Use these links to rapidly review the documentTable of Contents ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

---

---

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

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, 2002.
|- | ---------------------------------------------------------------------------------------------------------------------------------
|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

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

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

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

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

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

Indicate
by check mark whether the registrant (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

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

The
aggregate market value of voting common stock held by non-affiliates of the registrant on June 30, 2002 was approximately $29,815,042.

The
number of shares outstanding of the registrant's common stock as of February 28, 2003, was 8,520,942.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by certain items of 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 2003 annual meeting of stockholders.

---

---





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



|         |  |                 |  |                                                                                      
|-------- |  | --------------- |  | -------------------------------------------------------------------------------------
|PART I  
|         |  | Items 1. and 2. |  | Business and Properties                                                              
|         |  | 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                                       
|         |  | Item 14.        |  | Controls and Procedures                                                              
|PART IV 
|         |  | Item 15.        |  | Exhibits, Financial Statement Schedules, and Reports on Form 8-K                     



|Bbls                                                                          |  | barrels                                                           
|----------------------------------------------------------------------------- |  | ------------------------------------------------------------------
|Btu                                                                           |  | one British thermal unit, an energy measurement                   
|Gal/d                                                                         |  | gallons per day                                                   
|MBbl                                                                          |  | one million barrels                                               
|Mcf                                                                           |  | one thousand cubic feet of natural gas                            
|Mcfe                                                                          |  | one thousand cubic feet of natural gas equivalent                 
|Mcf/d                                                                         |  | one thousand cubic feet of natural gas per day                    
|Mcfe/d                                                                        |  | one thousand cubic feet of natural gas equivalent per day         
|MMBtu                                                                         |  | one million British thermal units, an energy measurement          
|MMcf                                                                          |  | one million cubic feet of natural gas                             
|MMcfe                                                                         |  | one million cubic feet of natural gas equivalent                  
|NGLs                                                                          |  | natural gas liquids, such as propane, butanes and natural gasoline
|One barrel of oil or NGLs is the energy equivalent of six Mcf of natural gas.





PART I

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

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General

We are a growing energy company that (i) explores for, develops and produces natural gas; (ii) gathers and processes natural gas and transports,
fractionates and stores NGLs through our consolidated subsidiary, MarkWest Energy Partners, L.P. (MarkWest Energy Partners or the Partnership); and (iii) markets natural gas and natural gas
liquids (NGLs) in support of our E & P and midstream businesses. These businesses are discussed in detail later in this section of this report.

We
were founded in 1988 as a partnership and later incorporated in Delaware. We completed our initial public offering in 1996. Our common stock is traded on the American Stock Exchange
under the symbol "MWP." Our executive offices are located at 155 Inverness Drive West, Suite 200, Englewood, Colorado 80112-5000.

Recent Developments

Since 1999, we have undertaken several important initiatives that have transformed MarkWest Hydrocarbon into a more focused midstream services and gas
exploitation and development company.
Our midstream services business is conducted through our 46.7%-owned subsidiary, MarkWest Energy Partners. The gas exploitation business is conducted by MarkWest Hydrocarbon. MarkWest Hydrocarbon also
markets its own NGLs and natural gas. In chronological order, these initiatives are:



Strategy

We believe the primary opportunities for our company are tied to our ability to successfully:



Business

Our business activities are segregated into three segments:



Exploration
and production and marketing are business activities conducted by MarkWest Hydrocarbon; MarkWest Energy Partners is responsible for gathering and processing. You should read
Note 14 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for financial information about our business segments.



Our exploration and production business includes development, exploration, production and acquisition of natural gas and, to a lesser extent, oil. 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.



Please review Note 18 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for
information regarding our proved and developed oil and gas reserves and the standardized measure of discounted future net cash flows and changes therein.

We
have not filed any oil or natural gas reserve estimates or included any such estimates in reports to a Federal or foreign government authority or agency, other than the Securities and
Exchange Commission (SEC) and the Department of Energy (DOE). There were no differences between the reserve estimates included in the SEC report, the DOE report and those included herein, except for production and additions and deletions due to the difference in the "as of" dates of such reserve estimates.



The following table sets forth information regarding net oil and natural gas production, average sales prices and other production information. Hedging gains and
losses are disclosed separately for the years ended December 31, 2002, 2001 and 2000.

|                                            |                                             | United States  |      | Canada(1)
|------------------------------------------- | ------------------------------------------- | -------------- | ---- | ---------
|
|
|Quantities produced and sold:               |                                             |                |      |          
|                                            | Natural gas (MMcf)                          |                |      | 3,228    
|                                            | Oil and liquids (MBbl)                      |                |      | 23       
|                                            |                                             | Total MMcfe(2) |      |          
|                                            |                                             | Average Mcfe/d |      |          
|Average sales price:                        |                                             |                |      |          
|                                            | Natural gas ($/Mcf) sales price received    |                | $    | 2.54     
|                                            | Natural gas ($/Mcf) effects of energy swaps |                | $    | 0.44     
|                                            | Oil and liquids ($/Bbl)                     |                | $    | 15.61    
|Average production (lifting) costs ($/Mcfe) |                                             | $              | 1.24 |          

---



The following table sets forth information regarding the number of productive wells in which we held a working interest at December 31, 2002:

|              |                | 2002 Productive Wells(1)
|------------- | -------------- | ------------------------
|
|
|United States |                |                         
|              | San Juan Basin |                         
|              | Michigan       |                         
|              |                |                         
|              |                | Total                   
|Canada        |                |                         
|              | Alberta        |                         
|              |                |                         
|Total wells   |                | 235                     
|              |                |                         

---





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     |       | Canada(1) |   
|----------------------- | --------------- | ----------------- | ----- | --------- | --
|
|Gross(2) (Net)(4) wells |                 |                   |       |           |   
|                        | Development     |                   |       |           |   
|                        |                 | Natural gas       |       | 14        |   
|                        |                 | Oil               |       |          |   
|                        |                 | Non-productive(3) |       |          |   
|                        |                 |                   |       |           |   
|                        |                 |                   | Total |           | 14
|                        |                 |                   |       |           |   
|                        | Exploratory     |                   |       |           |   
|                        |                 | Natural gas       |       | 2         |   
|                        |                 | Oil               |       |          |   
|                        |                 | Non-productive    |       |          |   
|                        |                 |                   |       |           |   
|                        |                 |                   | Total |           | 2 
|                        |                 |                   |       |           |   
|                        | Recompletion(5) |                   |       |           |   
|                        |                 | Natural gas       |       | 5         |   
|                        |                 | Oil               |       |          |   
|                        |                 | Non-productive    |       |          |   
|                        |                 |                   |       |           |   
|                        |                 |                   | Total |           | 5 
|                        |                 |                   |       |           |   
|Total gross wells       |                 | 21                |       | (10.8     | ) 
|                        |                 |                   |       |           |   

---



The following table sets forth the leasehold acreage held by MarkWest Hydrocarbon at December 31, 2002.

|              |                | Developed Acreage(1) |        | Undeveloped Acreage(2)
|------------- | -------------- | -------------------- | ------ | ----------------------
|
|United States |                |                      |        |                       
|              | San Juan Basin |                      | 14,577 |                       
|              | Michigan       |                      | 1,953  |                       
|              |                |                      |        |                       
|              |                | Total                |        | 16,530                
|              |                |                      |        |                       
|Canada        |                |                      |        |                       
|              | Alberta        |                      | 76,647 |                       
|              |                |                      |        |                       
|Total Acreage |                | 93,177               |        | 65,234                
|              |                |                      |        |                       

---

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 74,240 gross and 59,946 net acres through the year 2003.



MarkWest Energy Partners gathers and processes natural gas and transports, fractionates and stores NGLs for MarkWest Hydrocarbon and other energy companies. The
Partnership's midstream operations are currently concentrated in two core areasthe Appalachian basin and Michigan. MarkWest Energy Partners is the largest gas processor in the
northeastern United States, processing the gas or fractionating the NGLs delivered by substantially all of the producers who deliver gas into two of the three largest gathering systems in Appalachia.



The majority of the Partnership's assets 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 Hydrocarbon, 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. 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.

MarkWest
Energy Partners owns and operates the following facilities in Appalachia:

|                              |  |                    |  |      |  |               |  | Year Ended
December 31, 2002
|----------------------------- |  | ------------------ |  | ---- |  | ------------- |  | ----------------------------
|
|Boldman Extraction Plant      |  | Pike County, KY    |  | 1991 |  | 70,000 Mcf/d  |  | 42,000                      
|Cobb Extraction Plant         |  | Kanawha County, WV |  | 1968 |  | 35,000 Mcf/d  |  | 24,000                      
|Kenova Extraction Plant(2)    |  | Wayne County, WV   |  | 1996 |  | 160,000 Mcf/d |  | 136,000                     
|Maytown Extraction Plant      |  | Floyd County, KY   |  | 2000 |  | 55,000 Mcf/d  |  | 64,000                      
|Kermit Extraction Plant       |  | Mingo County, WV   |  | 2001 |  | (1)           |  | (1)                         
|Siloam Fractionation Plant(3) |  | South Shore, KY    |  | 1957 |  | 600,000 Gal/d |  | N/A                         

|                              |  |                                     |  |      |  |     |  |         |  | Year Ended
December 31,
2002
|----------------------------- |  | ----------------------------------- |  | ---- |  | --- |  | ------- |  | ----------------------------
|
|
|Kenova to Siloam pipeline     |  | Wayne County, WV to South Shore, KY |  | 1957 |  | 36  |  | 831,000 |  | 410,000                     
|Maytown to Kenova pipeline(4) |  | Lincoln County to Wayne County, WV  |  | 1976 |  | 100 |  | 160,000 |  | 145,000                     

---

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

The
Siloam fractionation plant receives substantially all of its extracted NGLs via pipeline or tanker truck from the Partnership's 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 MarkWest Energy Partners' Appalachian operations has
been approximately 64% propane, 18% normal butane, 6% isobutane, and 12% natural gasoline. The Partnership does not currently produce and sell any ethane.



MarkWest Energy Partners' operations in western Michigan consists of the following:

|                                    |  |                                         |  |      |     |        |  | Year Ended
December 31, 2002(2)
|----------------------------------- |  | --------------------------------------- |  | ---- | --- | ------ |  | -------------------------------
|
|
|90-mile sour gas gathering pipeline |  | Manistee, Mason and Oceana Counties, MI |  | 1996 | (1) | 25,000 |  | 13,800                         
|Fisk Gas Plant                      |  | Manistee County, MI                     |  | 1998 |     | 25,000 |  | 13,800                         

---

NANot
applicable

The
Partnership's 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). The Partnership's gathering pipeline serves approximately 30 wells and 13 producers in this three county area. The 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.

The
Partnership currently processes 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 MarkWest Energy Partners' pipeline and processing facility is dedicated to its gathering and processing facilities.
Under the fee component of these agreements, which represent approximately two-thirds of our gross margin (revenues less purchased product costs) in Michigan, producers pay the Partnership
a fee to transport and treat their gas. Under the percent-of-proceeds component, the Partnership retains a portion of the proceeds from the sale of the NGLs as compensation for
the processing services provided. The propane and butane-natural gasoline production is usually sold at the plant.



Our marketing group markets our NGL production in Appalachia. In 2002, we sold 183 million gallons of NGLs extracted at our Siloam facility. We ship NGL
products from Siloam by truck, rail and barge. We sell our own propane and purchase propane from third parties for resale to our wholesale 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 our keep-whole processing contracts.

We
strive to maximize the value of our NGL output by marketing directly to our customers. We minimize the use of third-party brokers and instead support a direct marketing staff focused
on multi- state 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. These efforts have allowed us to maintain premium pricing for the majority of our NGL products compared to Gulf Coast spot prices.

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 MarkWest Energy Partners' 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 the Partnership's 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 are Columbia Resources and Equitable Production Company (Equitable). Under the provisions of our contracts with the Appalachian producers,
the producers have committed all of the natural gas they deliver into Columbia Gas' transmission facilities upstream of MarkWest Energy Partners' Kenova, Boldman and Cobb facilities for processing.

As
compensation for providing processing services to our Appalachian producers (we have since outsourced these services to MarkWest Energy Partners as discussed below), we earn 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. Generally, the value of the NGLs extracted is greater than the cost of replacing those Btus with dry gas, resulting in positive operating
margins under these contracts. 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. The
spread between the NGL product sales price and the purchase price of natural gas with an equivalent Btu content is called the "frac spread".

At
the closing of its MarkWest Energy Partners' IPO on May 24, 2002, we outsourced our midstream services to the Partnership, which performs natural gas gathering and processing
and NGL 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 retained all the benefits
and associated risks of our keep-whole contracts with producers. Our NGL and gas marketing operations were not contributed to MarkWest Energy Partners.

Our
keep-whole contracts expose us to commodity price risk, both on the sales side (of NGLs) and on the purchase side (of natural gas), which may make our marketing results
and cash flows volatile. We attempt to mitigate our commodity price risk through our hedging program. You should read Item 7A, "Quantitative and Qualitative Disclosures About Market Risk" for further
details about our commodity price risk management program.

Our
natural gas marketing group, located primarily in Appalachia, provides services to natural gas producers, sources new gas for our facilities, and purchases our replacement BTU gas,
and assists with
our business development efforts. Our natural gas marketing operations are a fundamentally high-dollar, low-margin business intended to supplement MarkWest Energy Partners'
gathering and processing operations. Consequently, a significant percentage of our overall revenue stems from gas marketing, but the contribution to our gross margin is modest. For the years ended
December 31, 2002, 2001, and 2000, 37%, 36%, and 41%, respectively, of gathering, processing and marketing revenue stemmed from gas marketing. However, the gas marketing gross margin (revenue less purchased product
cost) as a percent of gathering, processing and marketing gross margin was just 12%, 4%, and 2%, respectively.

Factors Affecting our Operations

Seasonality

A substantial portion of our midstream revenues and, as a result, our midstream gross margin, 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 marketing segment during the first and fourth
quarters of the year.

Competition

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.

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



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, 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 are 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.

Alberta,
the province in which we operate, has legislation and regulations 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, 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.

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 stricter 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, 2002, we had 120 employees. At our fractionation facility in South Shore, Kentucky, the Paper, Allied Industrial, Chemical, and Energy
Workers International Union Local 5-0372 represent 15 employees. 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.

Available Information

You can find more information about us at our Internet website located atwww.markwest.com. Our Annual Report on
Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and any amendments to those reports are available free of charge
through our internet website as soon as is reasonably practicable after we electronically file such material with the SEC.

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," "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:



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

MarkWest Hydrocarbon, in the ordinary course of business, is a party to various legal actions. In the opinion of management, none of these actions, either
individually or in the aggregate, will have a material adverse effect on our financial condition, liquidity or results of operations.

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, 2002.





PART II

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

Our common stock trades on the American Stock Exchange national market under the symbol "MWP." As of December 31, 2002, there were 8,510,913 shares of
common stock outstanding held by approximately 550 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.

2002

2001HIGH

LOW

HIGH

LOWFirst Quarter

$
8.05

$
6.25

$
11.50

$
7.20Second Quarter

$
8.00

$
7.10

$
8.55

$
5.20Third Quarter

$
7.20

$
5.90

$
8.55

$
6.70Fourth Quarter

$
6.20

$
5.31

$
7.20

$
5.40


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 Hydrocarbon. Certain prior year amounts have been
reclassified to conform to the 2002 presentation. The selected consolidated statement of operations and balance sheet data for the years ended December 31, 2002, 2001, and 2000, and as of
December 31, 2002 and 2001, 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 ended December 31, 1999 and 1998, and as of December 31, 2000, 1999 and 1998, 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 accompanying Notes included elsewhere in this Form 10-K.

|                                        |                                            | Year Ended December 31, |        
|--------------------------------------- | ------------------------------------------ | ----------------------- | -------
|
|
|Statement of Operations Data:           |                                            |                         |        
|Revenues(1)                             |                                            | $                       | 187,261
|Net income (loss)                       |                                            | $                       | (2,796 
|Basic earnings (loss) per share         |                                            | $                       | (0.33  
|Earnings per share assuming dilution    |                                            | $                       | (0.33  
|Weighted average shares outstanding     |                                            |                         | 8,499  
|                                        | assuming dilution                          |                         |        
|Balance Sheet Data (as of December 31): |                                            |                         |        
|Total assets                            |                                            | $                       | 253,314
|Long-term debt                          |                                            | $                       | 64,223 
|Stockholders' equity                    |                                            | $                       | 53,352 
|Operating Data:                         |                                            |                         |        
|Exploration and production              |                                            |                         |        
|                                        | Natural gas produced (Mcfe/d)              |                         |        
|MarkWest Energy Partners(2)             |                                            |                         |        
|Appalachia:                             |                                            |                         |        
|                                        | Natural gas processed for a fee (Mcf/d)(3) |                         |        
|                                        | NGLs fractionated for a fee (gal/d)(4)     |                         |        
|Michigan:                               |                                            |                         |        
|                                        | Gas volume processed for a fee (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, 2002, 2001 and 2000. Certain prior year amounts have been reclassified to conform to the presentation used in 2002. In conjunction with the following discussion and analysis,
you should also read our Consolidated Financial Statements and related Notes thereto and the "Selected Financial Data" included elsewhere in this Form 10-K.

Initial Public Offering of MarkWest Energy Partners, L.P.

On May 24, 2002, MarkWest Hydrocarbon contributed most of the assets, liabilities and operations of our midstream business to MarkWest Energy Partners,
L.P. in exchange for 3,000,000 subordinated units, a 2% general partner interest in the Partnership, incentive distribution rights (as defined in the Partnership Agreement), and $63.5 million in cash (which was used to pay down bank
debt). The Partnership closed its initial public offering on that date selling 2,415,000 common units (including the underwriters' exercise of their over-allotment option) for gross
proceeds of $49 million and net proceeds (after fees and expenses) of $43 million. Concurrent with its initial public offering the Partnership borrowed $21.4 million (which is
included as long-term debt on the consolidated balance sheet of MarkWest Hydrocarbon). MarkWest Energy Partners' limited partnership structure reduces our cost of capital thereby enhancing
our ability to grow our midstream operations more efficiently.

As
of December 31, 2002, we own a 46.7% interest in MarkWest Energy Partners consisting of 2,479,762 subordinated units and a 2% general partner interest. Through our ownership of
the general partner of MarkWest Energy Partners, we control and operate MarkWest Energy Partners.

MarkWest
Hydrocarbon's consolidated financial statements, beginning May 24, 2002, reflect the consolidation of MarkWest Energy Partners, with the public unitholders' interest
being reflected as a minority interest in the Statement of Operations and Balance Sheet.

Recent Developments

On March 24, 2002, MarkWest Energy Partners, our consolidated subsidiary, entered into an agreement to merge with Pinnacle Natural Gas Company and certain
affiliates for approximately $38 million. The acquired assets, primarily located in Texas, are comprised of (a) three lateral natural gas pipelines transporting up to 1.1 Bcf/day of
natural gas under firm contracts to power plants and (b) eighteen gathering systems gathering more than 44,000 Mcf/d. The acquisition complements and expands MarkWest Energy Partners' core
fee-based business, while providing geographic and customer diversification. The acquisition will be financed primarily through borrowings under the Partnership's credit facility, which
was recently expanded by $15 million.

Results of Operations



Net loss.Our net loss was $2.8 million for the year ended December 31, 2002, compared to net income of
$2.8 million for the year ended December 31, 2001.

In
our exploration and production segment, revenue associated with our increased U.S. production was moderated by lower average sales prices; increased depreciation, depletion and
amortization offset income from our Canadian operations.

In
our gathering and processing segment, we had record production at our Siloam fractionator despite a third-party transmission and gathering company's employees' strike, since
concluded, and below-average cold weather in Appalachia starting late in 2002.

However,
volatile commodity prices in our marketing segment partially offset record production. NGL products traded at a historically low relationship to crude oil during the third
quarter of 2002, which adversely impacted us in two ways. First, on NGL product sales hedged by crude oil, losses on the crude oil sales contracts were not completely offset by increases in physical
NGL product sales prices. This caused us to experience $1.0 million less in after-tax revenue than had the historical relationship been realized.

Second,
we recorded a $1.5 million after-tax, non-cash reduction to revenue for estimated ineffectiveness of fourth quarter 2002 and 2003 crude oil hedges
of our NGL product sales. Based on historical regression analysis, our crude oil futures contracts are effective for hedge accounting treatment. To calculate the current period ineffectiveness, we
compared (and will compare) the futures market's value for existing crude oil futures contracts to the future value of the NGLs hedged (the resulting mark-to-market adjustment). This charge will reverse in future quarters and be offset by actual realized ineffectiveness, if any, which may be of a greater or lesser
amount.

Exploration and production revenue.Exploration and production revenue was $32.9 million for the year ended
December 31, 2002 compared to $15.2 million for the year ended December 31, 2001, an increase of $17.7 million, or 117%. Revenue was higher in 2002 than in 2001 primarily
due to production from the two Canadian natural gas production companies acquired in August 2001 and our increased production through drilling in both Canada and the U.S. The effect of the
increased production was somewhat moderated by lower average selling prices.

Gathering, processing and marketing revenue.Gathering, processing and marketing revenue was $154.3 million for the
year ended December 31, 2002 compared to $173.9 million for the year ended December 31, 2001, a decrease of $19.6 million, or 11%. Revenue was lower in 2002 than in 2001
primarily due to:



Purchased gas costs.Purchased gas costs were $127.5 million for the year ended December 31, 2002, compared to
$140.2 million for the year ended December 31, 2001, a decrease of $12.7 million, or 9%. Purchased gas costs were lower in 2001 primarily due to:



Plant operating expenses.Plant operating expenses were $16.3 million for the year ended December 31, 2002,
compared to $16.5 million for the year ended December 31, 2001, a decrease of $0.3 million, or 2%.

Lease operating expenses.Lease operating expenses were $7.9 million for the year ended December 31, 2002,
compared to $3.4 million for the year ended December 31, 2001, an increase of $4.5 million, or 135%. Lease operating expenses increased principally due to our acquisition of two
Canadian natural gas production companies in August 2001 and our increased production through drilling in both Canada and the U.S. in 2002.

Transportation costs.Transportation costs were $1.7 million for the year ended December 31, 2002, compared to
$1.2 million for the year ended December 31, 2001, an increase of $0.4 million, or 35%. Transportation costs increased principally due to our acquisition of two Canadian natural
gas production companies in August 2001 and our increased production through drilling in both Canada and the U.S.

Production taxes.Production taxes were $2.0 million for the year ended December 31, 2002, compared to
$0.7 million for the year ended December 31, 2001, an increase of $1.4 million, or 203%. Production taxes increased principally due to our acquisition of two Canadian natural gas
production companies in August 2001 and our increased production through drilling in both Canada and the U.S.

Selling,general and administrative expenses.Selling, general and administrative expenses
were $11.9 million for the year ended December 31, 2002, compared to $8.4 million for the year ended December 31, 2001, an increase of $3.5 million, or 42%. The
increase primarily stems from (a) supporting our Canadian operations, which were acquired in August 2001, and (b) the incremental, public company costs from our consolidated
subsidiary, MarkWest Energy Partners, which closed its IPO on May 24, 2002.

Depreciation and depletion.Depreciation and depletion were $21.4 million for the year ended December 31, 2002,
compared to $10.3 million, for the year ended December 31, 2001, an increase of $11.1 million, or 107%. The increase was principally caused by the depletion of reserves through
increased production from our 2001 Canadian acquisition and our capital programs in Canada and the U.S.

Interest expense.Interest expense was $3.8 million for both the years ended December 31, 2002 and 2001.

Write-down of deferred financing costs.We wrote off $3.0 million in deferred financing costs as a result
of the May 24, 2002 amendment of our credit facilitywhich was completed concurrently with the IPO of our consolidated subsidiary, MarkWest Energy Partnersand an
earlier amendment.

Gain on sale of non-operating assets.During November 2002, we sold 500,000 of our subordinated units of
MarkWest Energy Partners to a third party.



Exploration and production revenue.Exploration and production revenue was $15.2 million for the year ended
December 31, 2001 compared to $4.6 million for the year ended December 31, 2000, an increase of $10.6 million, or 233%. Revenue was higher in 2001 than in 2000 primarily
due to:



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:



Purchased gas costs.Purchased gas costs were $140.2 million for the year ended December 31, 2001, compared to
$172.6 million for the year ended December 31, 2000, a decrease of $32.4 million, or 19%. Purchased gas costs were lower in 2001 primarily due to:



Plant operating expenses.Plant operating expenses were $16.5 million for the year ended December 31, 2001,
compared to $15.9 million for the year ended December 31, 2000, an increase of $0.6 million, or 4%.

Lease operating expenses.Lease operating expenses were $3.4 million for the year ended December 31, 2001,
compared to $1.8 million for the year ended December 31, 2000, an increase of $1.6 million, or 91%. The increase is primarily attributable to our August 2001 Canadian
acquisition.

Transportation costs.Transportation costs were $1.2 million for the year ended December 31, 2001, compared to
$0.5 million for the year ended December 31, 2000, an increase of $0.8 million, or 178%. The increase is primarily attributable to our August 2001 Canadian acquisition.

Production taxes.Production taxes were $0.7 million for the year ended December 31, 2001, compared to
$0.5 million for the year ended December 31, 2000, an increase of $0.2 million, or 50%. The increase was principally attributable to our August 2001 Canadian acquisition.

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 that 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.

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.

Seasonality

A portion of our revenue and, as a result, our gross margin, is dependent upon the sales prices of NGL products, particularly propane, and the purchase price of
natural gas which fluctuate with winter weather conditions, and other supply and demand determinants. The strongest demand for propane, which increases sales volumes, and the highest propane sales
margins generally occur during the winter heating season. As a result, we historically recognize a substantial portion of our annual income during the first and fourth quarters of the year.

Liquidity and Capital Resources

MarkWest Hydrocarbon's primary sources of liquidity are cash flow generated from operations and borrowings under our credit facility. From time to time, our
sources of funds are supplemented with proceeds from sales of a non-core assets and operating leases used to finance support equipment. In 2002, we supplemented these sources through the
IPO of MarkWest Energy Partners (net proceeds of $43 million, which was primarily used to pay down our debt) and the sale of 500,000 subordinated units we owned in the Partnership (net proceeds
of $8 million).

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. Most of
our future capital expenditures are discretionary. In our exploration and production segment, future capital expenditures will be increased or decreased based on cash flow from operations and
availability under our credit facility. Cash generated from operations in MarkWest Hydrocarbon will depend on our operating performance, which will be affected by prevailing commodity prices and other
factors, some of which are beyond our control. Availability under our credit facility is based on our borrowing base, which is a function of our proved reserves (which are impacted by production, our
drilling results, and commodity prices), as well as our NGL marketing business's receivables and inventory levels.

In
an effort to increase our ability to make future discretionary capital expenditures, we may elect to supplement cash flow generated from operations by: raising additional equity,
entering into strategic partnerships, entering into the sale-leaseback of assets, the sale of non-core assets, or some combination thereof.

As
of December 31, 2002, exclusive of the Partnership's credit facility (discussed below), MarkWest Hydrocarbon had borrowed $42.8 million of the $51.2 million
available credit under its $60 million credit facility. Our available credit increases or decreases with monthly changes in our NGL accounts receivable and inventory levels and our semiannual
borrowing base re-determination based on our proved reserves.

For
the Partnership, future acquisitions or projects are expected to be financed through a combination of debt and issuance of additional units, as is common practice with master limited
partnerships. The March 2003 Pinnacle acquisition is expected to be financed thorough borrowings under the Partnership's credit facility, which was recently expanded by $15 million.

As
of December 31, 2002, the Partnership had borrowed $21.4 million of the $38.6 million available credit under its $60 million credit facility. The
Partnership's credit facility was expanded in March 2003 to $75 million.

MarkWest
Hydrocarbon forecasts a baseline capital budget of $17.0 million for 2003, almost all of which is for exploration and production projects. Our baseline capital budget is
principally discretionary and may change contingent upon a number of factors, including our results of operations and opportunities.

Cash Flow

Net cash provided by operating activities was $35.9 million, $13.0 million and $13.3 million for the years ended December 31, 2002,
2001 and 2000, respectively. Net cash provided by operations increased during 2002 because 2002 represented the first full year of our Canadian E&P operations. 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 used in investing activities was $22.5 million, $77.6 million and $12.3 million for the years ended December 31, 2002, 2001 and 2000, 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.

Net
cash used in financing activities was $9.3 million for the year ended December 31, 2002. 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 used in financing activities in 2002 was primarily
the result of using the proceeds from the Partnership's IPO to pay down debt. 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.

Total Contractual Cash Obligations

A summary of our total contractual cash obligations as of December 31, 2002, is as follows:

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

Credit Facilities

You should read Note 5 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for
information on our financing facilities.

Outlook

Cash flow generated from operations during the fourth quarter of 2002 was adversely affected by volatile commodity prices, including unusually high natural gas
prices, and the effect of below-average cold weather in the northeastern U.S. Both of these conditions prevailed into the first quarter of 2003. Unusually high natural gas costs increase the cost of
the replacement natural gas we must purchase to satisfy our keep-whole contractual arrangements in Appalachia. Although our Rocky Mountain and Canadian natural gas production mitigates our
natural gas price risk, the impact of our Rocky Mountain and Canadian production was partially offset by the unfavorable basis differential between the Rocky Mountains/Canada and Appalachia that
existed into the first quarter of 2003. Below-average cold weather caused (a) many landowners to tap into the gathering systems upstream of MarkWest Energy Partners' Appalachian facilities and
(b) increased the operational downtime of the Partnership's facilities, both of which reduced throughput and revenues from our Appalachian operations.

We
expect cash flow from operations to benefit in 2003 from our U.S. and Canadian drilling programs and the new gas stream that began flowing in January 2003 when a new gatherer
completed its connection into the existing transmission system upstream of the Partnership's Kenova processing plant. We also expect cash flow from operations to increase as a result of MarkWest
Energy Partners' March 2003 acquisition of the Pinnacle Companies.

Related Parties

You should read Notes 3 and 6 of the accompanying Notes to consolidated Financial Statements included in Item 8 of this Form 10-K for
information regarding related parties.

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. You should also read Note 2 of the accompanying Notes to Consolidated Financial
Statements included in Item 8 of this Form 10-K.



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 there from 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. 144,Accounting for the Impairment or Disposal of
Long-Lived Assets,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 our
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 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 Information" included earlier 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.



We account for price risk management activities based upon the fair value accounting methods prescribed by SFAS No. 133,Accounting
for Derivative Instruments. Risk management activities include utilizing various hedging contracts and other derivatives to reduce volatility in our cash flow. SFAS
No. 133 requires that we determine the fair value of the instruments we use in these business activities and reflect them in our balance sheet at their fair values. However, changes in the fair
value of our cash flow hedges are generally recognized in our income statement when the hedge is settled.

The
determination of fair value for our hedging derivatives requires substantial judgment. The fair values of our derivatives are based upon certain estimations and internal valuation
techniques. These estimations use various factors that include closing exchange prices on the NYMEX, over-the-counter quotations, correlation of the hedged items to the hedging
instruments and basis (location) differences. The factors underlying our estimates of fair value and our assessment of correlation of our hedging derivatives are impacted by market volatility and
changes.

Recent Accounting Pronouncements

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 did not have a material impact on our financial position or results
of operations.

In
June 2001, the FASB issued SFAS No. 143,Accounting for Asset Retirement Obligations, which addresses financial
accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations
associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS No. 143 requires that the fair
value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added
to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to
operating expense. If the obligation is
settled for other than the carrying amount of the liability, a gain or loss is recognized on settlement. The provisions of this statement are effective for fiscal years beginning after June 15,
2002. With respect to our exploration and production business, we generally are required to plug our gas and oil production wells when removed from service, and we anticipate recording a liability for such obligation in the first quarter of 2003. With respect to our midstream services, we have certain surface
facilities with ground leases requiring us to dismantle and remove these facilities upon the termination of the applicable lease. We anticipate recording a liability, if one can be reasonably
estimated, for such obligations in the first quarter of 2003.

In
January 2002, the FASB Emerging Issues Task Force released Issue No. 02-3,Issues Related to Accounting for Contracts Involved in
Energy Trading and Risk Management Activities. The Task Force reached a consensus to rescind EITF Issue No. 98-10,Accounting for
Contracts Involved in Energy Trading and Risk Management Activities, the impact of which is preclude mark-to-market accounting for all energy trading
contracts not within the scope of FASB Statement No. 133,Accounting for Derivative Instruments and Hedging Activities. The Task Force also
reached a consensus that gains and losses on derivative instruments within the scope of Statement 133 should be shown net in the income statement if the derivative instruments are held for trading
purposes. The consensus regarding the rescission of Issue 98-10 is applicable for fiscal periods beginning after December 15, 2002. We do not have any trading activities and did not
account for any contracts as trading contracts in accordance with EITF Issue No. 98-10. Therefore, the EITF consensus to rescind EITF Issue No. 98-10 will not
have an impact on our financial position or results of operations.

In
April 2002, the FASB issued SFAS No. 145,Rescission of SFAS Nos. 4, 44 and 64; Amendment of SFAS Statement No. 13; and Technical
Corrections, which is generally effective for transactions occurring after May 15, 2002. Through the rescission of SFAS Nos. 4 and 64, SFAS No. 145 eliminates the
requirement that gains and losses from extinguishments of debt be aggregated and, if material, be classified as an extraordinary item net of any income tax effect. SFAS No. 145 made several
other technical corrections to existing pronouncements that may change accounting practice. SFAS No. 145 did not impact on our results of operations or financial position.

In
June 2002, the FASB issued SFAS No. 146,Accounting for Costs Associated with Exit or Disposal Activities. SFAS
No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. This Statement addresses financial accounting and reporting for costs associated with
exit or disposal activities and nullifies EITF Issue No. 94-3,Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring).We do not believe that the adoption of SFAS No. 146 will have a material impact on our results of
operations or financial position.

In
November 2002, FASB Interpretation No. 45,Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others(FIN 45), was issued. The accounting recognition provisions of FIN 45 are effective January 1, 2003 on a prospective basis. They require that a
guarantor recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. Under prior accounting principles, a guarantee would
not have been recognized as a liability until a loss was probable and reasonably estimable. As FIN 45 only applies to prospective transactions, we are unable to determine the impact, if any, that
adoption of the accounting recognition provisions of FIN 45 would have on our future financial position or results of operations.

In
January of 2003, the FASB issued Interpretation No. 46,Consolidation of Variable Interest Entities, an interpretation of ARB
No. 51(FIN 46), which requires the consolidation of certain variable interest entities, as defined. FIN 46 is effective immediately for variable interest entities
created after January 31, 2003, and on July 1, 2003 for investments in variable interest entities acquired before February 1, 2003; however, disclosures are required currently if
a company expects to consolidate any variable interest entities. We do not have investments in any variable interest entities, and therefore, the adoption of FIN 46 is not expected to have an impact
on our results of operations, financial position or cash flows.





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 included 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 business produces products, natural gas and NGLs, and provides services, gathering and processing of natural gas and the transportation, fractionation and
storage of NGLs. Our products are commodities that are subject to price risk. Commodity prices are often subject to material changes in response to relatively minor changes in supply and demand,
general economic conditions and other market conditions over which we have no control, like the weather.

Our
primary risk management objective is to manage our price risk, thereby reducing volatility in our cash flows. Our risk management activities generally fall into one of these
categories: (i) hedges of those risks not mitigated by our "natural hedge" (discussed below); (ii) hedges to realize the economics of a transaction, like our 2001 Canadian E&P
acquisition; and (iii) our exploration and production basis hedges.

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 may 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 the 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 financial institutions. 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 (with non-bank counterparties) and NYMEX positions.

The
use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (i) sales volumes may be less than expected
requiring market purchases to meet commitments, (ii) our OTC counterparties could fail to purchase or deliver the contracted quantities of natural gas, NGL, or crude oil or otherwise fail to
perform, and (iii) when the trading relationship between crude oil and NGL products is outside historical levels. 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.



Within our exploration and production segment, our revenues are subject to natural gas price risk. Within our NGL marketing segment, our price risk varies by
contract as well as by spot market prices. Our Appalachian producers compensate us for providing midstream services under one of two contract types:





To the extent our natural gas production equals our keep-whole requirements for purchasing natural gas in Appalachia and there are no material
differences in net prices, we have a "natural hedge" and our commodity price risk is substantially mitigated. As of December 31, 2002, our equity natural gas production approximated
    % of our keep-whole natural gas purchase requirements, making us a net consumer of natural gas and subject to natural gas price risk.

However,
we are exposed to basis risk. Our basis risk for natural gas stems from the geographic price differentials between our E&P sales location (San Juan basin and Alberta, Canada)
and hedging contract delivery location (NYMEX) and our marketing purchase location (Appalachia) and NYMEX. We hedge our basis risk for natural gas.

As
of December 31, 2002, our natural gas basis hedges were as follows:

Table I
Hedged Natural Gas BasisYear Ending
December 31, 2003MMBtu


2,996,000$/MMBtu

$
(0.42
)


We
are generally unable to hedge our basis risk 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.



Generally, we are an overall net consumer of natural gas as our keep-whole contractual requirements for purchasing natural gas in Appalachia currently
exceed our natural gas production. Until such time this relationship reverses and we become a net producer of natural gas, we are limiting our E&P hedges to either (a) obtaining futures prices
that our models suggest are optimal or (b) realizing the economics of a transaction, like our 2001 Canadian E&P acquisition. Generally, we execute our strategy by either selling
fixed-for-float swaps or utilizing costless collars. As of December 31, 2002, we have hedged our combined Canadian and Rocky Mountain natural gas volumes and prices as
follows:

Table II
Hedged Natural Gas SalesYear Ending December 31,2003

2004

2005MMBtu


3,500,000


2,877,000


44,000$/MMBtu

$
3.43

$
3.26

$
3.34Henry Hub Equivalent $/MMBtu(1)

$
4.06

$
3.75

$
3.69


---

Also,
within our marketing segment, for certain Appalachian natural gas sales, as of December 31, 2002, we hedged 195,000 MMBtu at $4.09 per MMBtu for 2003.



We hedge our NGL product sales by selling forward propane or crude oil. As of December 31, 2002, we have hedged Appalachian and stet NGL product sales as
follows:

Table III
Hedged Sales Price for NGL ProductsYear Ending December 31,2003

2004MarkWest Hydrocarbon, Inc.NGL Volumes Hedges Using Crude OilNGL gallons


85,979,000


13,113,000NGL sales prices per gallon

$
0.44

$
0.51MarkWest Energy Partners, L.P.NGL Volumes Hedged Using Crude OilNGL gallons


3,731,000


NGL sales price per gallon

$
0.47


NGL Volumes Hedged Using PropaneNGL gallons


1,260,000


NGL sales price per gallon

$
0.41


Total NGL Volumes HedgedNGL gallons


4,991,000


NGL sales price per gallon

$
0.45





Under
Table III, all projected margins or prices on open positions assume that both (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.

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.

To
the extent our Appalachian natural gas purchase requirements exceed our E&P natural gas production, we are simultaneously subject to NGL price risk on the sales side and natural gas
price risk on the purchase side within our GPM business. Consequently, we may hedge our Appalachian processing margin (defined as revenues less purchased product costs) by simultaneously selling
propane or crude oil while purchasing natural gas. However, as of December 31, 2002, we had no such hedges in place.



Our hedging program reduces our annual sensitivity to changes in NGL product sales prices. In our marketing segment, net income would have been higher by
$6.0 million, lower by $4.0 million and higher by $1.7 million for the years ended December 31, 2002, 2001 and 2000, 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 $1.9 million, lower by $0.4 million and higher by $0.6 million for the years ended December 31, 2002, 2001 and 2000,
respectively.

Our
annual sensitivities to changes in commodity prices considering our hedge position are as follows. For every $0.10 per MMBtu increase in the natural gas price, our gross margin
(defined as revenue less purchased product costs) 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 $1.3 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 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 experienced a loss in 2001 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 subsidiaries (Enron) filed for bankruptcy protection. In response to this filing, we have terminated all derivative contracts where Enron was the counterparty. As a
result, in 2001 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 was 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 reclassified $0.8 million and will be reclassifying $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, 2002, 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 $0.5 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, 2002.





ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements



|                                                                                                                            
|----------------------------------------------------------------------------------------------------------------------------
|Report of Independent Accountants                                                                                           
|Consolidated Balance Sheets at December 31, 2002 and 2001                                                                   
|Consolidated Statements of Operations for each of the three years in the period ended December 31, 2002                     
|Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2002                     
|Consolidated Statements of Changes in Stockholders' Equity for each of the three years in the period ended December 31, 2002
|Notes to Consolidated Financial Statements                                                                                  





REPORT OF INDEPENDENT ACCOUNTANTS

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

In
our opinion, the accompanying consolidated balance sheets 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, 2002 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended December 31, 2002 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 2 to the financial statements, MarkWest Hydrocarbon, Inc. changed its method of accounting for inventory effective January 1, 2002. As discussed
in Note 10, MarkWest Hydrocarbon, Inc. changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001.

/s/    PricewaterhouseCoopers
LLP

Denver,
Colorado
February 12, 2003, except for Note 17,
as to which date is March 25, 2003





MARKWEST HYDROCARBON, INC.        CONSOLIDATED BALANCE SHEETS

|                                                                                    |                                                                                                                  | December 31,                             |                                           
|----------------------------------------------------------------------------------- | ---------------------------------------------------------------------------------------------------------------- | ---------------------------------------- | ------------------------------------------
|
|
|ASSETS                                                                              |                                                                                                                  |                                          |                                           
|Current assets:                                                                     |                                                                                                                  |                                          |                                           
|                                                                                    | Cash and cash equivalents                                                                                        |                                          | $                                         
|                                                                                    | Receivables, including related party receivables of $748 and $600, 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                                                                                         |                                          |                                           
|                                                                                    |                                                                                                                  |                                          |                                           
|                                                                                    |                                                                                                                  |                                          | 270,235                                   
|Less: accumulated depreciation and depletion                                        |                                                                                                                  |                                          | (58,717                                   
|                                                                                    |                                                                                                                  |                                          |                                           
|                                                                                    |                                                                                                                  | Total property, plant and equipment, net |                                           
|Risk management asset, net of allowance of $0 and $912, respectively                |                                                                                                                  |                                          | 749                                       
|Intangible assets, net of accumulated amortization of $2,018 and $705, respectively |                                                                                                                  |                                          | 2,138                                     
|Notes receivables from officers and other assets                                    |                                                                                                                  |                                          | 271                                       
|                                                                                    |                                                                                                                  |                                          |                                           
|                                                                                    |                                                                                                                  | Total assets                             |                                           
|                                                                                    |                                                                                                                  |                                          |                                           
|LIABILITIES AND STOCKHOLDERS' EQUITY                                                |                                                                                                                  |                                          |                                           
|Current liabilities:                                                                |                                                                                                                  |                                          |                                           
|                                                                                    | Accounts payable, including related party payables of $1,264 and $500, Respectively                              |                                          | $                                         
|                                                                                    | Accrued liabilities                                                                                              |                                          |                                           
|                                                                                    | Current portion of long term debt                                                                                |                                          |                                           
|                                                                                    | Risk management liability                                                                                        |                                          |                                           
|                                                                                    |                                                                                                                  |                                          |                                           
|                                                                                    |                                                                                                                  | Total current liabilities                |                                           
|Deferred income taxes                                                               |                                                                                                                  |                                          | 35,685                                    
|Long-term debt                                                                      |                                                                                                                  |                                          | 64,223                                    
|Risk management liability                                                           |                                                                                                                  |                                          | 2,115                                     
|Other long-term liabilities                                                         |                                                                                                                  |                                          | 4,011                                     
|Minority interest in consolidated subsidiary                                        |                                                                                                                  |                                          | 46,001                                    
|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, 8,561,374 and 8,563,919 shares issued, respectively |                                          |                                           
|                                                                                    | Additional paid-in capital                                                                                       |                                          |                                           
|                                                                                    | Retained earnings                                                                                                |                                          |                                           
|                                                                                    | Accumulated other comprehensive income (loss), net of tax                                                        |                                          |                                           
|                                                                                    | Treasury stock; 50,461 and 59,622, shares, respectively                                                          |                                          |                                           
|                                                                                    |                                                                                                                  |                                          |                                           
|                                                                                    |                                                                                                                  | Total stockholders' equity               |                                           
|                                                                                    |                                                                                                                  |                                          |                                           
|                                                                                    |                                                                                                                  |                                          | Total liabilities and stockholders' equity
|                                                                                    |                                                                                                                  |                                          |                                           

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



MARKWEST HYDROCARBON, INC.        CONSOLIDATED STATEMENTS OF OPERATIONS

|                                                               |                                                            | Year Ended December 31,              |      
|-------------------------------------------------------------- | ---------------------------------------------------------- | ------------------------------------ | -----
|
|
|Revenues:                                                      |                                                            |                                      |      
|                                                               | Gathering, processing and marketing revenue                |                                      | $    
|                                                               | Exploration and production revenue                         |                                      |      
|                                                               |                                                            |                                      |      
|                                                               |                                                            | Total revenues                       |      
|                                                               |                                                            |                                      |      
|Operating expenses:                                            |                                                            |                                      |      
|                                                               | Purchased gas costs                                        |                                      |      
|                                                               | Plant operating expenses                                   |                                      |      
|                                                               | Lease operating                                            |                                      |      
|                                                               | Transportation costs                                       |                                      |      
|                                                               | Production taxes                                           |                                      |      
|                                                               | Selling, general and administrative expenses               |                                      |      
|                                                               | Depreciation and depletion                                 |                                      |      
|                                                               |                                                            |                                      |      
|                                                               |                                                            | Total operating expenses             |      
|                                                               |                                                            |                                      |      
|                                                               |                                                            | Income (loss) from operations        |      
|                                                               |                                                            |                                      |      
|Other income and expense:                                      |                                                            |                                      |      
|                                                               | Interest income                                            |                                      |      
|                                                               | Interest expense                                           |                                      |      
|                                                               | Write-down of deferred financing costs                     |                                      |      
|                                                               | Gain on sale of non-operating assets                       |                                      |      
|                                                               | Gain on sale of non-operating asset to a related party     |                                      |      
|                                                               | Minority interest in net income of consolidated subsidiary |                                      |      
|                                                               | Other expense, net                                         |                                      |      
|                                                               |                                                            |                                      |      
|                                                               |                                                            | Income (loss) before income taxes    |      
|                                                               |                                                            |                                      |      
|Provision (benefit) for income taxes:                          |                                                            |                                      |      
|                                                               | Current                                                    |                                      |      
|                                                               | Deferred                                                   |                                      |      
|                                                               |                                                            |                                      |      
|                                                               |                                                            | Provision (benefit) for income taxes |      
|                                                               |                                                            |                                      |      
|                                                               |                                                            | Net income (loss)                    |      
|                                                               |                                                            |                                      |      
|Basic earnings (loss) per share of common stock                |                                                            | $                                    | (0.33
|                                                               |                                                            |                                      |      
|Earnings (loss) 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.





MARKWEST HYDROCARBON, INC.        CONSOLIDATED STATEMENTS OF CASH FLOWS

|                                                                                  |                                                                                                    | Year Ended December 31,                                                 |                                                    
|--------------------------------------------------------------------------------- | -------------------------------------------------------------------------------------------------- | ----------------------------------------------------------------------- | ---------------------------------------------------
|
|
|Cash flows from operating activities:                                             |                                                                                                    |                                                                         |                                                    
|Net income (loss)                                                                 |                                                                                                    | $                                                                       | (2,796                                             
|Adjustments to reconcile net income to net cash provided by operating activities: |                                                                                                    |                                                                         |                                                    
|                                                                                  |                                                                                                    | Depreciation and depletion                                              |                                                    
|                                                                                  |                                                                                                    | Amortization of deferred financing costs included in interest expense   |                                                    
|                                                                                  |                                                                                                    | Write-off of deferred financing costs                                   |                                                    
|                                                                                  |                                                                                                    | Minority interest in net income of subsidiary                           |                                                    
|                                                                                  |                                                                                                    | Derivative ineffectiveness                                              |                                                    
|                                                                                  |                                                                                                    | Deferred income taxes                                                   |                                                    
|                                                                                  |                                                                                                    | Gain on sale of non-operating assets                                    |                                                    
|                                                                                  |                                                                                                    | Gain on sale of non-operating asset to related party                    |                                                    
|                                                                                  |                                                                                                    | Write-off Enron financial position, net of tax                          |                                                    
|                                                                                  |                                                                                                    | Reclassification of Enron hedges to purchased gas costs                 |                                                    
|                                                                                  |                                                                                                    | 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         |                                                    
|                                                                                  |                                                                                                    | Increase in other long-term 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 property, plant and equipment                                                |                                                                         |                                                    
|                                                                                  | Proceeds from sale of Partnership subordinated units and general partner interest to related party |                                                                         |                                                    
|                                                                                  | Proceeds from sale of Partnership subordinated units                                               |                                                                         |                                                    
|                                                                                  | Acquisition of Partnership subordinated units and general partner interest                         |                                                                         |                                                    
|                                                                                  |                                                                                                    |                                                                         |                                                    
|                                                                                  |                                                                                                    |                                                                         | Net cash used in investing activities              
|Cash flows from financing activities:                                             |                                                                                                    |                                                                         |                                                    
|                                                                                  | Proceeds from long-term debt                                                                       |                                                                         |                                                    
|                                                                                  | Repayments of long-term debt                                                                       |                                                                         |                                                    
|                                                                                  | Proceeds from initial public offering, net                                                         |                                                                         |                                                    
|                                                                                  | Debt issuance costs                                                                                |                                                                         |                                                    
|                                                                                  | Distributions to MarkWest Energy Partners unitholders                                              |                                                                         |                                                    
|                                                                                  | Exercise of stock options                                                                          |                                                                         |                                                    
|                                                                                  | Net reissuance (buyback) of treasury shares                                                        |                                                                         |                                                    
|                                                                                  | Payment on share purchase notes                                                                    |                                                                         |                                                    
|                                                                                  |                                                                                                    |                                                                         |                                                    
|                                                                                  |                                                                                                    |                                                                         | Net cash provided by (used in) financing activities
|Effect of exchange rate on changes in cash                                        |                                                                                                    |                                                                         | 8                                                  
|                                                                                  |                                                                                                    |                                                                         |                                                    
|Net increase (decrease) in cash and cash equivalents                              |                                                                                                    |                                                                         | 4,070                                              
|Cash and cash equivalents at beginning of year                                    |                                                                                                    |                                                                         | 2,340                                              
|                                                                                  |                                                                                                    |                                                                         |                                                    
|Cash and cash equivalents at end of year                                          |                                                                                                    | $                                                                       | 6,410                                              
|                                                                                  |                                                                                                    |                                                                         |                                                    

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



MARKWEST HYDROCARBON, INC.        CONSOLIDATED STATEMENTS 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 (Loss) |   | Total
Stockholders'
Equity |  
|--------------------------------------------- | ---------------------------------------------------- | --------------------------------------------------------------- | ----------------------------------- | ------------------------ | - | ------------ | -- | -------------------------- | - | ----------------- | - | -------------- | ------ | --------------------------------------------- | - | -------------------------- | -
|
|Balance, December 31, 1999                    |                                                      | 8,531                                                           |                                     | (69                      | ) | $            | 85 |                            | $ | 42,222            |   | $              | 10,801 |                                               | $ | (389                       | )
|Net income                                    |                                                      |                                                                |                                     |                         |   |              |   |                            |   |                  |   |                | 8,878  |                                               |   |                           |  
|Issuance of common stock                      |                                                      | 30                                                              |                                     | (30                      | ) |              | 1  |                            |   | 197               |   |                |       |                                               |   | (198                       | )
|Exercise of options                           |                                                      |                                                                |                                     | 5                        |   |              |   |                            |   | 10                |   |                |       |                                               |   | 28                         |  
|Net treasury stock (acquisitions) reissuances |                                                      |                                                                |                                     | (10                      | ) |              |   |                            |   | 42                |   |                |       |                                               |   | (83                        | )
|                                              |                                                      |                                                                 |                                     |                          |   |              |    |                            |   |                   |   |                |        |                                               |   |                            |  
|Balance, December 31, 2000                    |                                                      | 8,561                                                           |                                     | (104                     | ) |              | 86 |                            |   | 42,471            |   |                | 19,679 |                                               |   | (642                       | )
|Comprehensive income:                         |                                                      |                                                                 |                                     |                          |   |              |    |                            |   |                   |   |                |        |                                               |   |                            |  
|                                              | Net income                                           |                                                                 |                                    |                          |  |              |    |                           |   |                   |  |                |        | 2,810                                         |   |                            | 
|                                              | Foreign currency translation                         |                                                                 |                                    |                          |  |              |    |                           |   |                   |  |                |        |                                              |   |                            | 
|                                              | 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                       | )
|Comprehensive income:                         |                                                      |                                                                 |                                     |                          |   |              |    |                            |   |                   |   |                |        |                                               |   |                            |  
|                                              | Net loss                                             |                                                                 |                                    |                          |  |              |    |                           |   |                   |  |                |        | (2,796                                        | ) |                            | 
|                                              | Foreign currency translation, net of tax adjustments |                                                                 |                                    |                          |  |              |    |                           |   |                   |  |                |        |                                              |   |                            | 
|                                              | Other comprehensive income:                          |                                                                 |                                     |                          |   |              |    |                            |   |                   |   |                |        |                                               |   |                            |  
|                                              |                                                      | Risk management activities, net of tax                          |                                     |                         |   |             |    |                            |  |                   |   |               |        |                                               |  |                            |  
|                                              |                                                      |                                                                 |                                     |                          |   |              |    |                            |   |                   |   |                |        |                                               |   |                            |  
|Comprehensive income                          |                                                      |                                                                |                                     |                         |   |              |   |                            |   |                  |   |                |       |                                               |   |                           |  
|                                              |                                                      |                                                                 |                                     |                          |   |              |    |                            |   |                   |   |                |        |                                               |   |                            |  
|Payment on share purchase notes               |                                                      |                                                                |                                     |                         |   |              |   |                            |   | 13                |   |                |       |                                               |   |                           |  
|Forfeiture of share purchase notes            |                                                      |                                                                |                                     | 20                       |   |              |   |                            |   | 176               |   |                |       |                                               |   | (141                       | )
|Exercise of options                           |                                                      |                                                                |                                     |                         |   |              |   |                            |   | 2                 |   |                |       |                                               |   |                           |  
|Net treasury stock (acquisitions) reissuances |                                                      |                                                                |                                     | (10                      | ) |              |   |                            |   | 20                |   |                |       |                                               |   | 180                        |  
|                                              |                                                      |                                                                 |                                     |                          |   |              |    |                            |   |                   |   |                |        |                                               |   |                            |  
|Balance, December 31, 2002                    |                                                      | 8,564                                                           |                                     | (50                      | ) | $            | 87 |                            | $ | 42,758            |   | $              | 19,693 |                                               | $ | (328                       | )
|                                              |                                                      |                                                                 |                                     |                          |   |              |    |                            |   |                   |   |                |        |                                               |   |                            |  

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





MARKWEST HYDROCARBON, INC.        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Nature of Operations

MarkWest Hydrocarbon, Inc. (MarkWest Hydrocarbon or the Company) explores for and produces natural gas, markets natural gas liquids (NGLs) and natural gas
and provides midstream services. The Company's exploration and production business segment produces natural gas in Alberta, Canada; in the San Juan basin of Colorado and New Mexico; and in Michigan.
We primarily market our own equity NGLs and natural gas. MarkWest Energy Partners, L.P. (MarkWest Energy Partners or the Partnership), our 47 percent owned and fully consolidated affiliate,
gathers natural gas from the wellhead and processes the natural gas to remove impurities and the valuable natural gas liquids. The Partnership provides services in Appalachia and Michigan.

2. Summary of Significant Accounting Policies



Our consolidated financial statements include the accounts of all majority-owned or controlled subsidiaries after the elimination of all significant intercompany
accounts and transactions. Our financial statements for prior periods include reclassifications that were made to conform to the current year presentation. Those reclassifications had no impact on
reported net income or stockholders' equity.



We consolidate entities when we have the ability to control the operating and financial decisions and policies of that entity. The determination of our ability to
control or exert significant influence over an entity involves the use of judgment of the extent of our control or influence and that of the other equity owners or participants of the entity.



The preparation of financial statements in conformity with U.S. 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.



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 (FIFO), or market. Prior to 2002, the lower of cost, being FIFO, or market determined the cost of NGL product inventory. The change in accounting method from FIFO to
weighted average cost was made to better match purchased gas costs with revenues on a quarterly basis and to account for NGL product inventories on a consistent basis with other industry peer
companies. The cumulative effect of the change in accounting was not material as of January 1, 2002. If we would have changed our method of accounting from FIFO to weighted average cost on January 1, 2000, income before income taxes, net income and basic earnings
per share would have been as follows for the two-year period ended December 31, 2001, on a pro forma basis:

Year Ended December 31,2001

2000(in thousands)Pro forma income before income taxes

$
4,644

$
13,547Pro forma net income

$
2,972

$
8,737Pro forma basic earning per share

$
0.35

$
1.03


Prepaid Replacement Natural Gas

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 are recorded at cost. Expenditures that extend the useful lives of assets are capitalized. Repairs, maintenance and renewals that do
not extend the useful lives of the assets are expensed as incurred. Interest costs for the construction or development of long-term assets are capitalized and amortized over the related
asset's estimated useful life. Depreciation is provided principally on the straight-line method over the following estimated useful lives: gas gathering, processing and marketing,
20 years or the number of years reserves behind our facilities are contractually obligated, whichever is longer; 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, and capitalized interest. 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, 2002, approximately $37.3 million of investments in unevaluated properties in Canada were excluded from
amortization. As of December 31, 2002, 2001, and 2000, approximately $1.7, $0.5 million, and $0.6 million, respectively, of investments in unproved properties in the United States
were excluded from amortization.

Depletion
per unit of production (Mcfe) for each of our cost centers was as follows:

United States

Canada2002

$
0.68

$
1.832001

$
0.61

$
1.662000

$
0.48

$



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 test includes hedging contracts in place at the end of each year. No impairment existed during each of
the three years in the period ended December 31, 2002.

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.



In accordance with Statement of Financial Accounting Standards (SFAS) No. 121,Accounting for the
ImpairmentofLong-Lived Assets and for Long-Lived Assets to be Disposed Of, and SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived
Assets, evaluate the long-lived assets (excluding the full cost pool) 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
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 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, 2002.



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 amortized on a straight-line basis and charged to interest expense over the anticipated term of the associated agreement.



In June 1998, SFAS No. 133,Accounting for Derivative Instruments, was issued effective for fiscal
years beginning after June 15, 2000. Under SFAS No. 133, which was subsequently amended by SFAS No. 138, we are required to recognize the change in the market value of all
derivatives as either assets or liabilities in our Balance Sheet and measure those instruments at fair value. Changes in the fair value of derivatives are recorded each period in current earnings or
other comprehensive income depending upon the nature of the underlying transaction.

Prior
to January 1, 2001 and the implementation of SFAS No. 133, gains and losses on hedges of production were included in the carrying amount of the inventory and were
ultimately recognized in purchased gas costs or sales when the related inventory was sold. Gains and losses related to qualifying hedges, as defined by SFAS No. 80, Accounting for Futures Contracts,
 of firm commitments or anticipated transactions (including hedges of equity production) were recognized in purchased
gas costs or sales, as reported on the Consolidated Statement of Operations, when the hedged physical transaction occurred. For purposes of the Consolidated Statement of Cash Flows, all hedging gains
and losses were classified in net cash provided by operating activities.

We
currently hedge the sale of future NGL production with crude oil futures contracts. Based on historical regression analysis, these contracts are effective for hedge accounting
treatment. To determine the current period ineffectiveness computation, we compare the futures market's value for existing crude oil futures contracts (the resulting mark to market adjustment) to the
future value of the NGLs hedged. This computation resulted in a reduction in revenues of $2.4 million for the year ended December 31, 2002.



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, 2002 and 2001, 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 and unit-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25,Accounting
for Stock Issued to Employees.We have a fixed compensation plan and, through our consolidated subsidiary, MarkWest Energy Partners, we have a variable plan. We account for
these plans using fixed and variable accounting as appropriate.

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
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 (loss)                                                                                                             |                      | $                       | (2,796
|Deduct: total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effect |                      |                         | (369  
|                                                                                                                                           |                      |                         |       
|Pro forma net income (loss)                                                                                                                |                      | $                       | (3,165
|Earnings (loss) per share:                                                                                                                 |                      |                         |       
|                                                                                                                                           | Basic, as reported   |                         | $     
|                                                                                                                                           | Basic, pro forma     |                         | $     
|                                                                                                                                           | Diluted, as reported |                         | $     
|                                                                                                                                           | Diluted, pro forma   |                         | $     

Compensation
expense for the variable plan, including restricted unit grants, is measured using the market price of MarkWest Energy Partners' common units on the date the number of units
in the grant becomes determinable and is amortized into earnings over the period of service. Our stock options are issued under a fixed plan. Accordingly, compensation expense is not recognized for stock options unless the options were granted at an exercise price lower than market on the grant date.



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.



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 14).



Year Ended December 31,2002

2001

2000(in thousands)Interest paid

$
3,834

$
3,968

$
2,529Capitalized interest

$
1,899

$
950

$
137Income taxes paid (net of refunds)

$
(927
)
$
3,834

$
1,992




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 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143,Accounting for Asset Retirement
Obligations, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement
costs.
The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS
No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made.
The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the
end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, a gain or loss is recognized on settlement. The provisions of
this statement are effective for fiscal years beginning after June 15, 2002. With respect to our exploration and production business, we generally are required to plug our gas and oil production wells when removed from service, and we anticipate
recording a liability for such obligation in the first quarter of 2003. With respect to our midstream services, we have certain surface facilities with ground leases requiring us to dismantle and
remove these facilities upon the termination of the applicable lease. We anticipate recording a liability, if one can be reasonably estimated, for such obligations in the first quarter of 2003.

In
January 2002, the FASB Emerging Issues Task Force released Issue No. 02-3,Issues Related to Accounting for Contracts Involved in Energy Trading
and Risk Management Activities. The Task Force reached a consensus to rescind EITF Issue No. 98-10,Accounting for Contracts Involved in Energy
Trading and Risk Management Activities, the impact of which is preclude mark-to-market accounting for all energy trading contracts not within the scope of FASB Statement
No. 133,Accounting for Derivative Instruments and Hedging Activities. The Task Force also reached a consensus that gains and losses on
derivative instruments within the scope of Statement 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. The consensus regarding the rescission
of Issue 98-10 is applicable for fiscal periods beginning after December 15, 2002. We do not have any trading activities and did not account for any contracts as trading contracts in accordance
with EITF Issue No. 98-10. Therefore, the EITF consensus to rescind EITF Issue No. 98-10 will not have an impact on our financial position or results of operations.

In
April 2002, the FASB issued SFAS No. 145,Rescission of SFAS Nos. 4, 44 and 64; Amendment of SFAS Statement No. 13; and Technical
Corrections, which is generally effective for transactions occurring after May 15, 2002. Through the rescission of SFAS Nos. 4 and 64, SFAS No. 145 eliminates the
requirement that gains and losses from extinguishments of debt be aggregated and, if material, be classified as an extraordinary item net of any income tax effect. SFAS No. 145 made several
other technical corrections to existing pronouncements that may change accounting practice. SFAS No. 145 did not impact on our results of operations or financial position.

In
June 2002, the FASB issued SFAS No. 146,Accounting for Costs Associated with Exit or Disposal Activities. SFAS
No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. This Statement addresses financial accounting and reporting for costs associated with
exit or disposal activities and nullifies EITF Issue No. 94-3,Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring).We do not believe that the adoption of SFAS No. 146 will have a material impact on our results of operations or
financial position.

In
November 2002, FASB Interpretation No. 45,Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others(FIN 45), was issued. The accounting recognition provisions of FIN 45 are effective January 1, 2003 on a prospective basis. They require that a
guarantor recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. Under prior accounting principles, a guarantee would not
have been recognized as a liability until a loss was probable and reasonably estimable. As FIN 45 only applies to prospective transactions, we are unable to determine the impact, if any, that adoption
of the accounting recognition provisions of FIN 45 would have on our future financial position or results of operations.

In
January of 2003, the FASB issued Interpretation No. 46,Consolidation of Variable Interest Entities, an interpretation of ARB
No. 51(FIN 46), which requires the consolidation of certain variable interest entities, as defined. FIN 46 is effective immediately for variable interest entities created after January 31, 2003, and on July 1, 2003 for investments in variable interest
entities acquired before February 1, 2003; however, disclosures are required currently if a company expects to consolidate any variable interest entities. We do not have investments in any
variable interest entities, and therefore, the adoption of FIN 46 is not expected to have an impact on our results of operations, financial position or cash flows.

3. Initial Public Offering of MarkWest Energy Partners, L.P. and Concurrent Transactions, and Subsequent Transactions Involving Ownership of the Partnership

On May 24, 2002, MarkWest Hydrocarbon conveyed most of the assets, liabilities and operations of our midstream business to MarkWest Energy Partners in
exchange for:



The
Partnership concurrently issued 2,415,000 common units (including 315,000 units issued pursuant to the underwriters' over-allotment option), representing a 43.7% limited
partnership interest in the Partnership, in an initial public offering (IPO) at a price of $20.50 per unit. The Operating Company concurrently entered into a $60 million term loan credit
facility with various lenders and borrowed $21.4 million upon the closing of the IPO.

Upon
the closing of the IPO, MarkWest Hydrocarbon received cash totaling $63.5 million, which was funded by proceeds from the IPO and by Partnership borrowings under its credit
facility. We used the cash to repay bank indebtedness.

The
common units have preference over the subordinated units with respect to cash distributions and, accordingly, we accounted for the sale of the common units as a sale of a minority
interest. Our subordinated units automatically convert to common units on June 30, 2009, but a portion of the subordinated units may convert on or after June 30, 2005 if the Partnership
meets certain financial tests, namely operating surpluses that exceed the minimum quarterly distributions, as defined in the partnership agreement.

Immediately
after the IPO, MarkWest Hydrocarbon sold an 8.6% interest in MarkWest Energy GP, L.L.C., the general partner of the Partnership, and 24,864 of its Partnership subordinated
units, representing a 0.4% limited partner interest in the Partnership, to certain officers and key employees of MarkWest Hydrocarbon for $183,000 and $408,000, respectively. The officers and
employees paid approximately 30% of the purchase price in cash and financed the remainder via loans from MarkWest Hydrocarbon. The loans are formalized by non-recourse promissory notes
requiring the principal balance to be repaid no later than June 30, 2009 and bearing interest at the rate of 7% per annum on the unpaid balance. As of December 31, 2002, for both transactions combined we
recognized a $141,000 gain on the purchase price in excess of our book value to the extent that the purchase price was paid in cash, approximately $263,000. The remaining balance of $251,000 was
recorded as deferred income and is included in accrued liabilities on our balance sheet.

One
of our officers resigned effective the end of November 2002. MarkWest Hydrocarbon purchased from this officer the 4,626 Partnership subordinated units and 1.6% general partner
interest we had sold to him in May 2002. In return for the subordinated units and general partner interest, MarkWest Hydrocarbon exchanged the officer's remaining $77,000 note receivable and
$3,000 in related accrued
interest and paid $40,000 in cash for total consideration of $120,000. The purchase price for the Partnership subordinated units was based on market value (see below), and the purchase price for the
general partner interest was based on a formula included in the parties' original purchase and sale agreement.

During
November 2002, MarkWest Hydrocarbon sold 500,000 of its Partnership subordinated units to a private venture fund for $8.6 million. The sale price was $17.146 per
subordinated unit, representing a 22 percent discount off the common unit price of MarkWest Energy over the 20 trading days prior to closing. The discounted subordinated unit sales price
relative to the market value of the common units was attributable to the preference of the common units with respect to distributions as well as no public trading market for the subordinated units.
Net proceeds after transaction costs were $8.1 million. MarkWest Hydrocarbon recognized a gain on the sale of $5.5 million. MarkWest Hydrocarbon granted preferential rights to conversion
to the buyer: one-third of the 500,000 subordinated units sold will be converted into common units at each of the first three possible conversion dates provided for in MarkWest Energy's
partnership agreement. MarkWest Hydrocarbon's President and Chief Executive Officer purchased 13,997 of the subordinated units as a limited partner of the private venture fund.

At
December 31, 2002, MarkWest Hydrocarbon owned 93% of the general partner, and MarkWest Hydrocarbon thereby controls the Partnership. The subordinated units owned by MarkWest
Hydrocarbon comprise 45% of the Partnership's limited partner interests. Together, these interests represent an approximate 47% ownership interest. The Partnership's results are consolidated in our
financial statements. The minority interest in consolidated subsidiary on the consolidated balance sheet represents the minority (non-MarkWest Hydrocarbon) shareholders' investment in the
Partnership plus the minority shareholders' share of the net income of the Partnership since its initial public offering on May 24, 2002. Minority interest in net income of consolidated
subsidiary in the consolidated statement of operations represents the minority shareholders' share of the net income of the Partnership.

4. 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

$
49,005Direct acquisition costs


1,30150,306Current liabilities assumed


7,413Deferred income taxes


30,634Total

$
88,353Allocation of acquisition costs:Current assets

$
6,171Oil and gas propertiesproved


46,886Undeveloped properties


32,610Other facilities


2,686Total

$
88,353


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.



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, 2000. These unaudited pro forma results have been prepared for comparative purposes only and are not indicative of future results.

Year Ended December 31,2001

2000(in thousands, except per share data)Revenue

$
200,914

$
233,169Net income

$
2,687

$
13,347Basic net income per share

$
0.32

$
1.58Diluted net income per share

$
0.32

$
1.57


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.

5. Debt



On May 24, 2002, we amended our credit facility (the "Credit Facility") with various financial institutions. The $60 million revolving credit
facility is comprised of two components: (i) a $25 million U.S. facility and, (ii) through our wholly owned Canadian subsidiary, a $35 million Canadian facility.

Available
borrowings under the Credit Facility are determined by (i) a borrowing base, calculated semiannually, which is based principally on the proved reserves of our oil and
gas properties ($38 million was available as of December 31, 2002); and (ii) a working capital borrowing base, calculated monthly, which is based on NGL product accounts
receivable and inventory levels, to a maximum of $20 million ($13.2 million was available as of December 31, 2002). Actual borrowing limits may be less than $60 million,
and MarkWest Hydrocarbon may be required to pay down amounts borrowed in excess of their applicable borrowing base, depending on proved reserves for our properties, our working capital and our
financial covenants. At December 31, 2002, MarkWest Hydrocarbon had outstanding borrowings of $42.8 million under the Credit Facility.

The
Credit Facility permits us to borrow money using a base rate loan, plus an applicable margin of 0.375% and 1.375%, or a London Interbank Offered Rate ("LIBOR") loan option, plus an
applicable margin of between 1.75% 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 matures in August 2004. For the year ended December 31, 2002, the weighted average interest rate was 4.88%.

The
Credit Facility contains various covenants limiting our ability to:



The
Credit Facility also contains covenants requiring us to maintain a minimum tangible net worth and meet certain financial ratios, as defined in the Credit Facility. The Credit
Facility is secured by a first lien on substantially all of our assets, excluding our Partnership subordinated units and our interest in the Partnership's general partner.



In connection with its initial public offering, a wholly owned subsidiary of the Partnership (the "Operating Partnership") entered into a $60.0 million
credit facility (the "Partnership Credit Facility") with various financial institutions. The Partnership Credit Facility was expanded to $75 million in March 2003. The Partnership Credit Facility is comprised of both a revolving and term loan credit facility.

Under
the revolving credit facility, up to $28.6 million is available to fund capital expenditures and acquisitions and up to $10 million is available for working capital
purposes (including letters of credit) and to fund distributions to unitholders. However, not more than $2.25 million may be used in any four-quarter period to fund distributions to
unitholders. On May 24, 2002, the date our IPO closed, $21.4 million was drawn under the term loan and remained outstanding at December 31, 2002. Total credit available to be
drawn at December 31, 2002 was approximately $38.6 million.

The
Operating Partnership may prepay all loans at any time without penalty. The Operating Partnership will be required to reduce all working capital borrowings under the revolving credit
facility to zero for a period of at least 15 consecutive days once each calendar year.

Indebtedness
under the credit facility bears interest, at the Operating Partnership's option, at either (i) the higher of the federal funds rate plus 0.50% or the prime rate as
announced by lender plus an applicable margin of 0.375% to 1.375% or (ii) at a rate equal to LIBOR plus an applicable margin ranging from 1.75% per annum to 2.75% per annum depending on the
Partnership's ratio of Funded Debt (as defined in the Partnership Credit Facility) to EBITDA (as defined in the Partnership Credit Facility) for the four most recently completed fiscal quarters. For
the year ended December 31, 2002, the weighted average interest rate was 3.58%. The Operating Partnership incurs a commitment fee on the unused portion of the credit facility at a rate ranging
from 25.0 to 50.0 basis points based upon the ratio of our Funded Debt to EBITDA for the four most recently completed fiscal quarters. The
Partnership Credit Facility matures in May 2005. At that time, both the revolving and term loan credit facilities will terminate and all outstanding amounts thereunder will be due and payable.

The
Partnership Credit Facility contains various covenants limiting the Partnership's ability to:



The
Partnership Credit Facility also contains covenants requiring the Operating Partnership to maintain a minimum net worth and meet certain financial ratios, as defined in the Credit
Agreement. The Partnership and the subsidiaries of the Operating Partnership serve as joint and several guarantors of any obligations under the Partnership Credit Facility. The guarantees are full and
unconditional. The Partnership Credit Facility is secured by substantially all the assets of the Partnership and its subsidiaries.



Scheduled debt maturities as of December 31, 2002, were as follows (in thousands):

2003

$
2004


42,8232005


21,4002006


2007


2008 and thereafter


Total debt outstanding

$
64,223


6. 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, 2002 and 2001, we have receivables due from MAK-J, representing its share of operating and capital costs generated in the normal course of business, of
approximately $0.7 million and $0.6 million, respectively. We also have payables to MAK-J, representing its share of revenues generated in the normal course of business, of
approximately $1.3 million and $0.5 million for the years ended December 31, 2002, and 2001, respectively.

7. Benefit Plan

We made contributions of $0.3 million, $0.3 million, $0.5 million to a 401(k) savings and profit-sharing plan for the years ended
December 31, 2002, 2001 and 2000, respectively. The plan is discretionary, with annual contributions determined by our Board of Directors.





8. 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.

9. Commodity Price Risk Management



Our business produces products, natural gas and NGLs, and provides services, gathering and processing of natural gas and the transportation, fractionation and
storage of NGLs. Our products are commodities that are subject to price risk. Commodity prices are often subject to material changes in response to relatively minor changes in supply and demand,
general economic conditions and other market conditions over which we have no control, like the weather.

Our
primary risk management objective is to manage our price risk, thereby reducing volatility in our cash flows. Our risk management activities generally fall into one of these
categories: (i) hedges of those risks not mitigated by our "natural hedge" (discussed below); (ii) hedges to realize the economics of a transaction, like our 2001 Canadian E&P
acquisition; and (iii) our exploration and production basis hedges.

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 may 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 the 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 financial institutions. 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 (with non-bank counterparties) and NYMEX positions.

The
use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (i) sales volumes may be less than expected
requiring market purchases to meet commitments, (ii) our OTC counterparties could fail to purchase or deliver the contracted quantities of natural gas, NGL, or crude oil or otherwise fail to
perform, and (iii) when the trading relationship between crude oil and NGL products is outside historical levels. 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.



Within our exploration and production segment, our revenues are subject to natural gas price risk. Within our NGL marketing segment, our price risk varies by
contract as well as by spot market prices. Our Appalachian producers compensate us for providing midstream services under one of two contract types:





To the extent our natural gas production equals our keep-whole requirements for purchasing natural gas in Appalachia and there are no material
differences in net prices, we have a "natural hedge" and our commodity price risk is substantially mitigated. As of December 31, 2002, our equity natural gas production approximated
    % of our keep-whole natural gas purchase requirements, making us a net consumer of natural gas and subject to natural gas price risk.

However,
we are exposed to basis risk. Our basis risk for natural gas stems from the geographic price differentials between our E&P sales location (San Juan basin and Alberta, Canada)
and hedging contract delivery location (NYMEX) and our marketing purchase location (Appalachia) and NYMEX. We hedge our basis risk for natural gas.

As
of December 31, 2002, our natural gas basis hedges were as follows:

Table I
Hedged Natural Gas BasisYear Ending
December 31, 2003MMBtu


2,996,000$/MMBtu

$
(0.42
)


We
are generally unable to hedge our basis risk 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.



Generally, we are an overall net consumer of natural gas as our keep-whole contractual requirements for purchasing natural gas in Appalachia currently
exceed our natural gas production. Until such time this relationship reverses and we become a net producer of natural gas, we are limiting our E&P hedges to either (a) obtaining futures prices
that our models suggest are optimal or (b) realizing the economics of a transaction, like our 2001 Canadian E&P acquisition. Generally, we execute our strategy by either selling
fixed-for-float swaps or utilizing costless collars. As of December 31, 2002, we have hedged our combined Canadian and Rocky Mountain natural gas volumes and prices as follows:

Table II
Hedged Natural Gas SalesYear Ending December 31,2003

2004

2005MMBtu


3,500,000


2,877,000


44,000$/MMBtu

$
3.43

$
3.26

$
3.34Henry Hub Equivalent $/MMBtu(1)

$
4.06

$
3.75

$
3.69


---

Also,
within our marketing segment, for certain Appalachian natural gas sales, as of December 31, 2002, we hedged 195,000 MMBtu at $4.09 per MMBtu for 2003.



We hedge our NGL product sales by selling forward propane or crude oil. As of December 31, 2002, we have hedged Appalachian and stet NGL product sales as
follows:

Table III
Hedged Sales Price for NGL ProductsYear Ending December 31,2003

2004MarkWest Hydrocarbon, Inc.NGL Volumes Hedges Using Crude OilNGL gallons


85,979,000


13,113,000NGL sales prices per gallon

$
0.44

$
0.51MarkWest Energy Partners, L.P.NGL Volumes Hedged Using Crude OilNGL gallons


3,731,000


NGL sales price per gallon

$
0.47


NGL Volumes Hedged Using PropaneNGL gallons


1,260,000


NGL sales price per gallon

$
0.41


Total NGL Volumes HedgedNGL gallons


4,991,000


NGL sales price per gallon

$
0.45





Under
Table III, all projected margins or prices on open positions assume that both (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. For the year
ended December 31, 2002, the correlation between crude oil and NGL products was at times not consistent with historical averages; see Note 2.

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.

To
the extent our Appalachian natural gas purchase requirements exceed our E&P natural gas production, we are simultaneously subject to NGL price risk on the sales side and natural gas
price risk on the purchase side within our GPM business. Consequently, we may hedge our Appalachian processing margin (defined as revenues less purchased gas costs) by simultaneously selling propane
or crude oil while purchasing natural gas. However, as of December 31, 2002, we had no such hedges in place.

10. 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 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 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.

11. Income Taxes

The provision for income taxes is comprised of:

Year Ended December 31,2002

2001

2000(in thousands)Current:Federal

$
707

$


$
1,260State


55


82


406Foreign








Total current


762


82


1,666Deferred:Federal


(2,015
)

1,544


2,697State


(192
)

296


525Foreign


(367
)

(341
)

Total deferred


(2,574
)

1,499


3,222Total tax provision

$
(1,812
)
$
1,581

$
4,888




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

December 31,
2002

December 31,
2001(in thousands)Property, plant and equipment

$
41,464

$
45,583Risk management assets


(4,248
)

2,807Other assets


1,214


337Total deferred income tax liabilities


38,430


48,727Alternative minimum tax (AMT) credit carryforwards


(2,739
)

(2,031
)Federal net operating loss (NOL) carryforwards





(1,152
)State net operating loss (NOL) carryforwards





(227
)Intangible assets


(6
)

(6
)Total deferred income tax assets


(2,745
)

(3,416
)Net deferred tax liability

$
35,685

$
45,311


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 31,2002

2001

2000(in thousands)Income tax at statutory rate

$
(1,600
)
$
1,538

$
4,818State income taxes, net of federal benefit


(89
)

245


603Income tax credits


(274
)




(558
)Foreign operations:Resource allowance


(1,106
)

(471
)

Crown royalties


1,100


308


Other


157


(39
)

25Total

$
(1,812
)
$
1,581

$
4,888


At
December 31, 2002, we had AMT credit carryforwards for federal income tax purposes of approximately $2.7 million. We had no federal NOL or state NOL
carryforwards. These carryforwards expire as follows:

Expiration Dates

Federal NOL

State NOL

AMT(in thousands)2018

$


$


$
2019








2021








No expiration








2,739Total

$


$


$
2,739


We
believe that 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.

12. Stock Compensation Plans

At December 31, 2001, we have two stock-based compensation plans, and, through our consolidated subsidiary, MarkWest Energy Partners, a variable
unit-based plan. These plans are described below. We apply APB Opinion No. 25,Accounting for Stock Issued to Employees,and related
Interpretations in accounting for our plans. Accordingly, no compensation cost has been recognized for our fixed stock option plans but we did recognize $0.1 million in compensation expense for
the variable plan for the year ended December 31, 2002.

Under
the 1996 Stock Incentive Plan, we may grant options to our employees for up to 925,000 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 30,000 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 2002, 2001 and 2000 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:

2002

2001

2000Expected life of options

6 years

6 years

6 yearsRisk free interest rates

3.54%

4.84%

5.93%Estimated volatility

52%

52%

43%Dividend yield

0.0%

0.0%

0.0%


A
summary of the status of our two fixed stock option plans as of December 31, 2002, 2001 and 2000, and changes during the years ended on those dates are presented below:

|                                                                      |  | 2002 |         | 2001 |   | 2000
|--------------------------------------------------------------------- |  | ---- | ------- | ---- | - | ----
|
|Fixed Options                                                         |  |      |         |      |   |     
|Outstanding at beginning of year                                      |  |      | 792,948 |      | $ | 9.18
|Granted                                                               |  |      | 20,000  |      |   | 6.09
|Exercised                                                             |  |      | (386    | )    |   | 5.38
|Cancelled                                                             |  |      | (84,247 | )    |   | 9.51
|                                                                      |  |      |         |      |   |     
|Outstanding at end of year                                            |  |      | 728,315 |      | $ | 9.06
|                                                                      |  |      |         |      |   |     
|Options exercisable at December 31, 2002, 2001 and 2000, respectively |  |      | 559,382 |      |   |     
|Weighted-average fair value of options granted during the year        |  | $    | 2.54    |      |   |     



The
following table summarizes information about fixed stock options outstanding at December 31, 2002:

Options Outstanding

Options ExercisableRange of Exercise Prices

Number
Outstanding
at 12/31/02

Weighted-
Average
Remaining
Contractual
Life

Weighted-
Average
Exercise
Price

Number
Exercisable
At 12/31/02

Weighted-
Average
Exercise
Price$  5.34 to $  6.99

153,411

3.53

$
6.25

121,684

$
6.41$  7.14 to $  8.75

195,251

6.50


8.28

112,995


8.33$  9.00 to $10.50

157,041

3.66


10.16

140,467


10.15$10.75 to $10.75

158,614

4.83


10.75

149,871


10.75$11.25 to $11.38

63,998

7.38


11.25

34,365


11.25$  5.34 to $11.38

728,315

4.97

$
9.06

559,382

$
9.20


13. 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, 2002, 2001 and 2000:

|                                                                                                           |               | Year Ended December 31,
|---------------------------------------------------------------------------------------------------------- | ------------- | -----------------------
|
|
|Net income (loss)                                                                                          |               | $                      
|                                                                                                           |               |                        
|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 |               |                        
|                                                                                                           |               |                        

14. Segment Reporting

Our operations are classified into three reportable segments:



On
May 24, 2002, we spun off our gathering and processing assets into MarkWest Energy Partners, L.P., our fully consolidated subsidiary. The formation and initial public offering
of MarkWest Energy Partners (the IPO closed on May 24, 2002) and the subsequent change to the structure of our internal organization caused the composition of our reportable segments to change in the fourth quarter of 2002. Prior to the fourth quarter of 2002, we classified our operations into two reportable segments:



Although
the period from May 24, 2002 through December 31, 2002 reflects our new segments, information prior to May 24, 2002 has not been restated to reflect the
change in segmentation because no transfer pricing existed between Gathering and Processing and Marketing up until that point in time. In connection with the formation of MarkWest Energy Partners,
certain contracts were executed which established the basis of fees for services rendered by processing MarkWest Hydrocarbon's natural gas. No such arrangement existed prior to the formation of
MarkWest Energy Partners. As a result, it is not practicable to restate certain prior period segment information to conform with our current presentation.

We
evaluate the performance of our segments and allocate resources to them based on operating income. There were no intersegment revenues prior to May 24, 2002. 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, 2002, 2001 and 2000. 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 have not reported asset information by reportable segment because we do not produce such information internally.

|                                 |  | MarkWest Hydrocarbon
|-------------------------------- |  | --------------------
|
|
|
|May 24 through December 31, 2002 |  |                     
|Revenues                         |  | $                   
|Segment operating income         |  | $                   

|                               |  | Exploration and Production |        | Gathering
Processing &
Marketing |   |      
|------------------------------ |  | -------------------------- | ------ | -------------------------------- | - | -----
|
|January 1 through May 23, 2002 |  |                            |        |                                  |   |      
|Revenues                       |  | $                          | 3,775  |                                  | $ | 8,040
|Segment operating income       |  | $                          | 1,356  |                                  | $ | 834  
|Year ended December 31, 2001   |  |                            |        |                                  |   |      
|Revenues                       |  | $                          | 10,101 |                                  | $ | 5,075
|Segment operation income       |  | $                          | 4,462  |                                  | $ | 251  
|Year ended December 31, 2000   |  |                            |        |                                  |   |      
|Revenues                       |  | $                          | 4,559  |                                  | $ |     
|Segment operating income       |  | $                          | 1,241  |                                  | $ |     

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

|                                                           |                            | Year Ended December 31, |        
|---------------------------------------------------------- | -------------------------- | ----------------------- | -------
|
|
|Total segment operating income                             |                            | $                       | 10,454 
|Selling, general and administrative expenses               |                            |                         | (11,885
|Interest income                                            |                            |                         | 65     
|Interest expense                                           |                            |                         | (3,840 
|Write-down of deferred financing costs                     |                            |                         | (2,977 
|Gain on sale of non-operating assets                       |                            |                         | 5,454  
|Gain on sale of non-operating asset to related party       |                            |                         | 141    
|Minority interest in net income of consolidated subsidiary |                            |                         | (1,947 
|Other income (expense)                                     |                            |                         | (73    
|                                                           |                            |                         |        
|                                                           | Income (loss) before taxes |                         | $      
|                                                           |                            |                         |        



15. Commitments and Contingencies



MarkWest Hydrocarbon, in the ordinary course of business, is a party to various legal actions. In the opinion of management, none of these actions, either
individually or in the aggregate, will have a material adverse effect on our financial condition, liquidity or results of operations.



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 $2.3 million, $2.0 million and $1.8 million for the three years ended December 31, 2002, 2001 and 2000, respectively. Our minimum
future lease payments under these operating leases as of December 31, 2002, are as follows (in thousands):

2003

$
2,2632004


1,9592005


1,9712006


1,8682007


1,4832008 and thereafter


3,182Total

$
12,726


16. Quarterly Results of Operations (Unaudited)

The following summarizes certain quarterly results of operations:

|                                            |  | Three Months Ended
|------------------------------------------- |  | ------------------
|
|2002                                        |  |                   
|Operating revenue                           |  | $                 
|Income (loss) from operations               |  | $                 
|Net income (loss)                           |  | $                 
|Basic earnings (loss) per share             |  | $                 
|Earnings (loss) per share assuming dilution |  | $                 
|2001                                        |  |                   
|Operating revenue                           |  | $                 
|Income from operations                      |  | $                 
|Net income (loss)                           |  | $                 
|Basic earnings (loss) per share             |  | $                 
|Earnings (loss) per share assuming dilution |  | $                 

17. Subsequent Event

On March 24, 2003, our consolidated subsidiary, MarkWest Energy Partners, entered into an agreement to merge with Pinnacle Natural Gas Company and certain
affiliates for approximately $38 million. The acquired assets, primarily located in Texas, are comprised of three lateral natural gas pipelines and eighteen gathering systems. The acquisition
will be financed primarily through borrowings under the Partnership's credit facility, which was recently expanded by $15 million.

18. 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.

(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, 2002, 2001 and 2000:

United States

Canada

Total(in thousands)2002Property acquisition costs (undeveloped leases and proved properties)

$
1,792

$
1,252

$
3,044Exploration costs


1,170


5,360


6,530Development costs


7,851


10,270


18,121Total

$
10,813

$
16,882

$
27,6952001Property acquisition costs (undeveloped leases and proved properties)

$
4,563

$
79,496

$
84,059Exploration costs


1,259


1,387


2,646Development costs


3,427


1,826


5,253Total

$
9,249

$
82,709

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

$
739

$


$
739Exploration costs


1,589





1,589Development costs


1,818





1,818Total

$
4,146

$


$
4,146


(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:

2002

2001

2000(in thousands)Costs related to proved properties

$
99,360

$
72,294

$
12,481Costs related to unproved properties


32,934


36,629


4,072Costs related to equipment and facilities


6,940


4,570


1,484139,234


113,493


18,037Less: accumulated depreciation and depletion


(21,876
)

(7,119
)

(2,018
)Net capitalized costs

$
117,358

$
106,374

$
16,019


(C) Results of Operations from Producing ActivitiesResults of operations from producing activities for the years ended
December 31, 2002, 2001 and 2000 are presented below. Income taxes are 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(in thousands)2002Revenues:Sales

$
9,988

$
20,717

$
30,705Other


468


1,750


2,218Total


10,456


22,467


32,923Production taxes


(591
)

(1,453
)

(2,044
)Transportation and processing costs


(1,199
)

(481
)

(1,680
)Lease operating costs


(2,777
)

(5,136
)

(7,912
)Depreciation and depletion


(2,506
)

(13,179
)

(15,685
)Operating income


3,383


2,218


5,601Income tax expense


(1,313
)

(959
)

(2,272
)Results of operations

$
2,070

$
1,259

$
3,3292001Revenues:Sales

$
9,761

$
5,075

$
14,836Other


157





157Total


9,918


5,075


14,993Production taxes


(674
)




(674
)Transportation and processing costs


(1,314
)

(431
)

(1,745
)Lease operating costs


(1,743
)

(948
)

(2,691
)Depreciation and depletion


(1,726
)

(3,445
)

(5,171
)Operating income


4,461


251


4,712Income tax benefit


(1,726
)

(76
)

(1,802
)Results of operations

$
2,735

$
175

$
2,9102000Revenues:Sales

$
4,181

$


$
4,181Other


91





91Total


4,272





4,272Production taxes


(450
)




(450
)Transportation and processing costs


(781
)




(781
)Lease operating costs


(1,142
)




(1,142
)Depreciation and depletion


(658
)




(658
)Operating income


1,241





1,241Income tax benefit


185





185Results of operations

$
1,426

$


$
1,426


(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 2002, 2001 and 2000 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.

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, 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 |       
|                              | Revisions of previous estimates |        | 1,393 
|                              | Purchase of minerals in place   |        | 2,749 
|                              | Extensions and discoveries      |        | 3,458 
|                              | Production                      |        | (3,367
|                              | Sale of minerals in place       |        |      
|                              |                                 |        |       
|Balance at December 31, 2002  |                                 | 45,721 |       
|                              |                                 |        |       
|Proved developed reserves at: |                                 |        |       
|                              | December 31, 1999               |        | 22,114
|                              | December 31, 2000               |        | 22,804
|                              | December 31, 2001               |        | 28,586
|                              | December 31, 2002               |        | 37,327



(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 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.

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 38.8% in the United States and a combined federal and provincial rate of 43.25%
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, 2002 |        
|-------------------------------------------------------- |  | ----------------- | -------
|
|
|Future gas sales                                         |  | $                 | 197,626
|Future production costs                                  |  |                   | (65,035
|Future development costs                                 |  |                   | (3,888 
|Future income taxes                                      |  |                   | (47,165
|                                                         |  |                   |        
|Future net cash flows                                    |  |                   | 81,538 
|10% annual discount for estimated timing of cash flows   |  |                   | (37,849
|                                                         |  |                   |        
|Standardized measure of discounted future net cash flows |  | $                 | 43,689 
|                                                         |  |                   |        



Present
value of future net cash flows before income taxes was $67,524 in the United States and $63,751 in Canada at December 31, 2002.

|                                                         |  | 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, 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.

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, 2002 |       
|-------------------------------------------------------------------------------------------------------------- | ----------------------------------------------------------------------- | ----------------- | ------
|
|
|Standardized measure of discounted future net cash flows relating to proved gas reserves, at beginning of year |                                                                         | $                 | 18,366
|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       |                                                                         | $                 | 43,689
|                                                                                                               |                                                                         |                   |       

The
computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2002 was based on year end natural gas
prices of approximately $4.27 per Mcfe in the United States and approximately $3.87 per Mcfe in Canada, equivalent to $4.74 per MMBtu at the Henry Hub.

|                                                                                                               |                                                                         | 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
|                                                                                                               |                                                                         |                   |       

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.



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 AND EXECUTIVE OFFICERS OF THE REGISTRANT

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 sections 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 AND RELATED STOCKHOLDER MATTERS

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.

ITEM 14. CONTROLS AND PROCEDURES

Based on their evaluation of the internal controls, disclosure controls and procedures within 90 days of the filing date of this report, the Chief
Executive Officer and the Chief Financial Officer have concluded that the effectiveness of the Company's controls and procedures is satisfactory. Further, there were not any significant changes in our
internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.





PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K



| |  | 2.2   | (3) | Share Purchase Agreement between MarkWest Hydrocarbon Acquisition Corporation and Kaiser Energy, Ltd., dated as of August 10, 2001                                                                                                                                        
| |  | ----- | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | 2.3   | (3) | Share Purchase Agreement between MarkWest Hydrocarbon Acquisition Corporation and Brian E. Hiebert, Guy C. Crierson, Ian R. DeBie, Gordon A. Maybee, Erin Hiebert, Raylene Grierson, Kathleen DeBie and Patricia Maybee, dated as of August 10,
2001.                     
| |  | 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.                                                                                                                                                                                                                                         
| |  | 10.3  | (1) | 1996 Stock Incentive Plan.                                                                                                                                                                                                                                                
| |  | 10.4  | (1) | 1996 Non-employee Director Stock Option Plan.                                                                                                                                                                                                                             
| |  | 10.5  | (1) | Form of Non-Compete Agreement between John M. Fox and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                          
| |  | 10.6  | (4) | MarkWest Hydrocarbon, Inc., 1997 Severance and Non-Compete Plan.                                                                                                                                                                                                          
| |  | 10.7  | (5) | Fifth Amended and Restated Credit Agreement among MarkWest Hydrocarbon, Inc. and various lenders, dated as of May 24, 2002.                                                                                                                                               
| |  | 10.8  | (5) | Amended and Restated Canadian Credit Agreement among MarkWest Resources Canada Corp. and various lenders, dated as of May 24, 2002.                                                                                                                                       
| |  | 10.11 | (6) | Subordinated Unit Purchase Agreement among MarkWest Hydrocarbon, Inc. and Tortoise MWEP, L.P., dated as of November 20, 2002.                                                                                                                                             
| |  | 11.1* |     | Statement regarding computation of earnings per share.                                                                                                                                                                                                                    
| |  |       |     |                                                                                                                                                                                                                                                                           

| |  | 21.1* |  | List of Subsidiaries of MarkWest Hydrocarbon, Inc.                                                                                                                       
| |  | ----- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | 23.1* |  | Consent of PricewaterhouseCoopers LLP                                                                                                                                    
| |  | 23.2* |  | Consent of Cawley, Gillespie & Associates, Inc.                                                                                                                          
| |  | 23.3* |  | Consent of Gilbert Laustsen Jung Associates, Ltd.                                                                                                                        
| |  | 99.1* |  | Certification of Chief Executive Officer of the General Partner pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
| |  | 99.2* |  | Certification of Chief Financial Officer of the General Partner pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

---





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, 2003.

| |  |  |  | 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 Chairman                                                                                       |  |  | March 29, 2003
| |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------- |  |  | --------------
| |  | /s/DONALD C. HEPPERMANNDonald C. Heppermann
Senior Vice President,
Chief Financial Officer, Secretary and Director
(Principal Financial and Accounting Officer) |  |  | March 29, 2003
| |  | /s/ARTHUR J. DENNEYArthur J. Denney
Executive Vice President
and Director                                                                                       |  |  | March 29, 2003
| |  | /s/WILLIAM A. KELLSTROMWilliam A. Kellstrom
Director                                                                                                            |  |  | March 29, 2003
| |  | /s/KAREN L. ROGERSKaren L. Rogers
Director                                                                                                                      |  |  | March 29, 2003
| |  | /s/BARRY W. SPECTORBarry W. Spector
Director                                                                                                                    |  |  | March 29, 2003
| |  | /s/DONALD D. WOLFDonald D. Wolf
Director                                                                                                                        |  |  | March 29, 2003



CERTIFICATION

I, John M. Fox, certify that:



Date:
March 29, 2002

| | /s/JOHN M. FOXJohn M. Fox
President and
Chief Executive Officer
| | ---------------------------------------------------------------



CERTIFICATION

I, Donald C. Heppermann, certify that:



Date:
March 29, 2003

| | /s/DONALD C. HEPPERMANNDonald C. Heppermann
Senior Executive Vice President
and Chief Financial Officer
| | -------------------------------------------------------------------------------------------------------