur during the winter heating season. As a result, we recognize a substantial portion of our annual income from our GPM segment during the first and fourth quarters of the
year. No material seasonality is experienced in our E&P segment.

16

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Competition

In our GPM business, we face competition 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 our ability to obtain a satisfactory price for products recovered. Competitive factors affecting our fractionation services include availability of capacity, proximity
to supply and to industry marketing centers, cost efficiency, and reliability of service. Competition for customers is based primarily on price, delivery capabilities, flexibility, and maintenance of
quality customer relationships.

In
competing for new GPM business opportunities, we face strong competition in acquiring natural gas supplies and competing for fees for service. Our competitors include:



In
the exploration and production segment, we face competition in the acquisition of leases and producing properties. Competition comes in the form of other companies with existing
operations in our areas of focus as well as those companies wishing to buy properties as an entry strategy into such areas. Our competitors range in size from small independent operators to large
integrated oil companies. We believe we enjoy certain competitive advantages by virtue of our area knowledge and existing field operating infrastructure, making us a logical buyer for certain
properties.

Operational Risks and Insurance

Our operations are subject to the usual hazards incident to the exploration, production, gathering and processing of natural gas and the transmission,
fractionation and storage of NGLs, such as explosions, product spills, leaks, emissions and fires. These hazards can cause personal injury and loss of life, severe damage to and destruction of
property and equipment, and pollution or other environmental damage, and may result in curtailment or suspension of operations at the affected facility.

We
maintain general public liability, property and business interruption insurance in amounts that we consider to be adequate for such risks. Such insurance is subject to deductibles
that we consider reasonable and not excessive. Consistent with insurance coverage generally available to the industry, our insurance policies provide coverage for losses or liabilities related to
sudden occurrences of pollution or other environmental damage.

The
occurrence of a significant event that we are not fully insured or indemnified against, and/or the failure of a party to meet its indemnification obligations to us, could materially
and adversely affect our operations and financial condition. Moreover, we cannot provide assurance that we will be able to maintain adequate insurance in the future at rates we consider reasonable. To
date, however, we have not experienced material uninsured losses or any difficulty in acquiring insurance coverage in amounts we believe to be adequate.

Government Regulation

United States

In the Michigan area of our gathering, processing and marketing segment, we own and operate a gathering pipeline in conjunction with our processing plant. Under
the Natural Gas Act of 1938,

17

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facilities that have as their "primary function" the performance of gathering activities and are not owned by interstate gas pipeline companies are wholly exempt from Federal Energy Regulatory
Commission jurisdiction. State and local regulatory authorities oversee intrastate gathering and other natural gas pipeline operations. The Michigan Public Service Commission (MPSC) regulates the
construction, operation, rates and safety of certain natural gas gathering and transmission pipelines pursuant to state regulatory statutes. We conduct gas pipeline operations in Michigan through an
affiliate, which is subject to this regulation by the MPSC. The design, construction, operation and maintenance of the pipeline is also subject to safety regulations.

Natural
gas exploration and production operations are subject to various types of regulation at the federal, state and local levels. The effect of these regulations may limit the amount
of gas available to our systems or that we can produce from our wells. They also substantially affect the cost and profitability of conducting natural gas exploration and production activities.

Our
oil and natural gas operations are regulated by administrative agencies under statutory provisions of the states where such operations are conducted and by certain agencies of the
federal government for operations on federal oil and gas leases. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the
exploration for and production of crude oil and natural gas. These statutes include the regulation of the size of drilling and spacing units and the number of wells that may be drilled in an area and
the unitization or pooling of oil and natural gas properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, typically prohibit the venting
or flaring of natural gas, and impose certain requirements regarding the apportionment of production from fields and individual wells. The effect of these regulations may limit the amount of oil and
natural gas we can produce from our wells and to limit the number of wells or location at which we can drill. State commissions establish rules for reclamation of sites, plugging bonds, reporting and
other matters.

Increasingly,
a number of city and county governments have enacted oil and natural gas regulations that have increased the involvement of local governments in the permitting of oil and
natural gas operations and impart additional restrictions or conditions on the conduct of operators to mitigate the impact of operations on the local community. These local restrictions have the
potential to delay and increase the cost of oil and natural gas operations.

Canada

The oil and natural gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. Federal authorities do not
regulate the price of oil and gas in export trade but instead rely on market forces to establish these prices. Legislation exists that regulates the quantities of oil and natural gas that may be
removed from the provinces and exported from Canada. We do not expect that any of these controls and regulations will affect us in a manner significantly different than other oil and natural gas
companies of similar size.

The
province in which we operate has legislation and regulation that govern land tenure, royalties, production rates and environmental protection. The royalty regime in the province in
which we operate is a significant factor in the profitability of our production. Crown royalties are determined by government regulation and are typically calculated as a percentage of production. The
value of the production and the rate of royalties payable depends on prescribed reference prices, well productivity, geographical location and the type or quality of the product produced.

In
Alberta, we are entitled to a credit against Crown royalties on most of the properties in which we have an interest in by virtue of the Alberta Royalty Tax Credit (ARTC). The credit
is determined by applying a rate to a maximum of CDN$2.0 million of Crown royalties payable in Alberta for each company or associated group of companies. The rate is a function of the royalty
tax credit par prices,

18

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which is determined quarterly by the Alberta Department of Energy. The rate ranges from 25% to 75% depending upon petroleum prices for the previous quarter.

The
Investment Canada Act requires Government of Canada approval, in certain cases, of the acquisition of control of a Canadian business by an entity that is not controlled by Canadians.
In certain circumstances, the acquisition of natural resource-related properties may be considered to be a transaction that constitutes an acquisition of control of a Canadian business requiring
Government of Canada approval. The Act requires notification of the establishment of new unrelated businesses in Canada by entities not controlled by Canadians, but does not require Government of
Canada approval except when the new business is related to Canada's cultural heritage or national identity.

Environmental Matters

United States

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

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

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

Canada

In Canada, the oil and natural gas industry is currently subject to environmental regulations pursuant to provincial and federal legislation. Environmental
legislation provides for restrictions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires
that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such regulations may result in the imposition of fines and penalties, the suspension
of operations and potential civil liability. The Environmental Protection and Enhancement Act imposes environmental standards and requires compliance with various legislative criteria including
reporting and monitoring in Alberta. The Alberta Energy and Utility Board, pursuant to its governing legislation, also plays a role with respect to the regulation of environmental impacts of oil and
gas activities.

19

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Employee Safety

The workplaces associated with the processing and storage facilities and the pipelines we operate are also subject to the requirements of the federal Occupational
Safety and Health Act, or OSHA, and comparable state statues 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 our operations and that we provide this information to our 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 more strict over time, thereby resulting in increased compliance expenditures. While we cannot accurately
estimate these expenditures at this time, we do not expect such expenditures will have a material adverse effect on our results of operations.

Employees

As of December 31, 2001, we had 131 employees. At our fractionation facility in South Shore, Kentucky, 15 employees are represented by the Paper, Allied
Industrial, Chemical, and Energy Workers International Union Local 5-0372. We entered into our collective bargaining agreement with this Union on June 29, 2001 and it expires in
June 2004. The agreement covers only hourly, non-supervisory employees. We consider our labor relations to be good.

d.)  Financial Information about Geographic Areas

Prior to the Canadian acquisition that we completed in August 2001, MarkWest operated only within the United States. For the year ended,
December 31, 2001, our selected financial information about the United States and Canada follows:

|                                             |  | United
States |         | Canada |   | Total 
|-------------------------------------------- |  | ------------- | ------- | ------ | - | ------
|Balance Sheet Data:                          |  |               |         |        |   |       
|Working capital                              |  | $             | 19,370  |        | $ | (5,872
|Plant, property and equipment, gross         |  |               | 148,892 |        |   | 90,028
|Plant, property and equipment, net           |  |               | 114,237 |        |   | 86,616
|Total assets                                 |  |               | 183,990 |        |   | 66,521
|Long-term debt                               |  |               | 79,500  |        |   | 33,321
|Statement of Operations Data:                |  |               |         |        |   |       
|Revenues                                     |  | $             | 183,443 |        | $ | 5,075 
|Cost of sales                                |  |               | 142,616 |        |   | 431   
|Operating expenses                           |  |               | 17,498  |        |   | 947   
|Selling, general and administrative expenses |  |               | 7,918   |        |   | 459   
|Depreciation, depletion and amortization     |  |               | 6,882   |        |   | 3,445 
|                                             |  |               |         |        |   |       
|Income from operations                       |  | $             | 8,529   |        | $ | (207  
|Net income                                   |  | $             | 2,761   |        | $ | 49    

Forward-Looking Information

Statements included in this Annual Report on Form 10-K and documents incorporated by reference to this report that are not historical facts are
forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. We use
words such as "may," "believe," "estimate," "expect,"

20

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"plan," "intend," "project," "anticipate," and similar expressions to identify forward-looking statements. We have based these forward-looking statements on our current expectations and projections
about future events, activities or developments. Our actual results could differ materially from those discussed in our forward-looking statements. Forward-looking statements include statements
relating to, among other things:



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



21

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Forward-looking
statements involve many uncertainties that are beyond our ability to control. In many cases, we cannot predict what factors would cause actual results to differ
materially from those indicated by the forward-looking statements.

ITEM 3. LEGAL PROCEEDINGS

Reference is made to Note 15 of our Consolidated Financial Statements in Item 8 of this Form 10-K.

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

There were no matters submitted to a vote of security holders during the quarter ended December 31, 2001.

PART II

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

The American Stock Exchange began trading shares of MarkWest Hydrocarbon, Inc. under the ticker symbol MWP on Friday, May 12, 2000. Our stock
formerly traded on the American Stock Exchange under the ticker symbol NRG through May 11, 2000.

As
of December 31, 2001, there were 8,504,297 shares of common stock outstanding held by approximately 650 holders of record. The following table sets forth quarterly high and low
sales prices as reported by the American Stock Exchange for the periods indicated.

|               |  | 2001 |        | 2000
|-------------- |  | ---- | ------ | ----
|
|First Quarter  |  | $    | 11.500 |     
|Second Quarter |  |      | 8.550  |     
|Third Quarter  |  |      | 8.550  |     
|Fourth Quarter |  |      | 7.200  |     

We
have never paid dividends on our common stock and we anticipate that, for the foreseeable future, we will continue to retain earnings for use in the operation of our business. Payment
of cash dividends in the future will depend on our earnings; financial condition; contractual restrictions, if any, including those under its bank line of credit; restrictions imposed by law and other
factors deemed relevant by our Board of Directors.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected consolidated historical financial and operating data for MarkWest. Certain prior year amounts have been reclassified to
conform to the 2001 presentation. The selected consolidated statement of operations and balance sheet data for the years ended December 31, 2001, 2000, and 1999, and as of December 31,
2001 and 2000, are derived from, and are qualified by reference to, our audited Consolidated Financial Statements included elsewhere in this Form 10-K. The selected consolidated
statement of operations and balance sheet data set forth below for the years

22

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ended December 31, 1998 and 1997, and as of December 31, 1999, 1998 and 1997, have been derived from audited financial statements not included in this Form 10-K. You
should read this in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our Consolidated Financial Statements and related Notes included in
this Form 10-K.

|                                                                     |                                              | Year Ended December 31,  |                           
|-------------------------------------------------------------------- | -------------------------------------------- | ------------------------ | --------------------------
|
|
|Statement of Operations Data:                                        |                                              |                          |                           
|Revenues(1)                                                          |                                              | $                        | 188,518                   
|Operating expenses:                                                  |                                              |                          |                           
|                                                                     | Cost of sales                                |                          |                           
|                                                                     | Operating expenses                           |                          |                           
|                                                                     | Selling, general and administrative expenses |                          |                           
|                                                                     | Depreciation and depletion                   |                          |                           
|                                                                     | Gain on sale of operating asset              |                          |                           
|                                                                     |                                              |                          |                           
|                                                                     |                                              | Total operating expenses |                           
|                                                                     |                                              |                          |                           
|                                                                     |                                              |                          | Income from operations    
|Other income and expense:                                            |                                              |                          |                           
|                                                                     | Interest income                              |                          |                           
|                                                                     | Interest expense                             |                          |                           
|                                                                     | Gain on sale of non-operating asset          |                          |                           
|                                                                     | Other income (expense)                       |                          |                           
|                                                                     |                                              |                          |                           
|                                                                     |                                              |                          | Income before income taxes
|Provision (benefit) for income taxes                                 |                                              |                          | 1,581                     
|                                                                     |                                              |                          |                           
|Net income (loss)                                                    |                                              | $                        | 2,810                     
|                                                                     |                                              |                          |                           
|Basic earnings per share(2),(3)                                      |                                              | $                        | 0.33                      
|Earnings per share assuming dilution(2),(3)                          |                                              |                          | 0.33                      
|Weighted average shares outstanding                                  |                                              |                          | 8,478                     
|assuming dilution                                                    |                                              |                          | 8,499                     
|Other Financial Data:                                                |                                              |                          |                           
|Adjusted EBITDA(4)                                                   |                                              | $                        | 18,418                    
|Cash operating margin(5)                                             |                                              |                          | 27,026                    
|Cash flows from operating activities, before working capital changes |                                              |                          | 16,057                    
|Capital expenditures and acquisitions                                |                                              |                          | 78,297                    
|Balance Sheet Data (as of December 31):                              |                                              |                          |                           
|Working capital(6)(7)                                                |                                              | $                        | 13,498                    
|Property and equipment, gross                                        |                                              |                          | 238,920                   
|Property and equipment, net                                          |                                              |                          | 200,853                   
|Total assets                                                         |                                              |                          | 250,511                   
|Long-term debt(7)                                                    |                                              |                          | 104,850                   
|Stockholders' equity                                                 |                                              |                          | 69,033                    

23

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|                                    |                                       | Year Ended December 31,
|----------------------------------- | ------------------------------------- | -----------------------
|
|Operating Data:                     |                                       |                        
|Gathering, processing and marketing |                                       |                        
|Appalachia:                         |                                       |                        
|                                    | NGL productionSiloam plant (gallons) |                        
|                                    | NGL salesSiloam plant (gallons)      |                        
|Michigan:                           |                                       |                        
|                                    | Pipeline throughput (Mcf/d)           |                        
|                                    | NGL sales (gallons)                   |                        
|Exploration and production          |                                       |                        
|                                    | Natural gas produced (Mcf/d)          |                        

---

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis relates to factors that have affected our consolidated financial condition and results of operations for the three years
ended December 31, 2001, 2000 and 1999. Certain prior year amounts have been reclassified to conform to the presentation used in 2001. Reference should also be made to our Consolidated
Financial Statements and related Notes thereto and the Selected Financial Data included in this Form 10-K.



Gathering, processing and marketing revenue.Gathering, processing and marketing revenue was $173.9 million for the
year ended December 31, 2001 compared to $217.6 million for the year ended
December 31, 2000, a decrease of $43.7 million, or 20%. Revenue was lower in 2001 than in 2000 primarily due to:



24

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Exploration and production revenue.Exploration and production revenue was $14.6 million for the year ended
December 31, 2001 compared to $4.2 million for the year ended December 31, 2000, an increase of $10.5 million, or 252%. Revenue was higher in 2001 than in 2000 primarily
due to:



Cost of sales.Cost of sales were $143.0 million for the year ended December 31, 2001, compared to
$173.5 million for the year ended December 31, 2000, a decrease of $30.4 million, or 18%. Cost of sales were lower in 2001 primarily due to:



Operating expenses.Operating expenses were $18.4 million for the year ended December 31, 2001, compared to
$17.3 million for the year ended December 31, 2000, an increase of $1.1 million, or 6%. The increase in operating expenses during 2001 is principally attributable to our growing
exploration and production business segment.

Selling, general and administrative expenses.Selling, general and administrative expenses were $8.4 million for the
year ended December 31, 2001, compared to $8.8 million for the year ended December 31, 2000, a decrease of $0.4 million, or 4%.

Depreciation and depletion.Depreciation and depletion were $10.3 million for the year ended December 31, 2001,
compared to $5.5 million, for the year ended December 31, 2000, an increase of $4.8 million, or 88%. The increase was principally caused by (a) several Appalachian
expansion projects which commenced operations in 2000 and 2001, and (b) the depletion of reserves through increased production from our 2001 Canadian acquisition and our capital programs in
Canada, the Rocky Mountains and Michigan.

Interest expense.Interest expense was $3.8 million for the year ended December 31, 2001, compared to
$3.9 million for the year ended December 31, 2000, a decrease of $0.1 million, or 3%. Despite a significant increase in debt during 2001 due to our Canadian acquisition, interest
expense decreased due to decreasing interest rates throughout 2001.

25

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Gain on sale of non-operating assets.We sold a non-operating asset for a $1.0 million gain in
2000. No significant non-operating assets were sold in 2001.

Provision for income taxes.Provision for income taxes for the year ended December 31, 2001, was $1.6 million,
compared to $4.9 million for the year ended December 31, 2000, a decrease of $3.3 million, or 68%. Provision for income taxes decreased principally due to lower income before
income taxes in 2001.

Net income.Net income for the year ended December 31, 2001, was $2.8 million, compared to $8.9 million
for the year ended December 31, 2000, a decrease of $6.1 million, or 68%. Net income decreased principally as a result of our average Appalachian processing margin returning to near
historically average levels in 2001 from above average levels in 2000.



Gathering, processing and marketing revenue.Gathering, processing and marketing revenue was $217.6 million for the
year ended December 31, 2000, compared to $105.2 million for the year ended December 31, 1999, an increase of $112.4 million, or 107%. This increase was principally
attributable to:



Exploration and production revenue.Exploration and production revenue was $4.2 million for the year ended
December 31, 2000 compared to $1.9 million for the year ended December 31, 1999, an increase of
$2.3 million, or 124%. Revenue was higher in 2001 than in 2000 primarily due to a 52% increase in the volume of natural gas produced and sold. Production increased because of our capital
program.

Cost of sales.Cost of sales were $173.5 million for the year ended December 31, 2000, compared to
$77.5 million for the year ended December 31, 1999, an increase of $95.9 million, or 124%. The increase was primarily attributable to:



26

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Operating expenses.Operating expenses were $17.3 million for the year ended December 31, 2000, compared to
$12.7 million for the year ended December 31, 1999, an increase of $4.6 million, or 37%. The increase is primarily attributable to:



Selling, general and administrative expenses.Selling, general and administrative expenses were $8.8 million for the
year ended December 31, 2000, compared to $7.0 million for the year ended December 31, 1999, an increase of $1.8 million, or 25%. Selling, general and administrative
expenses increased primarily in support of the new Appalachian facilities and rent for office space; MarkWest Hydrocarbon sold its corporate headquarters and leased back its office space commencing in
February 2000.

Depreciation and depletion.Depreciation and depletion were $5.5 million for the year ended December 31, 2000
compared to $4.8 million for the year ended December 31, 1999, an increase of $0.7 million, or 14%. Depreciation expense increased as a result of the Appalachian expansion during
2000.

Gain on sale of operating asset.In 1999, we sold an asset for a $2.5 million gain. In 2000, no significant operating
assets were sold.

Interest expense.Interest expense was $3.9 million for the year ended December 31, 2000 compared to
$3.0 million for the year ended December 31, 1999, an increase of $0.9 million, or 31%. The increase was principally attributable to the amortization of deferred financing costs.

Provision for income taxes.Provision for income taxes for year ended December 31, 2000, was $4.9 million,
compared to $1.7 million for the year ended December 31, 1999, an increase of $3.2 million, or 187%. Provision for income taxes increased principally due to higher income before
income taxes.

27

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Net income.Net income for the year ended December 31, 2000, was $8.9 million, compared to $2.8 million
for the year ended December 31, 1999, an increase of $6.1 million, or 214%. Record Appalachian NGL production and related NGL sales volumes and above average NGL sales margins in 2000
were the primary reasons for the increase in net income. The increased volumes were due to increased gas production behind our facilities and our gas processing and fractionation plant expansions.

Critical Accounting Policies

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting
rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment, to the
specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and
consistent application of the accounting rules is critical. Our critical accounting policies are discussed below. For further details on our accounting policies, see Note 2 of the Notes to
Consolidated Financial Statements.



Our estimates of gas and oil reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the
interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground
accumulations of gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment.
Estimates of economically recoverable gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future gas and oil prices, future operating costs, severance
taxes, development costs and workover gas costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped
locations may ultimately increase to an extent that these reserves may be later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of gas and oil
attributable to any particular group of properties, classifications of such reserves based on risk recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any
significant variance in the assumptions could materially affect the estimated quantity and value of
the reserves, which could affect the carrying value of our gas and oil properties and/or the rate of depletion of the gas and oil properties. Actual production, revenues and expenditures with respect
to our reserves will likely vary from estimates, and such variances may be material.



In accordance with Statement of Financial Accounting Standards (SFAS) No. 121,Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of,we evaluate the long-lived assets, including related intangibles, of
identifiable business activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. The
determination of whether impairment has occurred is based on management's estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If
impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair
value. 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

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is required. Until the assets are disposed of, an estimate of the fair value is recalculated when related events or circumstances change.

When
determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. Our estimate of cash
flows is based on assumptions regarding the volume of reserves behind the asset and future NGL product and natural gas prices. The amount of reserves and drilling activity are dependent in part on
natural gas prices. Projections of reserves and future commodity prices are inherently subjective and contingent upon a number of variable factors. Any significant variance in any of our assumptions
or factors could materially affect our cash flows, which could require us to record an impairment of an asset. For a more complete discussion of these factors, you should read Forward-Looking Informationin Items 1 and 2 included in this Form 10-K. Factors that affect projections of reserves and
future commodity prices are the same factors that could impact our results of operations.



Historically, we have satisfied our working capital requirements and funded our capital expenditures with cash generated from operations and borrowings under our
credit facility. From time to time, our sources of funds are supplemented with proceeds from the sale of a non-core asset, like the sale of our corporate office building in 2000. We may
also use operating leases to finance support equipment. We believe that cash generated from operations and our borrowing capacity will be sufficient to meet our working capital requirements and fund
our required capital expenditures. Cash generated from operations will depend on our operating performance, which will be affected by prevailing economic
conditions in the NGL and natural gas industries and financial, business and other factors, some of which are beyond our control. For a more complete discussion of factors that will affect our cash
flow from operations, you should readForward-Looking Informationin Items 1 and 2 included in this Form 10-K.

As
a result of our Canadian acquisition and our 2001 capital program, our total debt increased from $43.0 million at December 31, 2000, to $112.8 million at
December 31, 2001. Our year-end debt includes financing our seasonally-high working capital requirements. At the time of our Canadian acquisition, we amended our credit
facility, increasing our maximum borrowing amount to $130 million. On March 29, 2002, we amended our credit facility to reduce our maximum borrowing amount to $120 million; based
on our borrowing base and our working capital, the maximum available to be drawn on this date was approximately $110 million. Our bank debt was approximately $101 million at this date.
For further details regarding our amended credit facility, seeFinancing Facilitiesbelow.

On
January 31, 2002, MarkWest Energy Partners, L.P., a newly formed limited partnership created to own and operate most of our gathering, processing, transportation,
storage, and fractionation assets in Appalachia and Michigan, filed a registration statement on Form S-1 with the Securities and Exchange Commission for an initial public offering.
On March 22, 2002, we filed an amendment to this Form S-1. We currently anticipate offering to the public approximately 40% of the limited partner interests in the
partnership. We and certain of our affiliates will own the general partner of the partnership, as well as the remaining 60% of the limited partner interests in the form of subordinated units. The
rights of the holders of subordinated units to receive distributions of cash from the partnership are subordinated to the rights of the public unitholders to receive such distributions. In connection
with the offering, we will enter into a number of contracts with the partnership pursuant to which we will pay it fees for providing us with gathering, processing, transportation, storage, and
fractionation services. We will retain the risks and benefits associated with our "keep-whole" contracts in Appalachia. Proceeds we receive from the offering will be used to reduce our
outstanding debt. We anticipate that the limited partnership will enter into a separate credit facility, the proceeds of which will be used to support the limited partnership's operations. For
financial reporting purposes, the results of operations of MarkWest Energy Partners, L.P. will be consolidated with our operating results.

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The completion of the offering is subject to numerous conditions, including market conditions, and we can provide no assurance that it will be successfully completed. A registration statement
relating to the proposed offering has been filed with the Securities and Exchange Commission but has not yet become effective. The securities may not be sold, nor may offers to buy be accepted prior
to the time the registration statement becomes effective. The information contained in this Form 10-K with respect to this offering shall not constitute an offer to sell or a
solicitation of an offer to buy these securities.

Absent
the proceeds of the offering, or other sources of capital, our 2002 capital program may need to be reduced, depending on commodity price levels and our operating performance. Our
2002 capital expenditures are largely discretionary and concentrated in our E&P business segment.



Net cash provided by operating activities was $13.0 million, $13.3 million and $6.1 million for the years ended December 31, 2001,
2000 and 1999, respectively. Net cash provided by 2001 operating activities was almost the same amount as it was in 2000. Favorable timing of cash flows from receivables and payables offset lower net
income in 2001. Net cash provided by operating activities was higher in 2000 relative to 1999 principally due to higher net income, a function of above average processing margins and record sales
volumes in 2000.

Net
cash used in investing activities was $77.6 million, $12.3 million and $11.9 million for the years ended December 31, 2001, 2000 and 1999, respectively.
Net cash used in investing activities was much higher in 2001 due to our acquisition of two related E&P companies in Canada. Net of cash acquired, we paid $46.1 million for the acquisition.
Absent the Canadian acquisition, capital expenditures over the last three years have principally been focused on our Appalachian expansion and our various E&P capital programs.

Net
cash provided by financing activities was $66.1 million for the year ended December 31, 2001. Net cash used in financing activities were $1.5 million for the
year ended December 31, 2000. Net cash provided by financing activities was $5.0 million for the year ended December 31, 1999. Net cash provided by financing activities was much
higher in 2001 principally due to borrowings used to purchase two Canadian E&P companies. Net cash used in 2000 financing activities was a result of, despite our extensive Appalachian expansion, our
ability to pay down our line of credit a modest amount because of strong cash flows from operations, which was a function of above average processing margins and record sales volumes in 2000. Net cash
provided by 1999 financing activities was a result of supplementing our Appalachian expansion capital expenditures with net borrowings from our line of credit.



A summary of our total contractual cash obligations as of December 31, 2001, giving effect to the March 29, 2002 credit agreement amendment, is as
follows:

|                                   |  | Payment Due by Period
|---------------------------------- |  | ---------------------
|
|
|Long-term debt                     |  | $                    
|Operating leases                   |  |                      
|                                   |  |                      
|Total contractual cash obligations |  | $                    
|                                   |  |                      

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MarkWest's capital expenditures are summarized as follows:

|                                          |                                     | Year Ended December 31,
|----------------------------------------- | ----------------------------------- | -----------------------
|
|
|Gathering, processing and marketing       |                                     |                        
|Appalachia expansion and marketing assets |                                     | $                      
|Western Michigan pipeline expansion       |                                     |                        
|Canadian expansion                        |                                     |                        
|Maintenance capital and other             |                                     |                        
|                                          |                                     |                        
|                                          | Gathering, processing and marketing |                        
|                                          |                                     |                        
|Exploration and production                |                                     |                        
|Canada                                    |                                     | $                      
|Rocky Mountains                           |                                     |                        
|Western Michigan                          |                                     |                        
|Eastern Michigan                          |                                     |                        
|                                          |                                     |                        
|                                          | Exploration and production          |                        
|                                          |                                     |                        
|                                          | Total capital expenditures          |                        
|                                          |                                     |                        



MarkWest forecasts a baseline capital budget of $25.8 million for 2002. In our GPM segment, $2.5 million is for the next phase of our Canadian
midstream infrastructure. In our E&P segment, $11.8 million is for our Canadian capital program, $7.0 million is for our Rocky Mountain capital program and $3.2 million for our
Michigan capital program. Another $1.3 million is for company-wide maintenance capital and other capital programs. Our baseline capital budget is principally discretionary and may
change contingent upon a number of factors, including our results of operations and opportunities.



In conjunction with our Canadian acquisition, effective August 10, 2001, we amended our credit agreement with various financial institutions. The amended
agreement provided for a maximum borrowing amount of $130 million. Subsequently, in December 2001, based on our projected needs, we signed a letter agreement with our lead bank to reduce
our maximum borrowing amount to $120 million. On March 29, 2002, we formalized our agreement and amended our credit agreement with various financial institutions to reflect this
revision. The $120 million credit facility is comprised of $80 million in revolving lines of credit ($45 million under a U.S. facility and $35 million under a Canadian
facility) and a $40 million term loan under the U.S. facility. The U.S. facility matures August 2004 and the Canadian facility matures October 2007. Amortization is required as
set out in the table above. The amended credit facility includes a borrowing base, calculated semiannually, which is based principally on oil and gas properties and midstream assets (initially
determined to be $100 million), plus a working capital borrowing base, calculated monthly, which is based on NGL product accounts receivable and inventory levels, to a maximum of
$20 million. In the future, actual borrowing limits may be less than $120 million, depending upon reserve reports on our properties, our working capital and our financial covenants.

The
credit facility permits us to borrow money using either a base rate loan or a London Interbank Offered Rate (LIBOR) loan option, plus an applicable margin of between 0.375% and
2.75%, based on a certain debt to earnings ratio. We pay fees of between 0.25% and 0.50% per annum

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on the unused commitment, based on our debt to earnings ratio. The credit facility is secured by a first lien on substantially all of our assets. The loan agreement restricts certain activities,
including incurrence of additional indebtedness, and requires the maintenance of certain financial ratios and other conditions. At December 31, 2001, we had $112.8 million outstanding
under the credit facility bearing interest at a weighted average rate of 4.81%.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following discussion should be read in conjunction with Notes 8 and 9 of the accompanying Notes to Consolidated Financial Statements in Item 8
of this Form 10-K.

We
face market risk from commodity price variations. We also incur credit risk, foreign currency exchange risk and interest rate risk.



Our primary risk management objective is to reduce volatility in our cash flows. Our hedging approach uses a statistical method that analyzes momentum and average
pricing over time, and various fundamental data such as industry inventories, industry production, demand and weather. Hedging levels increase with capital commitments and debt levels and when
above-average margins exist. We maintain a committee, including members of senior management, which oversees all hedging activity.

We
utilize a combination of fixed-price forward contracts, fixed-for-float price swaps and options on over-the-counter (OTC) market. New
York Mercantile Exchange (NYMEX) traded futures are authorized for use, but only occasionally used. Swaps and futures allow us to protect our margins because corresponding losses or gains in the value
of financial instruments are generally offset by gains or losses in the physical market.

We
enter OTC swaps with counterparties that are primarily other energy companies. We conduct a standard credit review and have agreements with such parties that contain collateral
requirements. We use standardized swap agreements that allow for offset of positive and negative exposures. Net credit exposure is marked to market daily. We are subject to margin deposit requirements
under OTC agreements and NYMEX positions.

The
use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (a) sales volumes are less than expected requiring
market purchases to meet commitments, or (b) our OTC counterparties fail to purchase or deliver the contracted quantities of natural gas, NGL, or crude oil or otherwise fail to perform. To the
extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in
such prices.

Basis
risk is the risk that an adverse change in the hedging market will not be completely offset by an equal and opposite change in the price of the physical commodity being hedged. We
hedge our basis risk for natural gas but are generally unable to do so for NGL products. We have two different types of NGL product basis risk. First, NGL product basis risk stems from the geographic
price differentials between our sales locations and hedging contract delivery locations. We cannot hedge our geographic basis risk because there are no readily available products or markets. Second,
NGL product basis risk also results from the difference in relative price movements between crude oil and NGL products. We may use crude oil, instead of NGL products, in our hedges because the NGL
hedge products and markets are limited. Crude oil is highly correlated with certain NGL products.

As
a result of our 2001 Canadian E&P acquisition, our expected 2002 natural gas production and sales volumes from our E&P segment largely offset our keep-whole contractual
requirements for purchasing natural gas in our Appalachian GPM segment, thereby reducing our risk caused by fluctuations in natural gas prices. Consequently, we are transitioning our hedging strategy
to recognize

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this natural hedge between our E&P production and our natural gas purchase requirements in our Appalachian GPM business.

Prior
to our 2001 Canadian E&P acquisition, we hedged, in our GPM segment, our Appalachian processing margin (defined as revenues less cost of sales) by simultaneously selling propane or
crude oil while purchasing natural gas (Table I below). In our E&P segment, we historically hedged our natural gas sales (Table III below). As a result of our natural hedge, we are
transitioning our hedging strategy such that we no longer specifically hedge our Appalachian processing margin, nor our equivalent volume E&P natural gas sales, rather we hedge our NGL sales only
(Table II below).

As
of December 31, 2001, under our historical hedging practice, the hedged Appalachian NGL product sales volumes and associated projected margin per NGL product gallon, were as
follows:

Table I  Hedged Processing Margin

|                                   |                                  | Three Months Ended |   | Total
Year Ended |  | Year Ended
|---------------------------------- | -------------------------------- | ------------------ | - | ---------------- |  | ----------
|
|NGL Volumes Hedged Using Crude Oil |                                  |                    |   |                  |  |           
|                                   | NGL gallons                      |                    |   | 5,233,356        |  |           
|                                   | NGL processing margin ($/gallon) |                    | $ | 0.24             |  | $         
|NGL Volumes Hedged Using Propane   |                                  |                    |   |                  |  |           
|                                   | Propane gallons                  |                    |   | 11,550,000       |  |           
|                                   | NGL processing margin ($/gallon) |                    | $ | 0.19             |  | $         
|Total NGL Volumes Hedged           |                                  |                    |   |                  |  |           
|                                   | NGL gallons                      |                    |   | 16,783,356       |  |           
|                                   | NGL processing margin ($/gallon) |                    | $ | 0.21             |  | $         

Under our new hedging strategy, we hedge our NGL product sales by selling forward propane or crude oil. As of December 31, 2001, we hedged
Appalachian NGL product sales as follows:

Table II  Hedged Sales Price for NGL Products

|                                             |  | Three Months Ended |  | Total
Year Ended |           | Year
Ended
|-------------------------------------------- |  | ------------------ |  | ---------------- | --------- | ----------
|
|NGL volumes hedged using crude oil (gallons) |  |                   |  |                  | 7,625,720 |           
|NGL sales price per gallon                   |  |                   |  | $                | 0.43      |           

Under Tables I and II, all projected margins or prices on open positions assume (a) the basis differentials between our sales
location and the hedging contract's specified location, and (b) the correlation between crude oil and NGL products, are consistent with historical averages.

Also
within our GPM segment, for certain Appalachian natural gas sales, as of December 31, 2001, we hedged 650,000 MMBtu and 54,000 MMBtu at $4.38 per MMBtu for 2002 and 2003,
respectively.

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In
addition to these risk management tools, we utilize our NGL product storage facilities and contracts for third-party storage to build product inventories during lower-demand periods
for resale during higher-demand periods.

In
our E&P segment, under our historical hedging strategy we hedged our exposure to changes in market prices for our natural gas production by selling
fixed-for-float swaps and utilizing costless collars. Historically, we hedged a significant portion of our natural gas production. In light of our natural hedge, we are
transitioning our hedging strategy to limit our hedges to E&P natural gas production in
excess of natural gas purchase requirements in our GPM segment. As of December 31, 2001, we hedged natural gas volumes and prices as follows:

Table III  Hedged Natural Gas Sales

|                                |  | Three Months Ended |           | Total
Year Ended |   | Year Ended
|------------------------------- |  | ------------------ | --------- | ---------------- | - | ----------
|
|MMBtu                           |  |                    | 1,370,485 |                  |   | 1,316,343 
|$/MMBtu                         |  | $                  | 3.10      |                  | $ | 2.94      
|Henry Hub Equivalent $/MMBtu(1) |  | $                  | 3.64      |                  | $ | 3.48      

---

We enter into speculative transactions on an infrequent basis. Specific approval by the Board of Directors is necessary prior to executing such
transactions. Speculative transactions are marked to market at the end of each accounting period, and any gain or loss is recognized in income for that period. There were no such speculative
activities for the years ended December 31, 2001, 2000 and 1999.

Our
hedging program reduces our annual sensitivity to changes in NGL product sales prices. In our GPM segment, net income would have been lower by $4.0 million and higher by
$1.7 million and $0.9 million for the years ended December 31, 2001, 2000 and 1999, respectively, if we had not hedged. These figures consider only hedges of Appalachian
processing margin and do not reflect other decisions made concerning when to buy natural gas or store NGL production for sale in later months. In our E&P segment, without hedging, net income would
have been lower by $0.4 million and higher by $0.6 million and $0.1 million for the years ended December 31, 2001, 2000 and 1999, respectively.

Looking
ahead, as of February 20, 2002, under our historical hedging practice, we have hedged approximately 22.8 million gallons of our 2002 Appalachian NGL production
volumes governed by keep-whole contracts. For these hedged production volumes, we have hedged our processing margin by simultaneously hedging the expected NGL product sales and the related
cost of our replacement natural gas. Also, under our new hedging practice we have hedged an additional 64.5 million gallons of our 2002 Appalachian NGL sales volumes governed by
keep-whole contracts. We have hedged approximately 4.9 million gallons of our 2002 Michigan NGL production volumes governed by percent-of-proceeds contracts.
As of February 20, 2002, under our historicial hedging practice, we have hedged approximately 14,800 MMBtu/d of our expected E&P production for the year 2002.

Our
annual sensitivities to changes in commodity prices considering our hedge position is as follows. For every $0.10 per MMBtu increase in the natural gas price, our gross margin
(defined as revenue less cost of sales) would decrease by $0.6 million. For every $1.00 per barrel reduction in the crude oil price, or $0.02 per gallon reduction in NGL prices, our gross
margin would decrease by $1.2 million.



Counterparties pursuant to the terms of their contractual obligations expose us to potential losses as a result of nonperformance. We maintain credit policies
with regard to our counterparties that we

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believe minimize overall credit risk. Such policies include the evaluation of a prospective counterparty's financial condition, collateral requirements where deemed necessary, and the use of
standardized agreements, which facilitate the netting of cash flows associated with a single counterparty. We also monitor the financial condition of existing counterparties on an ongoing basis. In
general, our risk of default by these counterparties is low. However, we recently experienced a loss as described below.

SFAS
No. 133 provides that hedge accounting must be discontinued on contracts when it becomes reasonably possible that the counterparty will default. During the fourth quarter of
2001, Enron
Corporation and its subsidaries (Enron) filed for bankruptcy protection. In response to this filing, we have terminated all derivative contracts where Enron was the counterparty. As a result, we wrote
off $1.1 million of risk management assets related to our cash flow hedges offset by $0.1 million of risk management liabilities related to our fair value hedges. In addition, our
contracts with Enron provide for netting of amounts owed to each other and as such we have netted $0.6 million in amounts payable to Enron. The net result of the above transactions is a charge
of $0.4 million to earnings in the fourth quarter 2001. In the case of discontinuing hedge accounting for cash flow hedges, SFAS No. 133 provides the amount in other comprehensive income
will be reclassified to earnings in the periods of the forecasted transactions. As such, we will be reclassifying $0.8 million and $0.2 million from other comprehensive income to
revenue, net of $0.3 million and $0.1 million of deferred taxes for 2002 and 2003, respectively.

While
we enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that additional losses
will result from counterparty credit risk in the future.



We conduct business in Canada and thus are subject to foreign currency exchange rate risk on cash flows related to sales, expenses, financing and investing
transactions. We manage this risk in part through use of the Canadian dollar component of our credit facility. To date, we have not entered into any foreign currency forward contracts or other similar
financial instruments to manage this risk.



We are exposed to changes in interest rates, primarily as a result of our long-term debt with floating interest rates. We may make use of interest
rate swap agreements expiring June 7, 2004 to adjust the ratio of fixed and floating rates in the debt portfolio. As of December 31, 2001, we are a party to contracts to fix interest
rates on $10.0 million of our debt at 5.28% compared to floating LIBOR, plus an applicable margin. The impact of a 100 basis point increase in interest rates on our debt would result in an
increase in interest expense and a decrease in income before taxes of approximately $1.0 million. This amount has been determined by considering the impact of the hypothetical interest rates on
our variable-rate debt balances as of December 31, 2001.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements



|                                                                                                                            |  | Page
|--------------------------------------------------------------------------------------------------------------------------- |  | ----
|Report of Independent Accountants                                                                                           |  | 37  
|Consolidated Balance Sheet at December 31, 2001 and 2000                                                                    |  | 38  
|Consolidated Statement of Operations for each of the three years in the period ended December 31, 2001                      |  | 39  
|Consolidated Statement of Cash Flows for each of the three years in the period ended December 31, 2001                      |  | 40  
|Consolidated Statement of Changes in Stockholders' Equity for each of the three years in the period ended December 31, 2001 |  | 41  
|Notes to Consolidated Financial Statements                                                                                  |  | 42  

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REPORT OF INDEPENDENT ACCOUNTANTS

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

In
our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of cash flows and of changes in stockholders' equity present fairly, in
all material respects, the financial position of MarkWest Hydrocarbon, Inc., a Delaware corporation, and its subsidiaries at December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended December 31, 2001 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, which 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
discussed in Note 9 to the financial statements, MarkWest Hydrocarbon, Inc. changed its method of accounting for derivative instruments and hedging activities effective
January 1, 2001.

/s/
PricewaterhouseCoopers LLP

Denver,
Colorado
March 1, 2002, except for Note 4,
as to which the date is March 29, 2002

37

---



MARKWEST HYDROCARBON, INC.        CONSOLIDATED BALANCE SHEET

|                                                                                         |                                                                                                                  | December 31,                             |                                           
|---------------------------------------------------------------------------------------- | ---------------------------------------------------------------------------------------------------------------- | ---------------------------------------- | ------------------------------------------
|
|
|ASSETS                                                                                   |                                                                                                                  |                                          |                                           
|Current assets                                                                           |                                                                                                                  |                                          |                                           
|                                                                                         | Cash and cash equivalents                                                                                        |                                          | $                                         
|                                                                                         | Receivables, including related party receivables of $600,000 and $2,200,000, respectively                        |                                          |                                           
|                                                                                         | Inventories                                                                                                      |                                          |                                           
|                                                                                         | Prepaid replacement natural gas                                                                                  |                                          |                                           
|                                                                                         | Risk management asset                                                                                            |                                          |                                           
|                                                                                         | Other assets                                                                                                     |                                          |                                           
|                                                                                         |                                                                                                                  |                                          |                                           
|                                                                                         |                                                                                                                  | Total current assets                     |                                           
|Property, plant and equipment:                                                           |                                                                                                                  |                                          |                                           
|                                                                                         | Gas gathering, processing, storage and marketing equipment                                                       |                                          |                                           
|                                                                                         | Oil and gas properties and equipment, full cost method                                                           |                                          |                                           
|                                                                                         | Land, buildings and other equipment                                                                              |                                          |                                           
|                                                                                         | Construction in progress                                                                                         |                                          |                                           
|                                                                                         |                                                                                                                  |                                          |                                           
|                                                                                         |                                                                                                                  |                                          | 238,920                                   
|Less: accumulated depreciation and depletion                                             |                                                                                                                  |                                          | (38,067                                   
|                                                                                         |                                                                                                                  |                                          |                                           
|                                                                                         |                                                                                                                  | Total property, plant and equipment, net |                                           
|Risk management asset, net of allowance of $912 and $0, respectively                     |                                                                                                                  |                                          | 1,056                                     
|Deferred financing costs, net of accumulated amortization of $705 and $708, respectively |                                                                                                                  |                                          | 4,385                                     
|                                                                                         |                                                                                                                  |                                          |                                           
|                                                                                         |                                                                                                                  | Total assets                             |                                           
|                                                                                         |                                                                                                                  |                                          |                                           
|LIABILITIES AND STOCKHOLDERS' EQUITY                                                     |                                                                                                                  |                                          |                                           
|Current liabilities:                                                                     |                                                                                                                  |                                          |                                           
|                                                                                         | Accounts payable, including related party payables of $500,000 and $800,000, respectively                        |                                          | $                                         
|                                                                                         | Accrued liabilities                                                                                              |                                          |                                           
|                                                                                         | Current portion of long term debt                                                                                |                                          |                                           
|                                                                                         |                                                                                                                  |                                          |                                           
|                                                                                         |                                                                                                                  | Total current liabilities                |                                           
|Deferred income taxes                                                                    |                                                                                                                  |                                          | 45,311                                    
|Long-term debt                                                                           |                                                                                                                  |                                          | 104,850                                   
|Risk management liability                                                                |                                                                                                                  |                                          | 458                                       
|Other long-term liabilities                                                              |                                                                                                                  |                                          | 140                                       
|Commitments and contingencies (see Note 15)                                              |                                                                                                                  |                                          |                                           
|Stockholders' equity:                                                                    |                                                                                                                  |                                          |                                           
|                                                                                         | Preferred stock, par value $0.01; 5,000,000 shares authorized, 0 shares outstanding                              |                                          |                                           
|                                                                                         | Common stock, par value $0.01; 20,000,000 shares authorized, 8,563,919 and 8,561,206 shares issued, respectively |                                          |                                           
|                                                                                         | Additional paid-in capital                                                                                       |                                          |                                           
|                                                                                         | Retained earnings                                                                                                |                                          |                                           
|                                                                                         | Accumulated other comprehensive income, net of tax                                                               |                                          |                                           
|                                                                                         | Treasury stock; 59,622 and 104,093 shares, respectively                                                          |                                          |                                           
|                                                                                         |                                                                                                                  |                                          |                                           
|                                                                                         |                                                                                                                  | Total stockholders' equity               |                                           
|                                                                                         |                                                                                                                  |                                          |                                           
|                                                                                         |                                                                                                                  |                                          | Total liabilities and stockholders' equity
|                                                                                         |                                                                                                                  |                                          |                                           

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

38

---

MARKWEST HYDROCARBON, INC.        CONSOLIDATED STATEMENT OF OPERATIONS

|                                                               |                                              | Year Ended December 31,    |     
|-------------------------------------------------------------- | -------------------------------------------- | -------------------------- | ----
|
|
|Revenues:                                                      |                                              |                            |     
|                                                               | Gathering, processing and marketing revenue  |                            | $   
|                                                               | Exploration and production revenue           |                            |     
|                                                               |                                              |                            |     
|                                                               |                                              | Total revenues             |     
|                                                               |                                              |                            |     
|Operating expenses:                                            |                                              |                            |     
|                                                               | Cost of sales                                |                            |     
|                                                               | Operating expenses                           |                            |     
|                                                               | Selling, general and administrative expenses |                            |     
|                                                               | Depreciation and depletion                   |                            |     
|                                                               | Gain on sale of operating assets             |                            |     
|                                                               |                                              |                            |     
|                                                               |                                              | Total operating expenses   |     
|                                                               |                                              |                            |     
|                                                               |                                              | Income from operations     |     
|                                                               |                                              |                            |     
|Other income and expense:                                      |                                              |                            |     
|                                                               | Interest income                              |                            |     
|                                                               | Interest expense                             |                            |     
|                                                               | Gain on sale of non-operating assets         |                            |     
|                                                               | Other income (expense)                       |                            |     
|                                                               |                                              |                            |     
|                                                               |                                              | Income before income taxes |     
|                                                               |                                              |                            |     
|Provision for income taxes:                                    |                                              |                            |     
|                                                               | Current                                      |                            |     
|                                                               | Deferred                                     |                            |     
|                                                               |                                              |                            |     
|                                                               |                                              | Provision for income taxes |     
|                                                               |                                              |                            |     
|                                                               |                                              | Net income                 |     
|                                                               |                                              |                            |     
|Basic earnings per share of common stock                       |                                              | $                          | 0.33
|                                                               |                                              |                            |     
|Earnings per share assuming dilution                           |                                              | $                          | 0.33
|                                                               |                                              |                            |     
|Weighted average number of outstanding shares of common stock: |                                              |                            |     
|                                                               | Basic                                        |                            |     
|                                                               |                                              |                            |     
|                                                               | Assuming dilution                            |                            |     
|                                                               |                                              |                            |     

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

39

---



MARKWEST HYDROCARBON, INC.        CONSOLIDATED STATEMENT OF CASH FLOWS

|                                                                                  |                                                                         | Year Ended December 31,                             |      
|--------------------------------------------------------------------------------- | ----------------------------------------------------------------------- | --------------------------------------------------- | -----
|
|
|Cash flows from operating activities:                                             |                                                                         |                                                     |      
|Net income                                                                        |                                                                         | $                                                   | 2,810
|Adjustments to reconcile net income to net cash provided by operating activities: |                                                                         |                                                     |      
|                                                                                  | Depreciation and depletion                                              |                                                     |      
|                                                                                  | Amortization of deferred financing costs                                |                                                     |      
|                                                                                  | Deferred income taxes                                                   |                                                     |      
|                                                                                  | Gain on sale of assets                                                  |                                                     |      
|                                                                                  | Write-off Enron financial position, net of tax                          |                                                     |      
|                                                                                  | Reclassification of Enron hedges to cost of sales                       |                                                     |      
|                                                                                  | Other                                                                   |                                                     |      
|Changes in operating assets and liabilities:                                      |                                                                         |                                                     |      
|                                                                                  | (Increase) decrease in receivables                                      |                                                     |      
|                                                                                  | (Increase) decrease in inventories                                      |                                                     |      
|                                                                                  | (Increase) decrease in prepaid replacement natural gas and other assets |                                                     |      
|                                                                                  | Increase (decrease) in accounts payable and accrued liabilities         |                                                     |      
|                                                                                  |                                                                         |                                                     |      
|                                                                                  |                                                                         | Net cash provided by operating activities           |      
|Cash flows from investing activities:                                             |                                                                         |                                                     |      
|                                                                                  | Capital expenditures                                                    |                                                     |      
|                                                                                  | Acquisition of Canadian operations, net of cash acquired                |                                                     |      
|                                                                                  | Proceeds from sale of assets                                            |                                                     |      
|                                                                                  |                                                                         |                                                     |      
|                                                                                  |                                                                         | Net cash used in investing activities               |      
|Cash flows from financing activities:                                             |                                                                         |                                                     |      
|                                                                                  | Proceeds from long-term debt                                            |                                                     |      
|                                                                                  | Repayments of long-term debt                                            |                                                     |      
|                                                                                  | Debt issuance costs                                                     |                                                     |      
|                                                                                  | Exercise of stock options                                               |                                                     |      
|                                                                                  | Acquisition of treasury stock                                           |                                                     |      
|                                                                                  | Reissuance of treasury stock                                            |                                                     |      
|                                                                                  |                                                                         |                                                     |      
|                                                                                  |                                                                         | Net cash provided by (used in) financing activities |      
|Effect of exchange rate on changes in cash                                        |                                                                         |                                                     | (18  
|                                                                                  |                                                                         |                                                     |      
|Net increase (decrease) in cash and cash equivalents                              |                                                                         |                                                     | 1,406
|Cash and cash equivalents at beginning of year                                    |                                                                         |                                                     | 934  
|                                                                                  |                                                                         |                                                     |      
|Cash and cash equivalents at end of year                                          |                                                                         | $                                                   | 2,340
|                                                                                  |                                                                         |                                                     |      

The
accompanying notes are an integral part of these financial statements

40

---

MARKWEST HYDROCARBON, INC.        CONSOLIDATED STATEMENT OF CHANGES IN  STOCKHOLDERS' EQUITY

|                                         |                                                                 | Shares of
Common
Stock              |   | Shares of
Treasury
Stock |   | Common
Stock |    | Additional
Paid-In
Capital |   | Retained
Earnings |   | Treasury
Stock |        | Accumulated
Other
Comprehensive
Income |   | Total
Stockholders'
Equity |  
|---------------------------------------- | --------------------------------------------------------------- | ----------------------------------- | - | ------------------------ | - | ------------ | -- | -------------------------- | - | ----------------- | - | -------------- | ------ | -------------------------------------- | - | -------------------------- | -
|
|Balance, December 31, 1998               |                                                                 | 8,531                               |   | (60                      | ) | $            | 85 |                            | $ | 42,693            |   | $              | 7,978  |                                        | $ | (721                       | )
|Net income, 1999                         |                                                                 |                                    |   |                         |   |              |   |                            |   |                  |   |                | 2,823  |                                        |   |                           |  
|Acquisition of treasury stock            |                                                                 |                                    |   | (156                     | ) |              |   |                            |   |                  |   |                |       |                                        |   | (1,035                     | )
|Reissuance of treasury stock             |                                                                 |                                    |   | 147                      |   |              |   |                            |   | (471              | ) |                |       |                                        |   | 1,367                      |  
|                                         |                                                                 |                                     |   |                          |   |              |    |                            |   |                   |   |                |        |                                        |   |                            |  
|Balance, December 31, 1999               |                                                                 | 8,531                               |   | (69                      | ) |              | 85 |                            |   | 42,222            |   |                | 10,801 |                                        |   | (389                       | )
|Net income, 2000                         |                                                                 |                                    |   |                         |   |              |   |                            |   |                  |   |                | 8,878  |                                        |   |                           |  
|Issuance of common stock                 |                                                                 | 30                                  |   | (30                      | ) |              | 1  |                            |   | 197               |   |                |       |                                        |   | (198                       | )
|Exercise of options                      |                                                                 |                                    |   | 5                        |   |              |   |                            |   | 10                |   |                |       |                                        |   | 28                         |  
|Acquisition of treasury stock            |                                                                 |                                    |   | (39                      | ) |              |   |                            |   |                  |   |                |       |                                        |   | (251                       | )
|Reissuance of treasury stock             |                                                                 |                                    |   | 29                       |   |              |   |                            |   | 42                |   |                |       |                                        |   | 168                        |  
|                                         |                                                                 |                                     |   |                          |   |              |    |                            |   |                   |   |                |        |                                        |   |                            |  
|Balance, December 31, 2000               |                                                                 | 8,561                               |   | (104                     | ) |              | 86 |                            |   | 42,471            |   |                | 19,679 |                                        |   | (642                       | )
|Comprehensive income:                    |                                                                 |                                     |   |                          |   |              |    |                            |   |                   |   |                |        |                                        |   |                            |  
|Net income, 2001                         |                                                                 |                                    |   |                         |   |              |   |                            |   |                  |   |                | 2,810  |                                        |   |                           |  
|Foreign currency translation adjustments |                                                                 |                                    |   |                         |   |              |   |                            |   |                  |   |                |       |                                        |   |                           |  
|Other comprehensive income:              |                                                                 |                                     |   |                          |   |              |    |                            |   |                   |   |                |        |                                        |   |                            |  
|                                         | Cumulative effect of change in accounting principle, net of tax |                                     |  |                          |  |              |    |                           |   |                   |  |                |        |                                       |   |                            | 
|                                         | Risk management activities, net of tax                          |                                     |  |                          |  |              |    |                           |   |                   |  |                |        |                                       |   |                            | 
|                                         |                                                                 |                                     |   |                          |   |              |    |                            |   |                   |   |                |        |                                        |   |                            |  
|                                         |                                                                 | Ending accumulative derivative gain |   |                          |   |              |    |                            |   |                   |   |                |        |                                        |   |                            |  
|                                         |                                                                 |                                     |   |                          |   |              |    |                            |   |                   |   |                |        |                                        |   |                            |  
|Comprehensive income                     |                                                                 |                                    |   |                         |   |              |   |                            |   |                  |   |                |       |                                        |   |                           |  
|                                         |                                                                 |                                     |   |                          |   |              |    |                            |   |                   |   |                |        |                                        |   |                            |  
|Exercise of options                      |                                                                 | 3                                   |   |                         |   |              | 1  |                            |   | 17                |   |                |       |                                        |   |                           |  
|Reissuance of treasury stock             |                                                                 |                                    |   | 44                       |   |              |   |                            |   | 59                |   |                |       |                                        |   | 275                        |  
|                                         |                                                                 |                                     |   |                          |   |              |    |                            |   |                   |   |                |        |                                        |   |                            |  
|Balance, December 31, 2001               |                                                                 | 8,564                               |   | (60                      | ) | $            | 87 |                            | $ | 42,547            |   | $              | 22,489 |                                        | $ | (367                       | )
|                                         |                                                                 |                                     |   |                          |   |              |    |                            |   |                   |   |                |        |                                        |   |                            |  

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

41

---



MARKWEST HYDROCARBON, INC.        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.    Nature of Operations

MarkWest Hydrocarbon, Inc. provides natural gas processing and related services and produces natural gas. Our activities include gathering, treatment and
natural gas liquids (NGLs) extraction services for natural gas producers and pipeline companies and fractionation of NGLs into marketable products. We also purchase, store and market natural gas and
NGLs. We are also engaged in the exploration, acquisition, development, production and sale of natural gas. Our operations are concentrated in four core areas: the southern Appalachian region of
eastern Kentucky, southern West Virginia, and southern Ohio; Michigan; the Rocky Mountains of Colorado and New Mexico; and Alberta, Canada.

2.    Summary of Significant Accounting Policies



The consolidated financial statements include the accounts of MarkWest and its wholly owned subsidiaries. Through consolidation, we have eliminated all
significant intercompany accounts and transactions.

We
reclassified certain prior year amounts to conform to the current year's presentation.



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 assets and liabilities and 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.



We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Investments are limited to overnight
investments of end-of-day cash balances.



Inventories comprise the following:

December 31,2001

2000(in thousands)Product inventory

$
6,330

$
7,973Materials and supplies inventory


14


85$
6,344

$
8,058


Product
inventory consists of propane, butane, isobutane, natural gasoline and natural gas and is valued at the lower of cost, using the first-in, first-out
method, or market. Materials and supplies are valued at the lower of average cost or estimated net realizable value.

42

---



Prepaid replacement natural gas consists of natural gas purchased in advance of its actual use in our Appalachia processing business. Replacement natural gas
purchased as a result of our hedging program is valued using the specific identification method. Unhedged replacement natural gas is valued using the first in, first-out method.



Property, plant and equipment is 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. Depreciation is provided principally on the straight-line method over the following estimated useful lives: gas gathering, processing and marketing,
20 years; buildings, 40 years; furniture, leasehold improvements and other, 3 to 10 years.

Oil
and gas properties and equipment consist of leasehold costs, producing and non-producing properties, oil and gas wells, equipment and pipelines. We use the full cost
method of accounting for oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves are capitalized to the full cost pool.
Depletion for oil and gas properties is provided for using the units-of-production method.

These
capitalized costs, including estimated future costs to develop the reserves and estimated abandonment costs, net of salvage value, are amortized on a
units-of-production basis using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves
associated with the projects can be determined or until impairment occurs. If the results of an assessment of such properties indicate that the properties are impaired, the amount of
impairment is added to the capitalized cost base to be amortized. As of December 31, 2001, approximately $31.2 million of investments in unproved properties in Canada were excluded from
amortization. As of December 31, 2001, 2000 and 1999, approximately $0.5 million, $0.6 million and $1.2 million, respectively, of investments in unproved properties in the
United States were excluded from amortization.

Depletion
per unit of production (Mcfe) for each of the Company's cost centers was as follows:

United States

Canada2001

$
0.61

$
1.662000


0.48


1999


0.58





The
capitalized costs included in the full cost pool are subject to a "ceiling test," which limits such costs to the aggregate of the estimated present value, using a 10% discount rate,
of the future net revenues from proved reserves, based on current economics and operating conditions. The ceiling tests includes hedging contracts in place at the end of each year. No impairment
existed during the three years ended December 31, 2001.

Sales
of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the
relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in the consolidated statement of operations.

43

---



We capitalize interest on major projects during construction and on unproved properties. Interest is capitalized on borrowed funds. The interest rates used are
based on the average interest rate on related debt.



Deferred financing costs are charged to interest expense over the anticipated term of the associated agreement.



In accordance with Statement of Financial Accounting Standards (SFAS) No. 121,Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of,we evaluate the long-lived assets, including related intangibles, of
identifiable business activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. The
determination of whether an impairment has occurred is based on management's estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If
an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than
fair value. 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 an impairment is
required. Until the assets are disposed of, an estimate of the fair value is redetermined when related events or circumstances change. No impairment charges were recognized for the three years ended
December 31, 2001.



In order to reduce volatility in our cash flows as a result of commodity price fluctuations, we may, from time to time in the ordinary course of business, enter
into commodity swap agreements, forward purchase contracts, forward sale contracts, commodity futures, options and other similar agreements relating to natural gas, NGL and crude oil.

Financial
instruments designated as hedges are accounted for on the accrual basis with gains and losses being recognized based on the type of contract and exposure being hedged. Gains
and losses on natural gas, NGL and crude oil swaps designated as hedges of anticipated transactions, including accrued gains or losses upon maturity or termination of the contract, are deferred and
recognized in income when the associated hedged commodities are sold. In order for natural gas, NGL and crude oil swaps to qualify as a hedge of an anticipated transaction, the derivative contract
must identify the expected date of the transaction, the commodity involved, and the expected quantity to be purchased or sold among other requirements. In the event that a hedged transaction does not
occur, future gains and losses, including termination gains or losses, are included in the income statement when incurred. See also Notes 8 and 9.

Prior
to our adoption of SFAS No. 133,Accounting for Derivative Instruments and Hedging Activitieson January 1, 2001, we
accounted for futures contracts in accordance with the provisions of SFAS No. 80,Accounting for Futures Contracts.Gains and losses on futures
contracts were deferred and included as a component of revenues or cost of sales when the hedged production sold.

44

---



Financial instruments that subject us to concentrations of credit risk consist principally of trade accounts receivable. In our gathering, processing and
marketing segment, our customers are concentrated within the Appalachian basin and Michigan geographic areas and the retail propane, refining and petrochemical industries. Consequently, changes within
these regions and/or industries have the potential to impact, both positively and negatively, our exposure to credit risk. In our exploration and production segment, our revenues are derived
principally from uncollateralized sales to customers in the oil and gas industry. The concentration of credit risk in a single industry affects our overall exposure to credit risk because customers
may be similarly affected by changes in economic or other conditions. We have not experienced significant credit losses on our receivables.



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



Our financial instruments consist of cash and cash equivalents, receivables, accounts payable and other current liabilities, and long-term debt.
Except for long-term debt, the carrying amounts of financial instruments approximate fair value due to their short maturities. At December 31, 2001 and 2000, based on rates
available for similar types of debt, the fair value of long-term debt was not materially different from its carrying amount.



Revenue for natural gas and NGL product sales is recognized at the time the title is transferred. Gas gathering and processing and NGL fractionation,
transportation and storage revenues are recognized as volumes are processed, fractionated, transported and stored in accordance with contractual terms.



Deferred income taxes reflect the impact of "temporary differences" between amounts of assets and liabilities for financial reporting purposes and such amounts as
measured by tax laws. These temporary differences are determined in accordance with the liability method of accounting for income taxes as prescribed by SFAS No. 109, Accounting for Income Taxes.



As permitted under SFAS No. 123,Accounting for Stock-Based Compensation,we have elected to continue to
measure compensation costs for stock-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25,Accounting for Stock Issued to
Employees.



Basic earnings per share are determined by dividing net income by the weighted-average number of common shares outstanding during the year. Earnings per share
assuming dilution are determined by
dividing net income by the weighted-average number of common shares and common stock equivalents outstanding.

45

---



In accordance with SFAS No. 131,Disclosures About Segments of an Enterprise and Related Information, the
internal organization that is used by management for making operating decisions and assessing performance is the source of our reportable segments (see Note 13).



Year Ended December 31,2001

2000

1999(in thousands)Interest paid

$
3,968

$
2,529

$
2,688Capitalized interest

$
950

$
137

$
157Income taxes paid (net of refunds)

$
3,834

$
1,992

$
(1,326
)




Assets and liabilities of our Canadian subsidiary, which has the Canadian dollar as its functional currency, are translated into United States dollars at the
foreign currency exchange rate in effect at the applicable reporting date, and the combined statements of operations are translated at the average rates in effect during the applicable period. The
resulting cumulative translation adjustment is recorded as a separate component of other comprehensive income.



In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No. 133,Accounting for Derivative Instruments and
Hedging Activities.This statement, as amended by SFAS Nos. 137 and 138, is effective for fiscal years beginning after June 15, 2000. SFAS No. 133 requires
an entity to recognize all derivatives as assets or liabilities in the balance sheet and measure those instruments at fair value. We have adopted SFAS No. 133, as amended, on January 1,
2001. See Note 9.

In
June 2001, the FASB issued SFAS No. 141,Business Combinations,which addresses financial accounting and reporting for
business combinations. SFAS No. 141 is effective for all business combinations initiated after June 30, 2001 and for all business combinations accounted for under the purchase method
initiated before but completed after June 30, 2001. All business combinations in the scope of this Statement are to be accounted for using one methodthe purchase method. We used
this method with the Canadian acquisition, see Note 3.

In
June 2001, the FASB issued SFAS No. 142,Goodwill and Other Intangible Assets,which is effective for fiscal years
beginning after December 15, 2001, and applies to all goodwill and other intangibles recognized in the financial statements at that date. Under the provisions of this statement, goodwill will
not be amortized, but will be tested for impairment on an annual basis. The adoption of SFAS No. 142 is not expected to have a material impact on our financial position or results of
operations.

In
July 2001, the FASB issued SFAS No. 143,Accounting for Asset Retirement Obligations. SFAS No. 143, is effective
for fiscal years beginning after June 15, 2002 (January 1, 2003 for MarkWest), and establishes an accounting standard requiring the recording of the fair value of liabilities associated
with the retirement of long-lived assets in the period in which they are incurred. We are in the process of determining the future impact that the adoption of SFAS No.143 may have on our
results of operations and financial position.

46

---

In
August 2001, the FASB issued SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets.This statement requires the recognition of an impairment loss if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and measures the impairment
loss as the difference between the carrying amount and fair value of the asset. The adoption of SFAS No. 144 is not expected to have a material impact on our financial position or results of
operations.

47

---



3.    Acquisition

On August 10, 2001, we acquired for $50.3 million in cash 100% of the voting shares of Leland Energy Canada, Ltd. and Watford
Energy, Ltd. (Leland/Watford), two privately owned natural gas production companies active in central and southeast Alberta, Canada.

The
purchase price was allocated as follows:

|                                 |                               | (in thousands)
|-------------------------------- | ----------------------------- | --------------
|Acquisition costs:               |                               |               
|                                 | Long term debt incurred       |               
|                                 | Direct acquisition costs      |               
|                                 |                               |               
|                                 |                               |               
|                                 | Current liabilities assumed   |               
|                                 | Deferred income taxes         |               
|                                 |                               |               
|                                 |                               | Total         
|                                 |                               |               
|Allocation of acquisition costs: |                               |               
|                                 | Current assets                |               
|                                 | Oil and gas propertiesproved |               
|                                 | Undeveloped properties        |               
|                                 | Other facilities              |               
|                                 |                               |               
|                                 |                               | Total         
|                                 |                               |               

In
addition to the $50.3 million acquisition cost identified above, we recorded a deferred income tax liability of $30.6 million to recognize the difference between the
historical tax basis of the Leland/Watford assets and the acquisition costs recorded for book purposes. The recorded book value of the oil and gas properties was increased to recognize this tax basis
differential.

We
have entered into employment contracts with certain executives from Leland/Watford that provide for a minimum annual salary and incentives based on increases in reserve value, as
defined, since the acquisition. The executives' entitlement to these incentives vests over time through December 31, 2005, and are payable in cash or in kind by way of transferring to the
executives a working interest in the acquired assets.



The following table reflects the unaudited pro forma consolidated results of operations for the years ended December 31, 2001 and 2000 as though our
Canadian acquisitions had occurred on January 1 for the periods presented. These unaudited pro forma results have been prepared for comparative purposes only and are not indicative of future
results.

|                             |  | Year Ended December 31,
|---------------------------- |  | -----------------------
|
|
|Revenue                      |  | $                      
|Net income                   |  |                        
|Basic net income per share   |  |                        
|Diluted net income per share |  |                        

48

---

Pro
forma net income included results of operations of the predecessor company including a bonus expense of $2.8 million and a gain on settlement of derivatives of
$1.1 million for the year ended December 31, 2001. Pro forma net income included a gain on sale of a partnership of $4.3 million for the year ended December 31, 2000.

4.    Debt



In conjunction with our Canadian acquisition (see Note 3), effective August 10, 2001, we amended our credit agreement with various financial
institutions. The amended agreement provided for a maximum borrowing amount of $130 million. Subsequently, in December 2001, based on our projected needs, we signed a letter agreement
with our lead bank to reduce our maximum borrowing amount to $120 million. On March 29, 2002, we formalized our agreement and amended our credit agreement with various financial
institutions to reflect this revision. The $120 million credit facility is comprised of $80 million in revolving lines of credit ($45 million under a U.S. facility and
$35 million under a Canadian facility) and a $40 million term loan under the U.S. facility. The U.S. facility matures August 2004 and the Canadian facility matures
October 2007. Amortization is required as set out in the table below. The amended credit facility includes a borrowing base, calculated semiannually, which is based principally on oil and gas
properties and midstream assets (initially determined to be $100 million), plus a working capital borrowing base, calculated monthly, which is based on NGL product accounts receivable and
inventory levels, to a maximum of $20 million. In the future, actual borrowing limits may be less than $120 million, depending upon reserve reports on our properties, our working capital
and our financial covenants.

The
credit facility permits us to borrow money using either a base rate loan or a London Interbank Offered Rate (LIBOR) loan option, plus an applicable margin of between 0.375% and
2.75%, based on a certain debt to earnings ratio. We pay fees of between 0.25% and 0.50% per annum on the unused commitment, based on our debt to earnings ratio. The credit facility is secured by a
first lien on substantially all of our assets. The loan agreement restricts certain activities, including incurrence of additional indebtedness, and requires the maintenance of certain financial
ratios and other conditions. At December 31, 2001, we had $112.8 million outstanding under the credit facility bearing interest at a
weighted average rate of 4.81%. At December 31, 2000, we had $43.0 million outstanding under the credit facility bearing interest at a weighted average rate of 8.27%.



Scheduled debt maturities as of December 31, 2001, giving effect to the March 29, 2002 amendment, were as follows:

|                                       |  | (in thousands)
|-------------------------------------- |  | --------------
|2002                                   |  | $             
|2003                                   |  |               
|2004                                   |  |               
|2005                                   |  |               
|2006                                   |  |               
|2007                                   |  |               
|                                       |  |               
|Total debt outstanding                 |  | $             
|Less current portion of long term debt |  | $             
|                                       |  |               
|Long term debt                         |  | $             
|                                       |  |               

49

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5.    Related Party Transactions

Through our wholly owned subsidiary, MarkWest Resources, Inc. (Resources), we hold varied undivided interests in several exploration and production assets,
in which MAK-J Energy Partners Ltd. (MAK-J), also owns an undivided interest, varying from 25% to 51%. The general partner of MAK-J is a corporation owned
and controlled by our President and Chief Executive Officer. Joint property
acquisitions and joint operating agreements are subject to the approval of independent members of our Board of Directors. The properties are held pursuant to operating agreements entered into between
Resources and MAK-J. Resources is the operator under such agreements. As the operator, Resources is obligated to provide certain engineering, administrative and accounting services to the
joint ventures. The joint venture agreements provide for a monthly fee payable to Resources to offset the costs of such services. As of December 31, 2001 and 2000, we have receivables due from
MAK-J, for its normal course of business share of operating and capital costs of approximately $0.6 million and $2.2 million, respectively, and payables to MAK-J,
for its normal course of business share of revenues of approximately $0.5 million and $0.8 million, respectively.

6.    Benefit Plan

We made contributions of $0.3 million, $0.5 million and $0.3 million to a profit-sharing plan for the years ended December 31, 2001,
2000 and 1999, respectively. The plan is discretionary, with annual contributions determined by our Board of Directors.

7.    Significant Customer

For the years ended December 31, 2001 and 2000 sales to one customer accounted for approximately 11% of each year's total revenues. There were no
significant customers for the year ended December 31, 1999.

8.    Commodity Price Risk Management

Our primary risk management objective is to reduce volatility in our cash flows. Our hedging approach uses a statistical method that analyzes momentum pricing and
average pricing over time, and various fundamental data such as industry inventories, industry production, demand and weather. Hedging levels increase with capital commitments and debt levels and when
above-average margins exist. We maintain a committee, including members of senior management, which oversees all hedging activity.

We
utilize a combination of fixed-price forward contracts, fixed-for-float price swaps and options on over-the-counter (OTC) market. New
York Mercantile Exchange (NYMEX) traded futures are authorized for use, but only occasionally used. Swaps and futures allow us to protect our margins because corresponding losses or gains in the value
of financial instruments are generally offset by gains or losses in the physical market.

We
enter OTC swaps with counterparties that are primarily other energy companies. We conduct a standard credit review and have agreements with such parties that contain collateral
requirements. We
use standardized swap agreements that allow for offset of positive and negative exposures. Net credit exposure is marked to market daily. We are subject to margin deposit requirements under OTC
agreements and NYMEX positions.

The
use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (a) sales volumes are less than expected requiring
market purchases to meet commitments, or (b) our OTC counterparties fail to purchase or deliver the contracted quantities of natural gas, NGL, or crude oil or otherwise fail to perform. To the
extent that

50

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we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in such
prices.

Basis
risk is the risk that an adverse change in the hedging market will not be completely offset by an equal and opposite change in the price of the physical commodity being hedged. We
hedge our basis risk for natural gas but are generally unable to do so for NGL products. We have two different types of NGL product basis risk. First, NGL product basis risk stems from the geographic
price differentials between our sales locations and hedging contract delivery locations. We cannot hedge our geographic basis risk because there are no readily available products or markets. Second,
NGL product basis risk also results from the difference in relative price movements between crude oil and NGL products. We may use crude oil, instead of NGL products, in our hedges because the NGL
hedge products and markets are limited. Crude oil is highly correlated with certain NGL products.

As
a result of our 2001 Canadian E&P acquisition, our expected 2002 natural gas production and sales volumes from our E&P segment largely offset our keep-whole contractual
requirements for purchasing natural gas in our Appalachian GPM segment, thereby reducing our risk caused by fluctuations in natural gas prices. Consequently, we are transitioning our hedging strategy
to recognize this natural hedge between our E&P production and our natural gas purchase requirements in our Appalachian GPM business.

Prior
to our 2001 Canadian E&P acquisition, we hedged, in our GPM segment, our Appalachian processing margin (defined as revenues less cost of sales) by simultaneously selling propane or
crude oil while purchasing natural gas (Table I below). In our E&P segment, we historically hedged our natural gas sales (Table III below). As a result of our natural hedge, we are
transitioning our hedging strategy such that we no longer specifically hedge our Appalachian processing margin, nor our equivalent volume E&P natural gas sales, rather we hedge our NGL product sales
only (Table II below).

As
of December 31, 2001, under our historical hedging practice, the hedged Appalachian NGL product sales volumes and associated projected margin per NGL product gallon, were as
follows:

Table I
Hedged Processing Margin

|                                   |                                  | Three Months Ended |   | Total
Year Ended |  | Year Ended
|---------------------------------- | -------------------------------- | ------------------ | - | ---------------- |  | ----------
|
|NGL Volumes Hedged Using Crude Oil |                                  |                    |   |                  |  |           
|                                   | NGL gallons                      |                    |   | 5,233,356        |  |           
|                                   | NGL processing margin ($/gallon) |                    | $ | 0.24             |  | $         
|NGL Volumes Hedged Using Propane   |                                  |                    |   |                  |  |           
|                                   | Propane gallons                  |                    |   | 11,550,000       |  |           
|                                   | NGL processing margin ($/gallon) |                    | $ | 0.19             |  | $         
|Total NGL Volumes Hedged           |                                  |                    |   |                  |  |           
|                                   | NGL gallons                      |                    |   | 16,783,356       |  |           
|                                   | NGL processing margin ($/gallon) |                    | $ | 0.21             |  | $         

51

---

Under
our historical hedging strategy, we hedge our NGL product sales by selling forward propane or crude oil. As of December 31, 2001, we hedged Appalachian NGL product sales as
follows:

Table II  Hedged Sales Price for NGL Products

|                                             |  | Three Months Ended |  | Total
Year Ended |           | Year Ended
|-------------------------------------------- |  | ------------------ |  | ---------------- | --------- | ----------
|
|NGL volumes hedged using crude oil (gallons) |  |                   |  |                  | 7,625,720 |           
|NGL sales price per gallon                   |  |                   |  | $                | 0.43      |           

Under
Tables I and II, all projected margins or prices on open positions assume (a) the basis differentials between our sales location and the hedging contract's specified
location, and (b) the correlation between crude oil and NGL products, are consistent with historical averages.

Also
within our GPM segments, for certain Appalachian natural gas sales, as of December 31, 2001, we hedged 650,000 MMBtu and 54,000 MMBtu at $4.38 per MMBtu for 2002 and 2003,
respectively.

In
addition to these risk management tools, we utilize our NGL product storage facilities and contracts for third-party storage to build product inventories during lower-demand periods
for resale during higher-demand periods.

In
our E&P segment, under our historical hedging strategy we hedged our exposure to changes in market prices for our natural gas production by selling
fixed-for-float swaps and utilizing costless collars. Historically, we hedged a significant portion of our natural gas production. In light of our natural hedge, we are
transitioning our hedging strategy to limit our hedges to E&P natural gas production in excess of natural gas purchase requirements in our GPM segment. As of December 31, 2001, we hedged
natural gas volumes and prices as follows:

Table III  Hedged Natural Gas Sales

|                                |  | Three Months Ended |           | Total
Year Ended |   | Year Ended
|------------------------------- |  | ------------------ | --------- | ---------------- | - | ----------
|
|MMBtu                           |  |                    | 1,370,485 |                  |   | 1,316,343 
|$/MMBtu                         |  | $                  | 3.10      |                  | $ | 2.94      
|Henry Hub Equivalent $/MMBtu(1) |  | $                  | 3.64      |                  | $ | 3.48      

---

We
enter into speculative transactions on an infrequent basis. Specific approval by the Board of Directors is necessary prior to executing such transactions. Speculative transactions are
marked to market at the end of each accounting period, and any gain or loss is recognized in income for that

52

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period. There were no such speculative activities for the years ended December 31, 2001, 2000 and 1999.

9.    Adoption of SFAS No. 133

We adopted SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended, on
January 1, 2001. In accordance with the transition provisions of SFAS No. 133, we recorded on that date
a net-of-tax cumulative effect adjustment of approximately $1.2 million loss to other comprehensive income to recognize at fair value all derivatives that are designated
as cash-flow hedging instruments.

SFAS
No. 133 establishes accounting and reporting standards requiring derivative instruments to be recorded in the balance sheet as either an asset or liability measured at fair
value. Changes in the derivative instruments' fair value are recognized in earnings unless specific hedge accounting criteria are met.

SFAS
No. 133 allows hedge accounting for fair-value and cash-flow hedges. A fair-value hedge applies to a recognized asset or liability or an
unrecognized firm commitment. A cash-flow hedge applies to a forecasted transaction or a variable cash flow of a recognized asset or liability. SFAS No. 133 provides that the gain
or loss on a derivative instrument designated and qualifying as a fair-value hedging instrument as well as the offsetting loss or gain on the hedged item be recognized currently in
earnings in the same accounting period. SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash-flow
hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. (The
remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings.) Effectiveness is evaluated by the derivative instrument's ability to generate offsetting changes
in fair value or cash flows to the hedged item. We formally document, designate and assess the effectiveness of transactions receiving hedge accounting treatment.

In
our gathering, processing and marketing segment, we enter into fixed-price contracts for the sale of NGL products and fixed-price contracts for the purchase of natural gas (designated
as cash flow hedges) and NGL products (designated as fair value hedges). At January 1, 2001, we recorded a risk management asset of approximately $2.1 million and a deferred tax
liability of approximately $0.7 million, resulting in a $1.3 million gain recorded as a cumulative effect of change in accounting principle. At December 31, 2001, we recorded a
risk management asset of $1.1 million and a deferred tax liability of $0.4 million, resulting in a $0.7 million gain recorded to other comprehensive income.

In
our exploration and production segment, we enter into fixed-price contracts for the sale of natural gas. At January 1, 2001, we recorded a risk management liability of
approximately $3.9 million and a deferred tax recovery of approximately $1.4 million, resulting in $2.5 million loss recorded to other comprehensive income. At December 31,
2001, we recorded a risk management asset of $6.3 million and a deferred tax liability of $2.2 million, resulting in a $4.1 million gain recorded in other comprehensive income.

During
the second quarter of 2001, we entered into three-year contracts to fix interest rates on $10.0 million of our debt at 5.28% compared to a floating LIBOR (in
both cases, plus an applicable margin). At December 31, 2001, we recorded a risk management liability related to this interest rate derivative of $0.5 million and a deferred tax recovery
of $0.2 million, resulting in an other comprehensive loss of $0.3 million.

SFAS
No. 133 provides that hedge accounting must be discontinued on contracts when it becomes reasonably possible that the counterparty will default. During the fourth quarter of
2001, Enron Corporation and its subsidaries (Enron) filed for bankruptcy protection. In response to this filing, we

53

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have terminated all derivative contracts where Enron was the counterparty. As a result, we wrote off $1.1 million of risk management assets related to our cash flow hedges offset by
$0.1 million of risk management liabilities related to our fair value hedges. In addition, our contracts with Enron provide for netting of amounts owed to each other and as such we have netted
$0.6 million in amounts payable to Enron. The summary of the above transactions is a charge of $0.4 million to earnings in the fourth quarter 2001. In the case of discontinuing hedge
accounting for cash flow hedges, SFAS No. 133 provides the amount in other comprehensive income will be reclassified to earnings in the periods of the forecasted transactions. As such, we will
be reclassifying $0.8 million and $0.2 million from other comprehensive income to revenue, net of $0.3 million and $0.1 million of deferred taxes for 2002 and 2003, respectively.

Together
at January 1, 2001, these amounts comprise the above net-of-tax cumulative effect adjustment of approximately $1.2 million loss to other
comprehensive income. At December 31, 2001, with all transactions considered, there is a $5.1 million gain recorded in accumulated other comprehensive income.

10.  Income Taxes

The provision for income taxes is comprised of:

|          |                     | Year Ended December 31, |  
|--------- | ------------------- | ----------------------- | -
|
|
|Current:  |                     |                         |  
|          | Federal             |                         | $
|          | State               |                         |  
|          | Foreign             |                         |  
|          |                     |                         |  
|          | Total current       |                         |  
|          |                     |                         |  
|Deferred: |                     |                         |  
|          | Federal             |                         |  
|          | State               |                         |  
|          | Foreign             |                         |  
|          |                     |                         |  
|          | Total deferred      |                         |  
|          |                     |                         |  
|          | Total tax provision |                         | $
|          |                     |                         |  

54

---

The
deferred tax liabilities (assets) are comprised of the tax effect of the following:

|                                                   |                                       | December 31, 2001 |        | December 31, 2000 |  
|-------------------------------------------------- | ------------------------------------- | ----------------- | ------ | ----------------- | -
|
|Property, plant and equipment                      |                                       | $                 | 45,583 |                   | $
|Risk management assets                             |                                       |                   | 2,807  |                   |  
|Other assets                                       |                                       |                   | 337    |                   |  
|                                                   |                                       |                   |        |                   |  
|                                                   | Total deferred income tax liabilities |                   |        | 48,727            |  
|                                                   |                                       |                   |        |                   |  
|Alternative minimum tax (AMT) credit carryforwards |                                       |                   | (2,031 | )                 |  
|Federal net operating loss (NOL) carryforwards     |                                       |                   | (1,152 | )                 |  
|State net operating loss (NOL) carryforwards       |                                       |                   | (227   | )                 |  
|Intangible assets                                  |                                       |                   | (6     | )                 |  
|                                                   |                                       |                   |        |                   |  
|                                                   | Total deferred income tax assets      |                   |        | (3,416            | )
|                                                   |                                       |                   |        |                   |  
|Net deferred tax liability                         |                                       | $                 | 45,311 |                   | $
|                                                   |                                       |                   |        |                   |  

55

---

The differences between the provision for income taxes at the statutory rate and the actual provision for income taxes, are summarized as follows:

|                                           |                    | Year Ended December 31, |      
|------------------------------------------ | ------------------ | ----------------------- | -----
|
|
|Income tax at statutory rate               |                    | $                       | 1,538
|State income taxes, net of federal benefit |                    |                         | 245  
|Income tax credits                         |                    |                         |     
|Foreign operations:                        |                    |                         |      
|                                           | Resource allowance |                         |      
|                                           | Crown royalties    |                         |      
|Other                                      |                    |                         | (39  
|                                           |                    |                         |      
|Total                                      |                    | $                       | 1,581
|                                           |                    |                         |      

At
December 31, 2001, we had federal and state NOL carryforwards and AMT credit carryforwards for federal income tax purposes of approximately $3.3 million,
$4.5 million and $2.0 million, respectively. These carryforwards expire as follows:

|Expiration Dates |  | Federal NOL |       | State NOL |   | AMT  
|---------------- |  | ----------- | ----- | --------- | - | -----
|
|2006             |  |             |      |           |   | 27   
|2018             |  |             |      |           |   | 470  
|2019             |  |             |      |           |   | 895  
|2021             |  |             | 3,292 |           |   | 3,114
|No expiration    |  |             |      |           |   |     
|                 |  |             |       |           |   |      
|Total            |  | $           | 3,292 |           | $ | 4,506
|                 |  |             |       |           |   |      

We
believe that the NOL carryforwards and AMT credit carryforwards will be fully utilized. They are expected to be offset by existing taxable temporary differences reversing within the
carryforward period or are expected to be realized by achieving future profitable operations based on our dedicated and owned reserves, dedicated reserves behind its processing plants, past results of
operations, history, and projections of future results of operations.

11.  Stock Compensation Plans

At December 31, 2001, we have two stock-based compensation plans, which are described below. We apply APB Opinion No. 25, Accounting for Stock Issued to
Employees,and related Interpretations in accounting for its plans. Accordingly, no compensation cost has been recognized
for our fixed stock option plans. Had compensation cost for our two stock-based compensation plans been determined based on the fair value at the grant dates under those plans consistent with the
method prescribed by

56

---

SFAS No. 123,Accounting for Stock-Based Compensation,our net income and earnings per share would have been reduced to the pro forma amounts
listed below:

|                                     |  |             |  | Year Ended December 31,
|------------------------------------ |  | ----------- |  | -----------------------
|
|
|Net income                           |  | As reported |  | $                      
|                                     |  | Pro forma   |  |                        
|Basic earnings per share             |  | As reported |  | $                      
|                                     |  | Pro forma   |  |                        
|Earnings per share assuming dilution |  | As reported |  | $                      
|                                     |  | Pro forma   |  |                        

Under
the 1996 Stock Incentive Plan, we may grant options to our employees for up to 850,000 shares of common stock in the aggregate. Under this plan, the exercise price of each option
equals the market price of our stock on the date of the grant, and an option's maximum term is ten years. Options are
granted periodically throughout the year and vest at the rate of 25% per year for options granted in 1999 and after, and 20% per year for options granted prior to 1999.

Under
the 1996 Non-employee Director Stock Option Plan, we may grant options to our non-employee directors for up to 20,000 shares of common stock in the
aggregate. Under this plan, the exercise price of each option equals the market price of our stock on the date of the grant, and an option's maximum term is three years. Options are granted upon the
date the director first becomes a director and biannually thereafter. Options granted upon the date the director first becomes a director vest at the rate of 33.33% per year. Biannual options vest
100% on the first anniversary of the option grant date.

The
fair value of each option granted in 2001, 2000 and 1999 was estimated using the Black-Scholes option pricing model. The following assumptions were used to compute the weighted
average fair market value of options granted:

|                         |  | 2001    |   | 2000    |   | 1999    |  
|------------------------ |  | ------- | - | ------- | - | ------- | -
|Expected life of options |  | 6 years |   | 6 years |   | 6 years |  
|Risk free interest rates |  | 4.84    | % | 5.93    | % | 6.22    | %
|Estimated volatility     |  | 52      | % | 43      | % | 40      | %
|Dividend yield           |  | 0.0     | % | 0.0     | % | 0.0     | %

A
summary of the status of our two fixed stock option plans as of December 31, 2001, 2000 and 1999, and changes during the years ended on those dates are presented below:

|                                                                      |  | 2001 |         | 2000 |   | 1999
|--------------------------------------------------------------------- |  | ---- | ------- | ---- | - | ----
|
|Fixed Options                                                         |  |      |         |      |   |     
|Outstanding at beginning of year                                      |  |      | 740,246 |      | $ | 9.15
|Granted                                                               |  |      | 71,464  |      |   | 7.62
|Exercised                                                             |  |      | (2,713  | )    |   | 6.74
|Cancelled                                                             |  |      | (16,049 | )    |   | 9.62
|                                                                      |  |      |         |      |   |     
|Outstanding at end of year                                            |  |      | 792,948 |      | $ | 9.18
|                                                                      |  |      |         |      |   |     
|Options exercisable at December 31, 2001, 2000 and 1999, respectively |  |      | 478,265 |      |   |     
|Weighted-average fair value of options granted during the year        |  | $    | 4.11    |      |   |     

57

---

The following table summarizes information about fixed stock options outstanding at December 31, 2001:

|                 |  | Options Outstanding |  |     |  |  
|---------------- |  | ------------------- |  | --- |  | -
|
|
|
|$5.38 to $7.65   |  | 221,450             |  | 5.6 |  | $
|$7.86 to $10.00  |  | 236,987             |  | 5.8 |  |  
|$10.50 to $10.50 |  | 69,675              |  | 6.9 |  |  
|$10.75 to $10.75 |  | 192,649             |  | 5.8 |  |  
|$11.25 to $11.38 |  | 72,187              |  | 8.6 |  |  
|                 |  |                     |  |     |  |  
|$5.38 to $11.38  |  | 792,948             |  | 6.1 |  | $
|                 |  |                     |  |     |  |  

12.  Earnings Per Share

The following table shows the amounts used in computing earnings per share and weighted average number of shares of dilutive potential common stock for the years
ended December 31, 2001, 2000 and 1999:

|                                                                                                           |               | Year Ended December 31,
|---------------------------------------------------------------------------------------------------------- | ------------- | -----------------------
|
|
|Net income                                                                                                 |               | $                      
|                                                                                                           |               |                        
|Weighted average number of outstanding shares of common stock used in earnings per share                   |               |                        
|Effect of dilutive securities:                                                                             |               |                        
|                                                                                                           | Stock options |                        
|                                                                                                           |               |                        
|Weighted average number of outstanding shares of common stock used in earnings per share assuming dilution |               |                        
|                                                                                                           |               |                        

13.  Segment Reporting

We classify our operations into two reportable segments, as follows:



We
evaluate the performance of our segments and allocate resources to them based on operating income. There are no intersegment revenues. We conduct our business in the United States and
Canada.

The
table below presents information about operating income for the reported segments for the three years ended December 31, 2001, 2000 and 1999. Operating income for each segment
includes total revenues less cost of goods sold, operating expenses, depreciation and depletion and excludes selling, general and administrative expenses, interest expense, interest income and income
taxes. We

58

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have not reported asset information by reportable segment because we do not produce such information internally.

|                             |  | Gathering, Processing and
Marketing |         | Exploration and
Production |   | Total 
|---------------------------- |  | ----------------------------------- | ------- | -------------------------- | - | ------
|
|Year Ended December 31, 2001 |  |                                     |         |                            |   |       
|Revenues                     |  | $                                   | 173,890 |                            | $ | 14,628
|Segment operating income     |  | $                                   | 11,986  |                            | $ | 4,713 
|Year Ended December 31, 2000 |  |                                     |         |                            |   |       
|Revenues                     |  | $                                   | 217,567 |                            | $ | 4,161 
|Segment operating income     |  | $                                   | 24,197  |                            | $ | 1,241 
|Year Ended December 31, 1999 |  |                                     |         |                            |   |       
|Revenues                     |  | $                                   | 105,169 |                            | $ | 1,861 
|Segment operating income     |  | $                                   | 11,899  |                            | $ | 59    

A
reconciliation of total segment operating income to total consolidated income before taxes is as follows:

|                                    |                     | Year Ended December 31, |       
|----------------------------------- | ------------------- | ----------------------- | ------
|
|
|Total segment operating income      |                     | $                       | 16,699
|General and administrative expenses |                     |                         | (8,377
|Interest income                     |                     |                         | 130   
|Interest expense                    |                     |                         | (3,830
|Gain on sale of assets              |                     |                         |      
|Other income (expense)              |                     |                         | (231  
|                                    |                     |                         |       
|                                    | Income before taxes |                         | $     
|                                    |                     |                         |       

14.  Subsequent Event

On January 31, 2001, we filed a registration statement on Form S-1 with the Securities and Exchange Commission relating to a proposed
underwritten initial public offering of 2,000,000 common units, representing limited partner interests in MarkWest Energy Partners, L.P., a Delaware limited partnership. All of the units sold
in the offering will be sold by MarkWest Energy Partners, L.P.

On
January 31, 2002, MarkWest Energy Partners, L.P., a newly formed limited partnership created to own and operate most of our gathering, processing, transportation,
storage, and fractionation assets in Appalachia and Michigan, filed a registration statement on Form S-1 with the Securities and Exchange
Commission for an initial public offering. The partnership currently anticipates offering to the public approximately 40% of the limited partner interests in the partnership. We and certain of our
affiliates will own the general partner of the partnership, as well as the remaining 60% of the limited partner interests in the form of subordinated units. The rights of the holders of subordinated
units to receive distributions of cash from the partnership are subordinated to the rights of the public unitholders to receive such distributions. Any proceeds we receive from the offering and
related debt financing will be used to reduce our outstanding debt. For financial reporting purposes, the results of operations of MarkWest Energy Partners, L.P. will be consolidated with our
operating results.

59

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15.  Commitments and Contingencies



In February 2001, three complaints were filed against us in the Circuit Court of Wayne County, West Virginia, by Columbia Gas Transmission Corporation and
Columbia Natural Resources, Inc.; Equitable Production Company and Equitable Energy LLC; and Cobra Petroleum Company et al. These complaints each allege breach of contract and seek
various forms of relief (including injunctive relief) and damages. On March 1, 2002, we reported that these suits were settled out of court. Two of the three actions have been dismissed and the
claims have been released. Documentation providing for the dismissal of the third action and dismissal of those claims is in the process of execution and filing with the Court.

On
June 6, 2001, Level Propane Gases, Inc. filed suit against us in the Court of Common Pleas, Cuyahoga County, Ohio alleging breach of contract for failure to furnish a
specified quantity of gallons of propane gas on a monthly basis from May 1, 2000 to April 30, 2001, and seeking direct and punitive damages. On July 25, 2001, we filed a motion to
stay proceedings pending arbitration in Denver, Colorado in the Court of Common Pleas, Cuyahoga County, Ohio. The Court of Common Pleas granted the motion to stay proceedings. MarkWest filed a
petition with the United States District Court for the District of Colorado seeking an order compelling Level Propane to comply with the arbitration provisions of its agreements with MarkWest. The
United States District Court affirmed Level Propane's arbitration obligation. MarkWest has initiated an arbitration proceeding against Level Propane with the American Arbitration Association in
Denver, Colorado seeking recovery of unpaid amounts owed by Level Propane for propane product received from MarkWest. While Level Propane has indicated the intention to renew its breach of contract
claims in the arbitration proceeding, Level Propane has not yet paid the required arbitration fee and those counterclaims have not yet been asserted. The agreements between the parties contain
limitation of liability provisions, including a prohibition on recovery of punitive damages, and MarkWest believes that Level's breach of contract claim has no merit.

On
October 2, 2001, Ross Brothers Construction Company filed a complaint against MarkWest Hydrocarbon, Inc. in the Greenup Circuit Court in Kentucky. The Complaint seeks
recovery of damages
for work performed and materials furnished in connection with a contract for construction of additions and improvements to MarkWest's Siloam plant expansion in Greenup County, Kentucky. The labor and
material at issue were provided outside of the scope of the original contract. MarkWest removed that action to the United States District Court for the Eastern District of Kentucky, Ashland Division.
MarkWest believes that an accord and satisfaction was reached under applicable Kentucky law in July, 2000 by reason of the negotiation by Ross brothers of a check tendered by MarkWest in full and
final satisfaction of any additional payments claimed to have been due. MarkWest has filed a motion for summary judgment on that ground, which motion is presently pending.



We have various non-cancelable operating lease agreements for equipment and office space expiring at various times through fiscal 2015. Annual rent
expense under these operating leases was $2.0 million, $1.8 million and $0.9 million for the three years ended December 31, 2001, 2000 and 1999,

60

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respectively. Our minimum future lease payments under these operating leases as of December 31, 2001, are as follows:

(in thousands)2002

$
2,3782003


1,9802004


1,8432005


1,8552006


1,6452007 and thereafter


4,131Total

$
13,832


16.  Quarterly Results of Operations (Unaudited)

The following summarizes certain quarterly results of operations:

|                                        |  | Three Months Ended
|--------------------------------------- |  | ------------------
|
|2001                                    |  |                   
|Operating revenue                       |  | $                 
|Income from operations(1)(2)            |  |                   
|Net income (loss)(2)                    |  |                   
|Basic earnings per share(2)             |  |                   
|Earnings per share assuming dilution(2) |  |                   
|2000                                    |  |                   
|Operating revenue                       |  | $                 
|Income from operations(1)               |  |                   
|Net income(3)                           |  |                   
|Basic earnings per share                |  |                   
|Earnings per share assuming dilution    |  |                   

---

17.  Supplemental Information on Oil and Gas Producing Activities (Unaudited)

The following information is presented in accordance with SFAS No. 69,Disclosure about Oil and Gas Producing
Activities.

61

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(A)  Costs Incurred in Oil and Gas Exploration and Development ActivitiesThe following costs were incurred in oil
and gas exploration and development activities during the years ended December 31, 2001, 2000 and 1999:

United States

Canada

Total(in thousands)2001Property acquisition costs (undeveloped leases and proved properties)

$
4,823

$
79,496

$
84,319Exploration costs


999


1,387


2,386Development costs


3,427


1,826


5,253Total

$
9,249

$
82,709

$
91,9582000Property acquisition costs (undeveloped leases and proved properties)

$
1,357

$


$
1,357Exploration costs


971





971Development costs


1,818





1,818Total

$
4,146

$


$
4,1461999Property acquisition costs (undeveloped leases and proved properties)

$
2,231

$


$
2,231Exploration costs


1,776





1,776Development costs


435





435Total

$
4,442

$


$
4,442


(B)  Aggregate Capital CostsThe aggregate capitalized costs relating to oil and gas activities at
December 31 of each of the years indicated were as follows:

2001

2000

1999(in thousands)Costs related to proved properties

$
72,294

$
12,481

$
11,167Costs related to unproved properties


36,629


4,072


1,972Costs related to equipment and facilities


4,570


1,484


1,379113,493


18,037


14,518Less: accumulated depreciation and depletion


(7,119
)

(2,018
)

(1,362
)Net capitalized costs

$
106,374

$
16,019

$
13,156


(C)  Results of Operations from Producing ActivitiesResults of operations from producing activities for the years
ended December 31, 2001, 2000 and 1999 are presented below. Income taxes are

62

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different from income taxes shown in the Consolidated Statements of Operations because this table excludes general and administrative and interest expense.

|     |                                      | United States       |   | Canada |       | Total |       
|---- | ------------------------------------ | ------------------- | - | ------ | ----- | ----- | ------
|
|2001 |                                      |                     |   |        |       |       |       
|     | Revenues:                            |                     |   |        |       |       |       
|     |                                      | Sales, net of taxes |   | $      | 9,260 |       | $     
|     |                                      | Other               |   |        | 293   |       |       
|     |                                      |                     |   |        |       |       |       
|     |                                      | Total               |   |        | 9,553 |       |       
|     | Cost of sales (transportation costs) |                     |   | (1,440 | )     |       | (431  
|     | Lease operating costs                |                     |   | (1,926 | )     |       | (948  
|     | Depreciation and depletion           |                     |   | (1,726 | )     |       | (3,445
|     |                                      |                     |   |        |       |       |       
|     | Operating income                     |                     |   | 4,461  |       |       | 251   
|     | Income tax expense                   |                     |   | (1,726 | )     |       | (76   
|     |                                      |                     |   |        |       |       |       
|     | Results of operations                |                     | $ | 2,735  |       | $     | 175   
|     |                                      |                     |   |        |       |       |       
|2000 |                                      |                     |   |        |       |       |       
|     | Revenues:                            |                     |   |        |       |       |       
|     |                                      | Sales, net of taxes |   | $      | 3,874 |       | $     
|     |                                      | Other               |   |        | 287   |       |       
|     |                                      |                     |   |        |       |       |       
|     |                                      | Total               |   |        | 4,161 |       |       
|     | Cost of sales (transportation costs) |                     |   | (833   | )     |       |      
|     | Lease operating costs                |                     |   | (1,429 | )     |       |      
|     | Depreciation and depletion           |                     |   | (658   | )     |       |      
|     |                                      |                     |   |        |       |       |       
|     | Operating income                     |                     |   | 1,241  |       |       |      
|     | Income tax benefit                   |                     |   | 185    |       |       |      
|     |                                      |                     |   |        |       |       |       
|     | Results of operations                |                     | $ | 1,426  |       | $     |      
|     |                                      |                     |   |        |       |       |       
|1999 |                                      |                     |   |        |       |       |       
|     | Revenues:                            |                     |   |        |       |       |       
|     |                                      | Sales, net of taxes |   | $      | 1,679 |       | $     
|     |                                      | Other               |   |        | 182   |       |       
|     |                                      |                     |   |        |       |       |       
|     |                                      | Total               |   |        | 1,861 |       |       
|     | Cost of sales (transportation costs) |                     |   | (322   | )     |       |      
|     | Lease operating costs                |                     |   | (919   | )     |       |      
|     | Depreciation and depletion           |                     |   | (561   | )     |       |      
|     |                                      |                     |   |        |       |       |       
|     | Operating income                     |                     |   | 59     |       |       |      
|     | Income tax benefit                   |                     |   | 53     |       |       |      
|     |                                      |                     |   |        |       |       |       
|     | Results of operations                |                     | $ | 112    |       | $     |      
|     |                                      |                     |   |        |       |       |       

(D)  Estimated Proved Oil and Gas ReservesOur estimate of our proved and proved developed future net recoverable
oil and gas reserves and changes for 2001, 2000 and 1999 follows. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., prices and costs as of the date
the estimate is made.

63

---

Proved
developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and
gas reserves are reserves that are expected to be recovered from new wells on drilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Proved
quantities of crude oil and natural gas liquids were not significant in any of the years presented.

Reserve
estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of
development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates of economically
recoverable reserves and of future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Results of subsequent drilling,
testing and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in commodity prices
and operating costs. Any significant revision of reserve estimates could materially adversely affect our financial condition and results of operations.

|                              |                                 | Gas    |       
|----------------------------- | ------------------------------- | ------ | ------
|
|Balance at December 31, 1998  |                                 | 26,049 |       
|                              | Revisions of previous estimates |        | 1,032 
|                              | Purchase of minerals in place   |        | 2,253 
|                              | Extensions and discoveries      |        | 4,355 
|                              | Production                      |        | (969  
|                              | Sale of minerals in place       |        |      
|                              |                                 |        |       
|Balance at December 31, 1999  |                                 | 32,720 |       
|                              | Revisions of previous estimates |        | (60   
|                              | Purchase of minerals in place   |        | 1,524 
|                              | Extensions and discoveries      |        | 2,253 
|                              | Production                      |        | (1,376
|                              | Sale of minerals in place       |        | (476  
|                              |                                 |        |       
|Balance at December 31, 2000  |                                 | 34,585 |       
|                              | Purchase of minerals in place   |        | 6,900 
|                              | Revisions of previous estimates |        | (2,895
|                              | Extensions and discoveries      |        | 5,730 
|                              | Production                      |        | (2,832
|                              | Sale of minerals in place       |        |      
|                              |                                 |        |       
|Balance at December 31, 2001  |                                 | 41,488 |       
|                              |                                 |        |       
|Proved developed reserves at: |                                 |        |       
|                              | December 31, 1998               |        | 13,665
|                              | December 31, 1999               |        | 22,114
|                              | December 31, 2000               |        | 22,804
|                              | December 31, 2001               |        | 28,586

(E)  Standardized Measure of Discounted Future Net Cash FlowsEstimated discounted future net cash flows and
changes therein were determined in accordance with SFAS No. 69,Disclosures about Oil and Gas Producing Activities.Certain information
concerning the assumptions used in computing

64

---

the valuation of proved reserves and their inherent limitations are discussed below. We believe such information is essential for a proper understanding and assessment of the data presented.

Future
cash inflows are computed by applying year-end prices of oil and gas relating to our proved reserves to the year-end quantities of those reserves. Future
price changes are considered only to the extent provided by contractual arrangements, including hedging contracts in existence at year-end, for the years ended December 31, 2000 and
1999.

The
assumptions used to compute estimated future net revenues do not necessarily reflect our expectations of actual revenues or costs, or their present worth. In addition, variations
from the expected production rate also could result directly or indirectly from factors outside of our control, such as unintentional delays in development, changes in prices or regulatory controls.
The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are
sold in place, additional economic considerations could also affect the amount of cash eventually realized.

Future
development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved reserves at the end of the year, based on
year-end costs and assuming continuation of existing economic conditions.

Future
income tax expenses are estimated using an estimated combined federal and state income tax rate of 39% in the United States and a combined federal and provincial rate of 42.62% in
Canada. Permanent differences in Canadian resource allowances and natural gas-related tax credits are recognized. Estimates for future general and administrative and interest expense have
not been considered.

An
annual discount rate of 10% was used to reflect the timing of the future net cash flows relating to proved reserves.

|                                                         |  | December 31, 2001 |        
|-------------------------------------------------------- |  | ----------------- | -------
|
|
|Future gas sales                                         |  | $                 | 101,228
|Future production costs                                  |  |                   | (39,679
|Future development costs                                 |  |                   | (4,194 
|Future income taxes                                      |  |                   | (18,654
|                                                         |  |                   |        
|Future net cash flows                                    |  |                   | 38,701 
|10% annual discount for estimated timing of cash flows   |  |                   | (20,335
|                                                         |  |                   |        
|Standardized measure of discounted future net cash flows |  | $                 | 18,366 
|                                                         |  |                   |        

Present
value of future net cash flows before income taxes was $26,269 in the United States and $32,628 in Canada at December 31, 2001. Present value of future net cash flows
before income taxes,

65

---

including hedging contracts in place at December 31, 2001, was $27,919 in the United States and $38,824 in Canada.

|                                                         |  | December 31, 2000 |        
|-------------------------------------------------------- |  | ----------------- | -------
|
|
|Future gas sales                                         |  | $                 | 296,454
|Future production costs                                  |  |                   | (52,047
|Future development costs                                 |  |                   | (1,484 
|Future income taxes                                      |  |                   | (90,103
|                                                         |  |                   |        
|Future net cash flows                                    |  |                   | 152,820
|10% annual discount for estimated timing of cash flows   |  |                   | (87,770
|                                                         |  |                   |        
|Standardized measure of discounted future net cash flows |  | $                 | 65,050 
|                                                         |  |                   |        

Present
value of future net cash flows before income taxes was $97,953 in the United States.

|                                                         |  | December 31, 1999 |        
|-------------------------------------------------------- |  | ----------------- | -------
|
|
|Future gas sales                                         |  | $                 | 75,290 
|Future production costs                                  |  |                   | (32,541
|Future development costs                                 |  |                   | (2,970 
|Future income taxes                                      |  |                   | (12,982
|                                                         |  |                   |        
|Future net cash flows                                    |  |                   | 26,797 
|10% annual discount for estimated timing of cash flows   |  |                   | (15,332
|                                                         |  |                   |        
|Standardized measure of discounted future net cash flows |  | $                 | 11,465 
|                                                         |  |                   |        

Present
value of future net cash flows before income taxes was $16,122 in the United States.

Changes in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas ReservesAn analysis of the
changes in the standardized measure of discounted future net cash flows during each of the last three years is as follows.

|                                                                                                               |                                                                         | December 31, 2001 |       
|-------------------------------------------------------------------------------------------------------------- | ----------------------------------------------------------------------- | ----------------- | ------
|
|
|Standardized measure of discounted future net cash flows relating to proved gas reserves, at beginning of year |                                                                         | $                 | 65,050
|Changes resulting from:                                                                                        |                                                                         |                   |       
|                                                                                                               | Sales and transfers of natural gas produced, net of production costs    |                   |       
|                                                                                                               | Net changes in prices and production costs related to future production |                   |       
|                                                                                                               | Previously estimated development costs incurred during the year         |                   |       
|                                                                                                               | Changes in future development costs                                     |                   |       
|                                                                                                               | Extensions and discoveries                                              |                   |       
|                                                                                                               | Revisions of previous quantity estimates                                |                   |       
|                                                                                                               | Purchases of reserves in place                                          |                   |       
|                                                                                                               | Sales of reserves in place                                              |                   |       
|                                                                                                               | Changes in production rates and other                                   |                   |       
|                                                                                                               | Accretion of discount                                                   |                   |       
|                                                                                                               | Net change in income taxes                                              |                   |       
|                                                                                                               |                                                                         |                   |       
|Standardized measure of discounted future net cash flows relating to proved gas reserves, at end of year       |                                                                         | $                 | 18,366
|                                                                                                               |                                                                         |                   |       

66

---

The
computation at the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001 was based on year end
natural gas prices of approximately $2.39 per Mcfe in the United States and approximately $2.19 per Mcfe in Canada, equivalent to $2.65 per MMBtu at the Henry Hub.

|                                                                                                               |                                                                         | December 31, 2000 |       
|-------------------------------------------------------------------------------------------------------------- | ----------------------------------------------------------------------- | ----------------- | ------
|
|
|Standardized measure of discounted future net cash flows relating to proved gas reserves, at beginning of year |                                                                         | $                 | 11,465
|Changes resulting from:                                                                                        |                                                                         |                   |       
|                                                                                                               | Sales and transfers of natural gas produced, net of production costs    |                   |       
|                                                                                                               | Net changes in prices and production costs related to future Production |                   |       
|                                                                                                               | Previously estimated development costs incurred during the year         |                   |       
|                                                                                                               | Changes in future development costs                                     |                   |       
|                                                                                                               | Extensions and discoveries                                              |                   |       
|                                                                                                               | Revisions of previous quantity estimates                                |                   |       
|                                                                                                               | Purchases of reserves in place                                          |                   |       
|                                                                                                               | Sales of reserves in place                                              |                   |       
|                                                                                                               | Changes in production rates and other                                   |                   |       
|                                                                                                               | Accretion of discount                                                   |                   |       
|                                                                                                               | Net change in income taxes                                              |                   |       
|                                                                                                               |                                                                         |                   |       
|Standardized measure of discounted future net cash flows relating to proved gas reserves, at end of year       |                                                                         | $                 | 65,050
|                                                                                                               |                                                                         |                   |       

The
computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2000 was based on year end
natural gas prices of approximately $8.56 per Mcfe in the United States.

|                                                                                                               |                                                                         | December 31, 1999 |       
|-------------------------------------------------------------------------------------------------------------- | ----------------------------------------------------------------------- | ----------------- | ------
|
|
|Standardized measure of discounted future net cash flows relating to proved gas reserves, at beginning of year |                                                                         | $                 | 4,973 
|Changes resulting from:                                                                                        |                                                                         |                   |       
|                                                                                                               | Sales and transfers of natural gas produced, net of production costs    |                   |       
|                                                                                                               | Net changes in prices and production costs related to future production |                   |       
|                                                                                                               | Previously estimated development costs incurred during the year         |                   |       
|                                                                                                               | Changes in future development costs                                     |                   |       
|                                                                                                               | Extensions and discoveries                                              |                   |       
|                                                                                                               | Revisions of previous quantity estimates                                |                   |       
|                                                                                                               | Purchases of reserves in place                                          |                   |       
|                                                                                                               | Sales of reserves in place                                              |                   |       
|                                                                                                               | Changes in production rates and other                                   |                   |       
|                                                                                                               | Accretion of discount                                                   |                   |       
|                                                                                                               | Net change in income taxes                                              |                   |       
|                                                                                                               |                                                                         |                   |       
|Standardized measure of discounted future net cash flows relating to proved gas reserves, at end of year       |                                                                         | $                 | 11,465
|                                                                                                               |                                                                         |                   |       

The
computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 1999 was based on year end
natural gas prices of approximately $2.30 per Mcfe in the United States.

67

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

PART III

Certain information required by Part III is omitted from this Report. We will file a definitive proxy statement pursuant to Regulation 14A (the
"Proxy Statement") not later than 120 days after the end of the fiscal year covered by this Report, and certain information included in the Proxy Statement is incorporated into Part III
of this Report by reference. Only those sections of the Proxy Statement that specifically address the items set forth herein are incorporated by reference.

ITEM 10. DIRECTORS OF THE REGISTRANT AND CERTAIN EXECUTIVE OFFICERS OF MARKWEST HYDROCARBON, INC.

The information required by this Item is incorporated by reference from the section labeled "Directors and Executive Officers" in the Proxy Statement.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this Item is incorporated by reference from the section labeled "Compensation of Directors" and "Executive Compensation" excluding the
"Board Compensation Committee Report on Executive Compensation" and the "Performance Graph" in the Proxy Statement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by this Item is incorporated by reference from the section labeled "Principal Stockholders" in the Proxy Statement.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by this Item is incorporated by reference from the section labeled "Certain Relationships and Related Transactions" in the Proxy
Statement.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K





68

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|2.1   |     | Purchase and Sale Agreement between MarkWest Hydrocarbon, Inc., and Michigan Energy Company, L.L.C., dated November 21, 1997 (filed as Exhibit 2.1 to MarkWest Hydrocarbon, Inc.'s Form 8-K
filed on January 29, 1998, and incorporated herein by reference).             
|----- | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|2.2   | (3) | Share Purchase Agreement between MarkWest Acquisition Corporation and Kaiser Energy, Ltd.                                                                                                                                                                                 
|2.3   | (3) | Share Purchase Agreement between MarkWest Acquisition Corporation and Brian E. Hiebert, Guy C. Crierson, Ian R. DeBie, Gordon A. Maybee, Erin Hiebert, Raylene Grierson, Kathleen DeBie, and Patricia Maybee.                                                             
|3.1   | (1) | Certificate of Incorporation of MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                                
|3.2   | (1) | Bylaws of MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                                                      
|10.1  | (2) | Amended and Restated Reorganization Agreement made as of August 1, 1996, by and among MarkWest Hydrocarbon, Inc.; MarkWest Hydrocarbon Partners, Ltd.; MWHC Holding, Inc.; RIMCO Associates, Inc.; and each of the limited
partners of MarkWest Hydrocarbon Partners, Ltd.
|10.2  | (2) | 1996 Incentive Compensation Plan (filed as Exhibit 10.25).                                                                                                                                                                                                                
|10.3  | (1) | 1996 Stock Incentive Plan (filed as Exhibit 10.26).                                                                                                                                                                                                                       
|10.4  | (1) | 1996 Non-employee Director Stock Option Plan (filed as Exhibit 10.27).                                                                                                                                                                                                    
|10.5  | (1) | Form of Non-Compete Agreement between John M. Fox and MarkWest Hydrocarbon, Inc. (filed as Exhibit 10.28).                                                                                                                                                                
|10.6  |     | MarkWest Hydrocarbon, Inc., 1997 Severance and Non-Compete Plan (filed as Exhibit 10.1 to MarkWest Hydrocarbon, Inc.'s Form 10-Q for the three months ended September 30, 1997, and incorporated herein by
reference).                                                    
|10.7  | (3) | 4th Amended and Restated Credit Agreement among MarkWest Hydrocarbon, Inc., and various lenders.                                                                                                                                                                          
|10.8  | (3) | Canadian Credit Agreement among MarkWest Resources Canada Corp. and various lenders.                                                                                                                                                                                      
|10.9  | *   | First Amendment to the Fourth Amended and Restated Credit Agreement among MarkWest Hydrocarbon, Inc., and various lenders dated March 29, 2002.                                                                                                                           
|10.10 | *   | First Amendment to the Canadian Credit Agreement among MarkWest Resources Canada Corp. and various lenders dated March 29, 2002.                                                                                                                                          
|11.   | *   | Statement regarding computation of earnings per share.                                                                                                                                                                                                                    
|21.   | *   | List of Subsidiaries of MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                                        
|23.1  | *   | Consent of PricewaterhouseCoopers LLP                                                                                                                                                                                                                                     
|      |     |                                                                                                                                                                                                                                                                           

69

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|23.2 | * | Consent of Cawley, Gillespie & Associates, Inc.  
|---- | - | -------------------------------------------------
|23.3 | * | Consent of Gilbert Laustsen Jung Associates, Ltd.

---

70

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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, in the City of Englewood, State of Colorado, on March 29, 2002.

| |  | MarkWest Hydrocarbon, Inc.
(Registrant)
| |  | ---------------------------------------
| |  | 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 and on
the dates indicated.

| |  | /s/JOHN M. FOXJohn M. Fox President, Chief Executive
Officer and Director                                                                         |  | March 29, 2002
| |  | ------------------------------------------------------------------------------------------------------------------------------------------------- |  | --------------
| |  | /s/GERALD A. TYWONIUKGerald A. Tywoniuk Senior Vice President of Finance and Chief Financial Officer
(Principal Financial and Accounting Officer) |  | March 29, 2002
| |  | /s/ARTHUR J. DENNEYArthur J. Denney Executive Vice President and Director                                                                         |  | March 29, 2002
| |  | /s/WILLIAM A. KELLSTROMWilliam A. Kellstrom Director                                                                                              |  | March 29, 2002
| |  | /s/KAREN L. ROGERSKaren L. Rogers Director                                                                                                        |  | March 29, 2002
| |  | /s/BARRY W. SPECTORBarry W. Spector Director                                                                                                      |  | March 29, 2002
| |  | /s/DONALD D. WOLFDonald D. Wolf Director                                                                                                          |  | March 29, 2002

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