<PAGE>

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

                                    FORM 10-K

[X]  Annual report pursuant to Section 13 or 15(d) of the Securities Exchange
     Act of 1934 for the fiscal year ended December 31, 2000.

[ ]  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                                84-1352233
     (State or other jurisdiction of                  (I.R.S. Employer
     incorporation or organization)                  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 /X/   No / /

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. ____

The aggregate market value of voting common stock held by non-affiliates of the
registrant on February 27, 2001, was $32,455,465.

The number of shares outstanding of the registrant's common stock as of February
27, 2001, was 8,568,641.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of this Report (Items 10, 11, 12 and 13) is
incorporated by reference from the registrant's proxy statement to be filed
pursuant to Regulation 14A with respect to the 2001 annual meeting of
stockholders.

                                       1
<PAGE>

                           MARKWEST HYDROCARBON, INC.
                                    FORM 10-K
                                TABLE OF CONTENTS

<TABLE>
<CAPTION>
                                                                                Page
                                                                                ----
<S>                                                                             <C>
PART I
    Items 1. and 2.  Business and Properties
       General.................................................................   3
       Strategy................................................................   3
       Segments................................................................   3
       Significant 2000 and 2001 Developments..................................   3
       Gathering, Processing and Marketing.....................................   5
       Exploration and Production..............................................   7
       Seasonality.............................................................   8
       Competition ............................................................   9
       Operational Risks and Insurance.........................................   9
       Governmental Regulation.................................................   9
       Environmental Matters...................................................  10
       Employees...............................................................  10
       Forward-Looking Information.............................................  10
    Item 3.  Legal Proceedings.................................................  10
    Item 4.  Submission of Matters to a Vote of Security Holders...............  11

PART II
    Item 5.  Market for the Registrant's Common Equity and Related
             Stockholder Matters...............................................  11
    Item 6.  Selected Financial Data...........................................  12
    Item 7.  Management's Discussion and Analysis of Financial Condition
             and Results of Operations.........................................  13
    Item 7A. Quantitative and Qualitative Disclosures About Market Risk........  17
    Item 8.  Financial Statements and Supplementary Data.......................  19
    Item 9.  Changes in and Disagreements with Accountants on Accounting
             and Financial Disclosure..........................................  37

PART III
    Item 10. Directors and Executive Officers of the Registrant................  37
    Item 11. Executive Compensation............................................  37
    Item 12. Security Ownership of Certain Beneficial Owners and Management....  37
    Item 13. Certain Relationships and Related Transactions....................  37

PART IV
    Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..  37

</TABLE>

Glossary of Terms

Bbls          barrels
Bcf           billion cubic feet of natural gas
Btu           British thermal unit, an energy measurement
EBITDA        earnings before gain on sale, interest income, interest expense,
              income taxes, depreciation, depletion and amortization; a cash
              flow financial measure commonly used in the oil and gas industry
MM            million
Mcf           thousand cubic feet of natural gas
Mcfd          thousand cubic feet of natural gas per day
Mcfe          thousand cubic feet of natural gas equivalent
MMBtu         million British thermal units, an energy measurement
MMcf          million cubic feet of natural gas
MMcfd         million cubic feet of natural gas per day
NGL           natural gas liquids, such as propane, butanes and natural gasoline

One barrel of oil or NGL is the energy equivalent of six Mcf of natural gas.

                                       2
<PAGE>

                                     PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

GENERAL

MarkWest Hydrocarbon, Inc., and its subsidiaries (referred to collectively as
the "Company" or "MarkWest") provide natural gas processing and related services
and produce natural gas. The Company's natural gas processing and related
activities (its gathering, processing and marketing segment) include providing
compression, gathering, treatment and NGLs extraction services to natural gas
producers and pipeline companies. Additionally, MarkWest fractionates NGLs into
marketable products and purchases and markets natural gas and NGLs. MarkWest
provides natural gas processing and related services through its modern,
efficient plant and pipeline systems. Increased drilling for natural gas to meet
expanding demand is driving growth for MarkWest's specialized services. Natural
gas producers are increasingly outsourcing the complex task of converting raw
natural gas produced at the wellhead to marketable natural gas and natural gas
liquids. MarkWest is the largest processor of natural gas in Appalachia and the
Company owns the only sour gas gathering and processing facilities in western
Michigan. The Company also produces natural gas in the Rocky Mountains and
Michigan (its exploration and production segment).

The Company was founded as a partnership in 1988 and incorporated in Delaware
and completed its initial public offering in 1996. The Company's principal
executive office is located at 155 Inverness Drive West, Suite 200, Englewood,
Colorado, 80112-5000, and its telephone number is (303) 290-8700. MarkWest
maintains an NGL marketing office in Columbus, Ohio and a gas marketing and
Appalachia producer relations office in Pittsburgh, Pennsylvania.

STRATEGY

MarkWest's strategy is to provide trend-line profit growth exceeding 15 percent
annually by (1) increasing volumes of natural gas processed and volumes of NGLs
produced and marketed; and (2) by increasing its natural gas production. In its
gathering, processing and marketing segment, the Company focuses on geographic
core areas where natural gas production is expected to increase, providing
opportunities for reinvestment. This focus allows MarkWest to capitalize on its
infrastructure for the benefit of its customers and its shareholders. Innovative
engineering, cost-efficient operations and effective NGL marketing are core
competencies of the Company. MarkWest also uses exploration to enhance its gas
processing business. In its exploration and production segment, the Company
focuses on lower-risk exploitation rather than exploration.

The Company aims to reduce earnings volatility through emphasis in its business
development efforts on fee-based services not susceptible to changes in
commodity prices (in its gathering, processing and marketing segment) and
through increasing hedging activities in 2001 and beyond (in both segments) when
market conditions permit. Fee-based services have increased to account for about
40 percent or more of gross margins in 2001 from less than 10 percent seven
years ago.

SEGMENTS

The Company's business activities are segregated into two segments: gathering,
processing and marketing, and exploration and production of natural gas.
Gathering, processing and marketing are concentrated in two core areas: the
significant gas-producing basin in the southern Appalachian region of eastern
Kentucky, southern West Virginia, and southern Ohio (the "Appalachian Core Area"
or "Appalachia"); and the developing basin in western Michigan (the "Michigan
Core Area" or "Michigan"). Exploration and production activities are
concentrated in the Rocky Mountains and eastern Michigan. These segments are
analyzed independently by management and derive revenue from different sources.
For financial information related to each segment, see RESULTS OF OPERATIONS, in
Item 7 - Management's Discussion and Analysis of Financial Condition and Results
of Operations, as well as Note 12, SEGMENT REPORTING, in the Notes to the
Consolidated Financial Statements in Item 8 of this Form 10-K.

SIGNIFICANT 2000 AND 2001 DEVELOPMENTS

Gathering, Processing and Marketing

During 2000, the two-phased expansion of the company's Appalachian
infrastructure continued. Phase I expansion was completed in February 2000 and
Phase II is in progress for completion expected by mid-2001.

Phase I expansion added a new 75 MMcfd, mechanical refrigeration, NGL extraction
plant ("Maytown") in southern Kentucky and nearly doubled the capacity, from
350,000 gallons per day to 600,000 gallons per day, of the Company's
fractionator ("Siloam") in northern Kentucky. Revenues to be derived from the
expansion are primarily fee and percent-of-proceeds based, which differ from
MarkWest's historical commodity-based contracts. Finally, MarkWest acquired a
40-mile NGL pipeline in West Virginia. This pipeline, together with MarkWest's
existing pipeline and a pipeline leased in 1999, forms a continuous 180-mile
pipeline network through the

                                       3
<PAGE>

southern portion of the Appalachia Basin. The pipeline connects MarkWest's new
Maytown gas plant to MarkWest's Siloam fractionator and significantly reduces
feedstock transportation costs from another of MarkWest's gas plants-Boldman.
MarkWest's Kenova gas plant was already connected to the pipeline.

On February 1, 2000, MarkWest assumed operation of the Company-owned Boldman
extraction plant from Columbia Gas Transmission Corporation ("Columbia").
Boldman is located in Kentucky. In March 2000, MarkWest acquired the Cobb, West
Virginia, natural gas liquids (NGLs) extraction plant from Columbia. NGLs
extracted at Boldman and Cobb have been and will continue to be fractionated
into propane, butane and other liquids at the Company's Siloam plant.

Phase II involves construction of the Kermit dewpoint control plant and
expanding MarkWest's Kenova NGL extraction plant, increasing MarkWest's total
production to 550,000 gallons per day. Phase II started construction in October
2000 and is targeted for completion and startup in mid-2001.

Capital spending for the Phase I and II expansions is estimated at $14 million
and $13 million, respectively.

To keep pace with the growing Appalachia NGL production, MarkWest has been
adding to its marketing infrastructure-additional terminals, tank railcars,
pressurized trailers and new and larger loading facilities. Over the period
1999-2001, MarkWest is investing $8 million in additional marketing assets.

In March 2000, MarkWest opened a new propane terminal at Lordstown, Ohio.
Lordstown is located about 300 truck miles northeast of MarkWest's Siloam
fractionation plant and accesses new retail markets. In September 2000, MarkWest
leased 60 additional railcars.

In May 2000, MarkWest entered into a two-year marketing agreement with a propane
retailer for an exclusive supply agreement for their propane requirements for 17
retail bulk plants in Ohio and Kentucky. MarkWest is also leasing additional
propane storage space. The agreement will involve about 30 million gallons per
year of propane sales, primarily from MarkWest's Siloam fractionation
facilities. MarkWest also bought twelve pressurized tank trailers to serve this
supply arrangement.

Although the Company's favorable year 2000 financial performance met Company
objectives, events since December 2000 have proved to be more challenging.
Futures prices for natural gas have risen dramatically, and prices for NGLs have
stayed essentially flat. A large portion, about 75 percent, of MarkWest's
processing services for gas producers in Appalachia involves extracting NGLs
from inlet gas streams and replacing the equivalent heat content with dry
natural gas purchased in the spot or forward markets. This part of the Company's
operating margin depends on a positive spread between NGL prices and natural gas
costs. Effective February 1, 2001, the Company provided producers with an
alternative processing contract that provides for additional compensation to the
Company when processing margins are low and reduced compensation when processing
margins are high. To date, about 65 producers (accounting for a minority share
of the volume) out of approximately 325 have agreed to the new contract. If
producers elect to remain with the existing contract, the Company has stated
that it will return the replacement natural gas at a later date, as it believes
is permitted under the existing contract, such that MarkWest can earn a
reasonable fee for its services. This is not an isolated situation with
MarkWest-nationwide, producers and processors are renegotiating their processing
agreements due to the relatively high cost of natural gas. These new
arrangements provide producers the capacity necessary to support their
increasing production. See also ITEM 3 - LEGAL PROCEEDINGS of this Form 10-K.

Exploration and production

In the third quarter of 2000, the Au Gres field in eastern Michigan began
producing from an initial well after completion of necessary surface facilities.
By year-end 2000, the well was producing 2,000 Mcf per day, with reserves
estimated at nearly 3 billion cubic feet (Bcf). The next well is expected to be
completed late first quarter 2001, with further expansions possible in late
2001. The Company's interest is 68 percent until payout, reverting to 23
percent, with an option to acquire an additional 23 percent.

In January 2001, MarkWest acquired additional natural gas production properties
and gathering systems in New Mexico's San Juan Basin for $5.625 million. The
properties cover 4,800 acres and 40 producing gas wells containing 3.9 Bcf of
proved developed reserves and 3.0 Bcf of proved, undeveloped reserves, net to
MarkWest. The purchase also includes 11 miles of gathering pipelines. MarkWest
is the operator of both the production and gathering systems, with initial
production of 1,200 thousand cubic feet per day (Mcfd) net to MarkWest.

Corporate

In May 2000, MarkWest began trading under a new ticker symbol-MWP-on the
American Stock Exchange.

                                       4
<PAGE>

In June 2000, MarkWest expanded its credit facility from $50,000,000 to
$65,000,000, added a third bank and extended its term by one year to December
31, 2006. This larger credit facility gives the company greater financial
flexibility to make acquisitions and develop new projects in the growing natural
gas industry.

GATHERING, PROCESSING AND MARKETING

APPALACHIA

The Company owns and operates in Appalachia five gas processing facilities, one
fractionation plant, an NGL pipeline and three propane terminals. Certain
information concerning the Appalachian assets is summarized in the following
tables:

<TABLE>
<CAPTION>
                                                                                                       For the Year Ended
                                                                 Year                                   December 31, 2000
                                                               Acquired                        -----------------------------------
                                                               or Placed                           Gas             NGL Production
                                                                 into       Throughput         Throughput            Throughput
      Plant Facilities                      Location            Service      Capacity            (Mcfd)              (Gal/Year)
------------------------------          -----------------      ---------   -------------       ----------          --------------
<S>                                     <C>                    <C>         <C>                 <C>                 <C>
Boldman Extraction Plant (1)            Pike County, KY          1991        70,000 Mcfd         50,000               12,797,000
Cobb Extraction Plant (2)               Kanawha County,WV        2000        35,000 Mcfd         27,000               19,747,000
Kenova Extraction Plant                 Wayne County, WV         1996       120,000 Mcfd        120,000               81,186,000
Kermit Dewpoint Control Plant           Mingo County, WV         2001        39,000 Mcfd          N/A                    N/A
Maytown Extraction Plant (3)            Floyd County, KY         2000        55,000 Mcfd         39,000               26,977,000
Siloam Fractionation Plant (4)          South Shore, KY          1988      600,000 Gal/d          N/A                148,082,000

</TABLE>

<TABLE>
<CAPTION>
                                                                 Year
                                                               Acquired                                                Sales for the
                                                               or Placed                  Throughput      Storage       Year Ended
         Storage and                                             into      Length in       Capacity       Capacity      December 31,
    Transmission Facilities                Location             Service      Miles         (Gal/d)         (Gal)        2000(Gal)(4)
-------------------------------         -------------------    ---------   ---------      ----------     ----------    -------------
<S>                                     <C>                    <C>         <C>            <C>            <C>           <C>
Siloam Fractionation Storage            South Shore, KY          1988          N/A           N/A         14,000,000    153,000,000
Terminal and Storage                    Lynchburg, VA            1999          N/A           N/A            270,000     10,692,000
Terminal and Storage                    Church Hill, TN          1995          N/A           N/A            240,000      3,822,000
Terminal and Storage                    Lordstown, OH            2000          N/A           N/A             80,000      5,500,000
Kenova to Siloam pipeline               Wayne County, WV         1988         38.5         831,000           N/A           N/A
                                        to South Shore, KY
Maytown to Kenova pipeline (5)          Lincoln County to        2000        140.0         160,000           N/A           N/A
                                        Wayne County, WV
</TABLE>

(1)  MarkWest assumed operations effective February 1, 2000. Previously, Boldman
     was leased to and operated by a third party.

(2)  Cobb was acquired March 1, 2000. Cobb was originally placed in service in
     1968 and its extracted NGLs have historically been fractionated at Siloam.

(3)  Maytown was placed into service in February 2000. Maytown can be expanded
     to 75,000 Mcfd for a modest amount of capital.

(4)  Includes fractionation of NGLs extracted at Kenova, Boldman, Cobb and
     Maytown listed above.

(5)  A portion of the pipeline is leased from a third party.

The Company's Appalachian operations are in the midst of a sizable expansion,
growing production from 310,000 gallons per day in 1999 to 550,000 gallons per
day by mid-2001. Production for 2000 was 405,000 gallons per day. See
SIGNIFICANT 2000 AND 2001 DEVELOPMENTS earlier in this section for further
information.

The Company believes this region has favorable supply and demand
characteristics. Appalachia is geographically situated between the TET pipeline
to the north and the Dixie pipeline to the south. The historical demand for NGL
products in Appalachia has exceeded local production and the capacity of these
two lines during peak winter periods. This factor has enabled NGL suppliers in
Appalachia (principally MarkWest, Marathon Ashland Petroleum LLC and CNG
Transmission Corporation) to price their products (particularly propane) at a
premium to Gulf Coast spot prices, especially during winter high demand periods.

There are approximately 11,000 wells behind the Company's NGL extraction plants
in Appalachia, with a potential for producers to drill up to another 20,000 to
50,000 infill wells. Typical wells in this area have long-lived reserves and
modest decline rates. This

                                       5
<PAGE>

producing basin is one of the country's oldest, but is still one of the most
prolific. The growth in production drilling can be attributed to the recently
higher gas prices in an area close to the high-demand northeast U.S., improved
drilling technologies, and cost reductions, all of which add up to improved
economic returns for producers.

The Kenova, Boldman, Cobb, Maytown and Kermit plants extract liquids from
natural gas for further separation at the Company's Siloam fractionator. All of
the NGLs recovered at the Kenova, Maytown and Boldman plants-beginning February
2000, Boldman NGLs are transported to Maytown via tanker trucks-are sent to
Siloam via pipeline. Cobb and Kermit liquids are transported to Siloam via
tanker trucks. At the Company's Siloam fractionation plant, extracted NGLs are
separated into NGL products, including propane, isobutane, normal butane and
natural gasoline. In addition to processing and NGL marketing, the Company
engages in terminaling and storage of NGLs in a number of NGL storage complexes
in the central and eastern United States and owns and operates propane terminals
in Virginia, Tennessee and Ohio.

MarkWest has contracted with producers for the exclusive right to process the
producers' hydrocarbon-rich gas currently delivered into producer-owned and
Columbia-owned transmission pipelines upstream of the Company's plants under
long term contracts. MarkWest also has long term operating agreements with
Columbia.

The Company currently processes natural gas under contracts containing both
keep-whole and fee components. In keep-whole arrangements, the Company's
principal cost is the reimbursement to the natural gas producers for the Btus
extracted from the gas stream in the form of liquids or consumed as fuel during
processing. In such cases, the Company creates operating margins by maximizing
the value of the NGLs extracted from the natural gas stream and minimizing the
cost of replacement Btus. While the Company maintains programs to minimize the
cost to deliver the replacement Btus to the natural gas supplier, the Company's
margins under keep-whole contracts can be negatively affected by either
decreases in NGL prices or increases in prices of replacement natural gas-See
SIGNIFICANT 2000 AND 2001 DEVELOPMENTS above and ITEM 3 - LEGAL PROCEEDINGS.
Processing contracts with producers also contain a fee component under which the
producers pay MarkWest a fee to process their gas and provide a portion of their
gas for fuel. The fee may be a per unit of throughput charge or a percentage of
the resulting NGL sales ("percent-of-proceeds") or some combination of both.
Substantially all of the Company's fractionation services in Appalachia
historically have been provided under keep-whole contracts. The contract for
processing services at the new Maytown plant contains fee and
percent-of-proceeds components.

The Company attempts to maximize the value of its NGL output by marketing
directly to distributors, resellers, blenders, refiners and petrochemical
companies. The Company minimizes the use of third-party brokers and instead
supports a direct marketing staff focused on multistate and independent dealers.
Additionally, the Company uses its own trailer and railcar fleet, as well as its
own terminals and owned and leased storage facilities, to enhance supply
reliability to its customers. All of these efforts have allowed the Company to
maintain premium pricing for the majority of its NGL products compared to Gulf
Coast spot prices. The Company's sales of NGLs are based on spot prices at the
time the NGLs are sold or are hedged. Spot market prices are based upon prices
and volumes negotiated for short terms, typically 30 days. As market conditions
permit, the Company has increased its hedging activities as described in Note 7,
COMMODITY PRICE RISK MANAGEMENT, in the Notes to the Consolidated Financial
Statements in Item 8 of this Form 10-K.

Historically, the majority of the Company's operating income has been derived
from gathering, processing and marketing services in Appalachia. Revenues from
the sale of Appalachian NGLs represented 54 percent, 52 percent, and 70 percent
of gathering, processing and marketing revenues for the years ended December 31,
2000, 1999, and 1998, respectively. In 1998, the Company started a natural gas
marketing group to provide, primarily in Appalachia, more services to natural
gas producers, source new gas for the Company's facilities, minimize its
replacement Btu cost, and assist with its business development efforts. The
Company's natural gas marketing activities are fundamentally high volume, low
margin transactions executed in support of MarkWest's processing business.
Consequently, an increasing percentage of the Company's overall revenues stem
from gas marketing. For the years ended December 31, 2000, 1999, and 1998, 41
percent, 32 percent, and 9 percent, respectively, of gathering, processing and
marketing revenue stemmed from gas marketing.

                                       6
<PAGE>

MICHIGAN

Certain information concerning the Company's Michigan assets is summarized in
the following table:

<TABLE>
<CAPTION>
                                                                                            For the Year Ended
                                                         Year                               December 31, 2000
                                                       Acquired                      -----------------------------
                                                       or Placed      Throughput        Gas         NGL Production
                                                         into          Capacity      Throughput      Throughput
      Facilities                   Location            Service          (Mcfd)         (Mcfd)        (Gal/Year)
--------------------------    -------------------      ---------      ----------     ----------     --------------
<S>                           <C>                      <C>            <C>            <C>            <C>
90-mile sour gas gathering    Manistee, Mason and      1996 (1)         35,000         11,000            N/A
pipeline                      Oceana Counties, MI

Fisk Gas Plant                Manistee County, MI      1998             35,000         11,000         9,200,000
</TABLE>

(1)  Extended from 31 miles in 1996 to 63 miles in 1997 and 90 miles in 1998.

The Company's operations in western Michigan consist of a pipeline and
processing plant. The Company's gas gathering pipeline gathers and transports
sour gas to a treatment plant, used to remove sulfur, owned and operated by a
third party. MarkWest's Fisk processing plant is located adjacent to the third
party's treating plant. The Fisk plant processes all of the natural gas gathered
by the pipeline and treated by the third party's treating plant, producing
propane and other liquid products. The plant also conditions the residue gas
such that it can be sold directly into the Michigan Consolidated Gas Company dry
distribution system serving western Michigan.

The Company currently processes natural gas in western Michigan under contracts
containing both fee and percent-of-proceeds components. The processing contracts
with producers contain a fee component under which the producers pay MarkWest a
fee to transport and treat their gas. Under the percent-of-proceeds component,
the Company retains a portion of the NGLs as compensation for the processing
services provided. Operating revenues earned by the Company under
percent-of-proceeds contracts increase proportionately with the price of NGLs
sold. The Company generally sells its propane production as soon as it is
produced. The Company's butane- natural gasoline production is transported
across the state via tanker trucks to the Marysville Fractionator, where it is
separated into NGL products, including isobutane, normal butane and natural
gasoline.

Throughput volumes in western Michigan for 2000 were 11,000 Mcfd, down 38
percent compared to 1999 volumes. New drilling is critical to maintaining and
increasing volumes. Drilling activity in the next few years will determine the
sustainable production level for the project. MarkWest's own exploration efforts
in 2000, along with partners, resulted in 4 dry holes. MarkWest's net interest
in these 4 wells averaged 25 percent. However, litigation surrounding a
third-party shut-in well is nearly settled, which is expected to allow for
connection to MarkWest's system in the first or second quarter 2001. Another
large producer well is expected to be on- stream in the fourth quarter. Last
year volumes averaged 11,000 Mcfd. In 2001, average volumes are expected to be
flat, although volumes are expected to ramp-up near year-end to 14,000 Mcfd.

MarkWest has exclusive gathering, treatment and processing agreements with
certain producers. Expected natural gas streams dedicated under these agreements
will primarily be produced from an extension of the Northern Niagaran Reef trend
in western Michigan. To date, over 2.5 trillion cubic feet equivalent of natural
gas has been produced from the Northern Niagaran Reef trend. Substantially all
of the natural gas produced from the western region of this trend, however, is
sour. In the past, while several successful large wells were developed in the
region, the natural gas producers lacked adequate gathering and treatment
facilities for sour gas, and development of the trend stopped in northern
Manistee County. However, with the Company's expanded infrastructure of the sour
gas pipeline, treatment and processing facilities and increased capacity, the
Company believes there could continue to be increased development in the region.
In addition, the Company believes that improvements in seismic technology may
increase exploration and production efforts, as well as drilling success rates.

EXPLORATION AND PRODUCTION

RESERVES

Cawley, Gillespie & Associates, Inc., an independent reservoir engineer, has
reviewed MarkWest's estimates of proved reserves, projected future production
and estimated future net revenues from production of proved reserves. The
estimates were based upon a review of production histories and other geologic,
economic, ownership and engineering data provided by or available to the
Company.

                                       7
<PAGE>

Proved reserves at year-end 2000 were 35 Bcf of natural gas compared to 33 Bcf
at year-end 1999. The SEC pre-tax net present value of the proved reserves at
year end 2000, discounted at 10 percent, was $98.0 million compared to $16.1
million reported at year-end 1999. Reserve values were calculated according to
SEC guidelines based on constant prices and costs using year-end NYMEX Henry Hub
spot market index of $9.52 per mmbtu adjusted to El Paso/ San Juan index of
$8.56 per Mcf for 2000 and $2.32 per mmbtu and $2.30 per Mcf, respectively for
1999, adjusted for price hedges. As a sensitivity analysis MarkWest also
evaluated its reserves based on an assumed El Paso/San Juan index price of $3.75
per Mcf, with prices and costs held constant. In this analysis, the pre-tax net
present value of the reserves would have been approximately $37.4 million.
Reserve additions from all sources during 2000 (excluding production and sales)
amounted to 3.7 million Bcf.

To accomplish uniformity in the reporting of reserves for comparison purposes,
the SEC requires that the pre-tax PV 10 of future net revenues be calculated
using a spot year-end pricing and costs, with no future escalation of these
factors. Because these assumptions are not intended to be predictions of future
commodity prices or costs, the calculated values are not intended to be
indicative of the market value of these assets. The alternative analysis of the
pre-tax PV 10 of future net revenues is presented above for comparative purposes
only, and is not intended to represent the Company's estimate of future prices
or the market value of these assets.

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

See related information in NOTE 15, SUPPLEMENTAL INFORMATION ON OIL AND GAS
PRODUCING ACTIVITIES.

ROCKY MOUNTAINS

MarkWest has focused its exploration and production business in Rocky Mountain
coal seam natural gas development-primarily in the San Juan Basin. In 2000,
nearly $1.8 million was spent, primarily in the fourth quarter, on high-return
workover activities on company properties to improve production. During the
second quarter, 2000, MarkWest sold its interest in a non-core property for
$350,000. Net natural gas sold for the year averaged 3,300 Mcfd, up 21 percent
over the prior year. This increase reflects the benefit from higher production
and the benefit realized from the 2000 capital program.

In January 2001, the acquisition of additional coal bed methane properties and
gathering systems in New Mexico's San Juan Basin added another 1,200 Mcfd of
production. This acquisition along with our 2001 capital expenditure program of
$ 4.0 million, is expected to increase our year-end 2001 production exit rate to
more than 6,800 Mcfd.

MICHIGAN

In eastern Michigan, the Company contracted with a producer to provide gas
processing services for a long-dormant sour gas formation. MarkWest also has a
25 percent working interest in the field. In the first phase of the project,
completed in third quarter 2000, MarkWest has successfully recompleted the Sims
1-7 well, constructed a well facility, modified an existing gas plant and
constructed a pipeline to bring an existing well into production from this
formation. This well is producing 2,000 Mcfd. The second phase of the project is
expected to begin in 2001 and will involve bringing another three to four wells
into production and constructing additional processing facilities. Prior to the
Sims 1-7, these wells have never produced from this formation due to the lack of
infrastructure. Initial results look positive and could lead to significant
additional investment in the project. Management believes the project has the
potential to grow into a significant contributor to MarkWest.

SEASONALITY

A substantial portion of the Company's revenues and, as a result, its gross
margins, remains dependent upon the sales price of NGLs, particularly propane,
which fluctuates 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, the
Company recognizes a substantial portion of its annual income during the first
and fourth quarters of the year. Specifically, this seasonality occurs in the
Company's gathering, processing and marketing segment.

                                       8
<PAGE>

COMPETITION

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

The Company's principal competitors include major integrated oil and gas
companies, major interstate pipeline companies, national and local gas
gatherers, NGL processing companies, brokers, marketers and distributors of
varying sizes, financial resources and experience. Many of the Company's
competitors, such as major oil and gas and pipeline companies, have capital
resources and control supplies of natural gas substantially greater than that of
the Company. Smaller local distributors may enjoy a marketing advantage in their
immediate service areas. Drilling activity behind the Company's systems varies
with industry conditions, commodity prices, and effectively competes for capital
with producers' other drilling opportunities.

In the exploration and production segment, the Company faces competition in the
acquisition of leases and producing properties. Competition comes in the form of
other companies with existing operations in the Company's areas of focus as well
as those companies wishing to buy properties as an entry strategy into such
areas. Competitors range in size from small independent operators to large
integrated oil companies. The Company believes it enjoys certain competitive
advantages by virtue of its area knowledge and existing field operating
infrastructure, making it a logical buyer for certain properties.

OPERATIONAL RISKS AND INSURANCE

The Company's operations are subject to the usual hazards incident to the
exploration for and production, gathering, transmission, processing and storage
of natural gas and 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.

The Company maintains general public liability, property and business
interruption insurance in amounts that it considers to be adequate for such
risks. Such insurance is subject to deductibles that the Company considers
reasonable and not excessive. Consistent with insurance coverage generally
available to the industry, the Company's insurance policies provide coverage for
losses or liabilities related to sudden occurrences of pollution or other
environmental damage.

The occurrence of a significant event not fully insured or indemnified against,
and/or the failure of a party to meet its indemnification obligations, could
materially and adversely affect the Company's operations and financial
condition. Moreover, no assurance can be given that the Company will be able to
maintain adequate insurance in the future at rates it considers reasonable. To
date, however, the Company has experienced no material uninsured losses or any
difficulty in acquiring insurance coverage in amounts it believes to be
adequate.

GOVERNMENT REGULATION

In the Michigan area of the gathering, processing and marketing segment, the
Company owns and operates a gathering pipeline in conjunction with its
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. The Company conducts 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 Company's 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 the Company's systems or
which the Company can produce from its wells. They also substantially affect the
cost and profitability of conducting natural gas exploration and production
activities.

                                       9
<PAGE>

ENVIRONMENTAL MATTERS

The Company is subject to environmental risks normally incident to its
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. The following is not intended to constitute a complete discussion of the
various federal, state and local statutes, rules, regulations, or orders to
which the Company's operations may be subject. For example, the Company, without
regard to fault, could incur liability under the Comprehensive Environmental
Response, Compensation, and Liability Act of 1980, as amended (also known as the
"Superfund" law), 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.

The Company's 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 its 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 a permit or other authorization before certain
activities may be conducted by the Company and include fines and penalties for
non-compliance. Further, these rules may limit or prohibit activities within
wilderness areas, wetlands, and areas providing habitat for certain species or
other protected areas. The Company is also subject to other federal, state and
local laws covering the handling, storage or discharge of materials used by the
Company. The Company believes that it is in material compliance with all
applicable laws and regulations.

EMPLOYEES

As of December 31, 2000, the Company had 122 employees. Fourteen employees at
the Company's Siloam fractionation facility in South Shore, Kentucky, are
represented by the Paper, Allied Industrial, Chemical, and Energy Workers
International Union Local 5-0372. The Company's collective bargaining agreement
with this Union expired on April 30, 2000; new contract negotiations continue.
The agreement covered only hourly, non- supervisory employees. The Company
considers labor relations to be satisfactory at this time.

FORWARD-LOOKING INFORMATION

This Annual Report on Form 10-K contains statements which, to the extent that
they are not recitations of historical fact, constitute "forward-looking
statements" within the meaning of Section 27A of the Securities Act of 1933, as
amended, ("Section 27A") and Section 21E of the Securities and Exchange Act of
1934, as amended, ("Section 21E") including statements with respect to the
outcome of the pending litigation matters and contract negotiations. All
forward-looking statements involve risks and uncertainties. The forward-looking
statements in this document are intended to be subject to the safe harbor
protection provided by Sections 27A and 21E. Factors that most typically impact
MarkWest's operating results and financial condition include: (i) changes in
general economic conditions in regions in which the Company's products are
located; (ii) the availability and prices of NGL and competing commodities;
(iii) the availability and prices of raw natural gas supply; (iv) the ability of
the Company to negotiate favorable marketing agreements; (v) the risks that
third party or Company natural gas exploration and production activities will
not occur or be successful; (vi) the Company's dependence on certain significant
customers, producers, gatherers, treaters, and transporters of natural gas;
(vii) competition from other NGL processors, including major energy companies;
(viii) the Company's ability to identify and consummate grass roots projects or
acquisitions complementary to its business; (ix) winter weather conditions; and
(x) intermediate or final decisions in the pending litigation, and the relative
positions of the parties in the negotiation of new agreements. Forward-looking
statements involve many uncertainties that are beyond the Company's ability to
control and in many cases the Company cannot predict what factors would cause
actual results to differ materially from those indicated by the forward-looking
statements.

ITEM 3. LEGAL PROCEEDINGS

As the Company reported in a current report on Form 8-K , dated February 22,
2001, three complaints have been filed against it in the Circuit Court of Wayne
County, West Virginia, by Columbia Gas Transmission Corporation and Columbia
Natural Resources, Inc.; Equitable Production Company and Equitable Energy LLC;
and Cobra Petroleum Production Company et al. These complaints each allege
breach of contract and seek various forms of relief (including injunctive
relief) and damages.

Current and futures prices for natural gas have risen dramatically, and prices
for natural gas liquids ("NGLs") (propane, butane, etc.) have stayed essentially
flat. A large portion of MarkWest's processing services for gas producers in
Appalachia involves extracting

                                       10
<PAGE>

NGLs from inlet gas streams and replacing the equivalent heat content with dry
natural gas purchased in the spot or forward markets. This part of the Company's
operating margin depends on a positive spread between NGL prices and natural gas
costs. When feasible, the Company has hedged a substantial portion of its
natural gas redelivery obligation. Effective February 1, 2001, the Company
provided producers with an alternative processing contract that provides for
additional compensation when processing margins are low and reduced compensation
when these margins are high. To date, about 65 producers (accounting for a
minority share of the volume) out of approximately 325 have agreed to the new
contract. If producers elect to remain with the existing contract, the Company
has stated it will return the replacement natural gas at a later date as it
believes is permitted under the existing contract such that the Company can earn
a reasonable fee for its services. The complaints allege this procedure for the
existing contracts constitutes a breach. The parties have agreed to a temporary
standstill to the litigation and are currently negotiating a resolution to this
dispute. There can be no assurance that these negotiations will be successful or
that the outcome of the litigation or the settlement discussions will be
favorable to the Company.

These high natural gas price conditions, of course, are not an isolated
situation with MarkWest-nationwide, producers and gas processors are
renegotiating their processing agreements for this reason.

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, 2000.


                                     PART II

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

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

As of December 31, 2000, there were 8,561,206 shares of common stock outstanding
held by approximately 600 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.

<TABLE>
<CAPTION>
                                         2000                   1999
                                   ------------------      ---------------
                                    HIGH        LOW         HIGH      LOW
                                   ------      ------      ------     ----
<S>                                <C>         <C>         <C>       <C>
     First Quarter ......           6.921       6.743       9.250     5.75
     Second Quarter .....           8.432       8.230      11.375     7.00
     Third Quarter ......           8.869       8.688       8.875     5.00
     Fourth Quarter .....          11.705      11.498       7.875     4.75

</TABLE>

The Company has paid no dividends on the common stock and anticipates that, for
the foreseeable future, it will continue to retain earnings for use in the
operation of its business. Payment of cash dividends in the future will depend
upon the Company's 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 the Company's Board of Directors.

                                       11
<PAGE>

ITEM 6. SELECTED FINANCIAL DATA

The selected consolidated statement of operations and balance sheet data for the
years ended December 31, 2000, 1999, and 1998, and as of December 31, 2000, and
1999, are derived from, and are qualified by reference to, audited consolidated
financial statements of the Company 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, 1997 and 1996, and as of December 31,
1997 and 1996, have been derived from audited financial statements not included
in this Form 10-K. The selected consolidated financial information set forth
below should be read in conjunction with Item 7 - Management's Discussions and
Analysis of Financial Condition and Results of Operations and the Company's
Consolidated Financial Statements and related notes thereto included in this
Form 10-K.

<TABLE>
<CAPTION>
                                                                             Year Ended December 31,
                                                ------------------------------------------------------------------------------
                                                    2000            1999            1998             1997            1996
                                                -------------   -------------   -------------    -------------   -------------
                                                         (in thousands, except per share amounts and operating data)
<S>                                             <C>             <C>             <C>              <C>             <C>
STATEMENT OF OPERATIONS:
Revenues (1) ................................   $     221,554   $     107,010   $      64,605    $      79,714   $      71,449
Cost of sales ...............................         173,281          77,314          43,866           46,545          41,594
Operating expenses ..........................          17,339          12,657          10,785           11,286           7,597
Cash operating margin (2) ...................          30,934          17,039           9,954           21,883          22,258
General and administrative expenses .........           8,761           6,986           5,319            6,651           4,753
Depreciation, depletion and amortization ....           6,314           5,070           4,594            3,246           2,910
Income from operations ......................          15,859           4,983              41           11,986          14,595
Net income (loss) (3), (4) ..................           8,878           2,823          (1,211)           7,847           7,769
Basic earnings per share (3), (4), (5) ......            1.05            0.33           (0.14)            0.92            1.21
Earnings per share assuming
   dilution (3), (4), (5) ...................   $        1.05   $        0.33   $       (0.14)   $        0.91   $        1.20
Weighted average shares
   outstanding (6) ..........................           8,452           8,475           8,490            8,485           6,415
   assuming dilution (6) ....................           8,492           8,481           8,490            8,614           6,481

CASH FLOW DATA:
Cash flows from operating activities,
   before working capital changes ...........   $      17,259   $       6,393   $       4,795    $      12,650   $      14,702
Capital and acquisition expenditures ........   $      18,765   $      17,898   $      15,890    $      30,329   $      17,516

OTHER FINANCIAL DATA:
EBITDA (7) ..................................   $      22,089   $       9,777   $       4,511    $      15,808   $      18,568

BALANCE SHEET DATA
(AS OF DECEMBER 31):
Working capital (8) .........................   $      15,148   $      11,511   $      11,463    $      14,603   $      11,896
Property and equipment, gross ...............         128,052         115,100         102,931           81,269          60,456
Property and equipment, net .................         100,219          92,311          83,322           65,830          48,140
Total assets ................................         147,287         119,243         103,631           98,657          78,254
Long-term debt ..............................          43,000          44,035          38,597           33,931          11,257
Stockholders' equity ........................   $      61,594   $      52,719   $      50,035    $      51,548   $      43,664
</TABLE>

                                       12
<PAGE>

<TABLE>
<CAPTION>
                                                                             Year Ended December 31,
                                                ------------------------------------------------------------------------------
                                                    2000            1999            1998             1997            1996
                                                -------------   -------------   -------------    -------------   -------------
<S>                                             <C>             <C>             <C>              <C>             <C>
OPERATING DATA
GATHERING, PROCESSING AND MARKETING
Appalachia:
   NGL production--Siloam plant (gallons) ...     148,100,000     113,000,000     102,900,000      102,500,000      94,900,000
   NGL sales--Siloam plant (gallons) ........     153,000,000     115,800,000     100,900,000      103,400,000      94,600,000
Michigan:(9)
   Pipeline throughput (Mcfd) ...............          11,000          17,800          16,000            8,900           4,800
   NGL sales (gallons) ......................       9,200,000      13,500,000      10,600,000               --              --
EXPLORATION AND PRODUCTION
   Natural gas produced (Mcfd) ..............           3,800           2,500           1,900            1,400             700
</TABLE>

------------
(1)  Includes gas marketing revenues of $89,700, $34,100 and $5,600 for the
     years ended December 31, 2000, 1999 and 1998, respectively. The Company's
     gas marketing business originated in 1998. Gas marketing activities are low
     margin; these activities are done in support of MarkWest's processing
     business.

(2)  Includes gathering, processing, and marketing revenue; oil and gas revenue;
     cost of sales; and operating expenses.

(3)  In 2000, includes $1,000 gain ($620, or $0.07 per share, after-tax) from
     the sale of an asset.

(4)  In 1999, includes $2,509 gain ($1,566, or $0.18 per share, after-tax) from
     the sale of an asset.

(5)  Prior to October 7, 1996, the Company was organized as a
     partnership-MarkWest Hydrocarbon Partners, Ltd. ("MarkWest
     Partnership")-and consequently, was not subject to income tax. Effective
     October 7, 1996, the Company reorganized (the "Reorganization"), and the
     existing general and limited partners exchanged 100 percent of their
     interests in MarkWest Partnership for 5,725,000 common shares of the
     Company. Pro forma information has been presented for purposes of
     comparability as if the Company had been a taxable entity for all periods
     presented:

<TABLE>
<CAPTION>
                                Year Ended December 31, 1996
          --------------------------------------------------------------------
<S>                                                                    <C>
          Historical income before income taxes .................      $14,760
          Pro forma provision for income taxes ..................        5,609
          Pro forma net income ..................................        9,151
          Pro forma basic earnings per share ....................         1.16
          Pro forma earnings per share assuming dilution ........      $  1.15
          Pro forma weighted average shares outstanding (a) .....        7,908
</TABLE>

     (a)  Pro forma weighted average shares outstanding represents the weighted
          average of, for the period prior to the initial public offering (the
          "Offering"), the number of common shares issued in the Reorganization
          plus the number of shares issued in the Offering for which the net
          proceeds were used to repay outstanding indebtedness and, for the
          period subsequent to the Offering, the total number of common shares
          outstanding.

(6)  Weighted average shares outstanding for the year ended December 31, 1996,
     represents the weighted average of, for the period prior to the Company's
     initial public offering, the number of common shares issued in the
     Reorganization and, for the period subsequent to the Offering, the total
     number of common shares outstanding.

(7)  Earnings (loss) before interest income; interest expense; income taxes;
     depreciation, depletion, and amortization; and gain on sale of West Memphis
     terminal and ticker symbol.

(8)  Includes cash of $934; $1,356; $2,055; $1,364; and $4,401, respectively.

(9)  2000, 1999, 1998 and 1997 results reflect the Company's acquisition of the
     remaining 40 percent interest of the Michigan operations in November 1997.
     Prior to November 1997, MarkWest owned 60 percent of the Michigan
     operations. Pipeline operations commenced in 1996; the Fisk processing
     plant commenced operations in 1998.

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

The following analysis should be read in conjunction with Item 6 - Selected
Financial Data and the Company's Consolidated Financial Statements included in
this Form 10-K.

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2000, COMPARED TO YEAR ENDED DECEMBER 31, 1999

OVERVIEW

For the year ended December 31, 2000, net income was $8.9 million, or $1.05 per
share, up $6.1 million or $0.72 per share from 1999. Excluding gains on asset
sales in both periods, income was $8.3 million, or $0.97 per share, for the year
ended December 31,

                                       13
<PAGE>

2000 compared to a net income of $1.3 million, or $0.15 per share, for the prior
year. EBITDA was $22.1 million for the year ended December 31, 2000, compared to
$9.8 million for the year ended December 31, 1999.

Results for the year ended December 31, 2000, were significantly impacted by the
record NGL production and sales volumes in the gathering, processing and
marketing segment. The increased volumes are due to increased gas production
behind the company's facilities, gas extraction and fractionator plant
expansions and additional marketing terminals in the Appalachia area. Decreased
western Michigan throughput and sales volume were partially offset by higher NGL
prices.

Natural gas production in the Exploration and Production segment also positively
impacted results for the year ended December 31, 2000. Daily production, net to
MarkWest interest was 3,800 thousand cubic feet (mcf) per day for 2000, a 52
percent increase over 1999 production levels.

For the year ended December 31, 2000, the Company expected increases in
operating, general and administrative, depreciation and interest expenses. These
increases were due to the Company's Appalachia expansion program.

GATHERING, PROCESSING AND MARKETING REVENUE

MarkWest is paid for its processing services in Appalachia through sales of
liquids extracted and fees for units of throughput. Recent sales volumes of
liquids at the Company's Siloam, Kentucky, fractionation facility were a record
153 million gallons compared to 116 million gallons for 1999, a 32 percent
increase. Higher prices and increased volumes at the terminals also benefited
revenues.

For the year ended December 31, 2000, gas marketing revenue was $90.0 million
compared to $34.0 million for the year ended December 31, 1999. The natural gas
marketing activities are high volume, low margin transactions supporting
MarkWest's processing business.

In western Michigan, volumes were 11,000 Mcfd for the year ended December 31,
2000 compared to 17,800 Mcfd for the year ended December 31, 1999. This decline
was partially offset by higher NGL prices.

EXPLORATION AND PRODUCTION REVENUE

Natural gas sold during the year ended December 31, 2000 totaled 3,800 Mcfd-a 52
percent increase over the 2,500 Mcfd produced and sold during the year ended
December 31, 1999. Production has increased because of the Company's capital
program.

COSTS AND EXPENSES

COST OF SALES. Cost of sales for the year ended December 31, 2000 increased $96
million or 124 percent compared to the year ended December 31, 1999. Similarly,
sales increased by nearly 110 percent from 1999 to 2000. The Company's
replacement feedstock in Appalachia increased $21 million as a result of
increased volumes and unit costs. In addition, the cost of sales for natural gas
marketing increased $55 million due to the increased volumes. Combined with a
corresponding increase in gas marketing sales, the 2000 gross margin from gas
marketing increased $0.3 million compared to 1999. The natural gas marketing
activities generate low margins; these activities are executed in support of
MarkWest's processing business. The cost and volume increases at the Company's
Appalachian terminals and Michigan facilities increased cost of sales by $20
million.

OPERATING EXPENSES. Operating expenses increased $4.7 million or 37 percent for
the year ended December 31, 2000 compared to the year ended December 31, 1999.
The increase is primarily attributable to operating costs associated with
incremental facilities added in Appalachia since third quarter 1999: the
Lynchburg and Lordstown terminals; the Maytown, Boldman and Cobb extraction
facilities and related pipeline; and the expanded Siloam fractionation plant.
Higher natural gas costs in 2000 also impacted fuel costs at its plants.
Finally, increased costs to achieve increased natural gas production were
realized in MarkWest's exploration and production segment.

GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses
increased $1.8 million or 25 percent primarily in support of the additional and
expanded Appalachia facilities previously mentioned and rent for office space;
the Company sold its corporate headquarters and leased back its office space
commencing in February 2000.

DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization increased for the year ended December 31, 2000 as a result of the
completion of the Phase I expansion in Appalachia in the first quarter of 2000.

                                       14
<PAGE>

YEAR ENDED DECEMBER 31, 1999, COMPARED TO YEAR ENDED DECEMBER 31, 1998

OVERVIEW

For the year ended December 31, 1999, MarkWest reported net income of $2.8
million, or $0.33 per share, a $4.0 million increase in net income over 1998's
net loss of $1.2 million, or $0.14 per share. Aside from the Company's $1.5
million, or $0.18 per share, after-tax gain on the sale of the Company's West
Memphis terminal, record NGL production and sales in Appalachia, coupled with
improving Appalachian processing margins in the Company's gathering, processing
and marketing segment, were the primary reasons behind the Company's return to
profitability in 1999. MarkWest sold 115.8 million gallons of NGLs in 1999, a 15
percent increase over 1998 levels, as gas production increased behind the
Company's facilities. Although Appalachian processing margins were up over 1998,
they were still significantly below the Company's ten-year historical average.
Increased NGL prices contributed to improving margins. Increased profitability
from MarkWest's terminals, due to increased NGL sales prices, and Michigan
operations, due to increased throughput and NGL sales prices, also contributed
in 1999. Expected increases in operating, general and administrative, interest
and depreciation, depletion and amortization expenses occurred.

GATHERING, PROCESSING AND MARKETING REVENUE

Gathering, processing and marketing revenue increased $42.0 million, or 66
percent, for the year ended December 31, 1999, compared to the year ended
December 31, 1998. The revenue increase was principally attributable to a $28.5
million increase in the Company's gas marketing operations. At the Company's
Siloam fractionation facility, higher NGL sales prices and larger volumes of
NGLs marketed contributed to increased 1999 revenues.

EXPLORATION AND PRODUCTION REVENUE

Oil and gas revenue increased $0.5 million for the year ended December 31, 1999,
compared to the year ended December 31, 1998. This increase was primarily
attributable to an increase in gas production from the prior year.

COSTS AND EXPENSES

COST OF SALES. Cost of sales increased $33.5 million, or 76 percent, for the
year ended December 31, 1999, compared to the year ended December 31, 1998. This
increase was primarily caused by a $28.5 million increase in gas marketing
purchases. At the Company's Siloam fractionation facility, both higher natural
gas costs and larger volumes of natural gas purchased contributed to increased
1999 cost of sales.

OPERATING EXPENSES. Operating expenses increased $1.9 million, or 17 percent,
for the year ended December 31, 1999, compared to the year ended December 31,
1998. The increase in operating expenses was principally attributable to four
factors. First, certain expenses increased with volumes in Appalachia, Michigan
and the Rocky Mountains. Second, MarkWest sold and leased back three compressors
at its Kenova processing plant beginning in the third quarter of 1998.
Consequently, 1999 operating expenses include twelve full months of lease
expense whereas the results from the comparable time period in 1998 do not.
Further, these compressors were overhauled in 1999. Third, 1998 operating
expenses were lower due to a sales and use tax refund during that period. Last,
performance-based incentive compensation increased in 1999; MarkWest did not pay
bonuses in 1998 due to the Company's overall net loss.

GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses
increased $1.7 million, or 31 percent, for the year ended December 31, 1999,
compared to the year ended December 31, 1998. This increase is attributable to
increased performance-based incentive compensation (MarkWest did not pay
incentive bonuses in 1998 due to the Company's overall net loss); professional
service fees also increased in 1999 due to the Company's arbitration with
Columbia, now settled; and to increased business development expenditures.

DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization increased $0.5 million, or 10 percent, for the year ended December
31, 1999, compared to the year ended December 31, 1998. This increase was
principally due to the Company's pipeline extension in Michigan placed in
service during mid-1998.

INTEREST EXPENSE. Interest expense increased $0.7 million for the year ended
December 31, 1999, compared to the year ended December 31, 1998, due to
increased average outstanding debt and higher interest rates.

                                       15
<PAGE>

LIQUIDITY AND CAPITAL RESOURCES

The Company's sources of liquidity and capital resources historically have been
internal cash flow and its revolving line of credit. In the first quarter of
2000, these sources were supplemented by proceeds from the sale of the Company's
corporate office building. In the second quarter of 2000, MarkWest increased its
line of credit by $15 million to $65 million.

The following summary table reflects comparative cash flows for the Company for
the three years ended December 31 (in 000's):

<TABLE>
<CAPTION>

                                                                                             2000           1999          1998
                                                                                           --------       --------       --------
<S>                                                                                        <C>            <C>            <C>
Net cash provided by operating activities before
    change in working capital .......................................................      $ 17,259       $  6,393       $  4,795
Net cash provided by (used in) operating activities from change in working capital ..        (3,924)          (253)         3,638
Net cash provided by (used in) investing activities (1) .............................       (12,273)       (11,884)       (11,559)
Net cash provided by (used in) financing activities .................................      $ (1,484)      $  5,045       $  3,817
</TABLE>

(1)  Net of asset sales of $6,492, $6,014 and $4,281, respectively.

CAPITAL INVESTMENT PROGRAM

Investing activities consist primarily of capital and acquisition expenditures
net of asset sales.

The Company's capital expenditures are summarized as follows (in millions):

<TABLE>
<CAPTION>
                                                     For the Year Ended December 31,
                                                     -------------------------------
                                                        2000      1999       1998
                                                      -------    -------    -------
<S>                                                  <C>        <C>        <C>
GATHERING, PROCESSING AND MARKETING
Appalachia
         Phase I expansion .....................      $   4.5    $   9.3    $  --
         Phase II expansion ....................          4.3       --         --
         Marketing assets ......................          3.4        2.1       --
Western Michigan
         Pipeline expansion ....................         --          0.1       10.7
Maintenance capital and other ..................          1.1        1.8        2.2
                                                      -------    -------    -------
         Gathering, processing and marketing ...      $  13.3    $  13.3    $  12.9
                                                      -------    -------    -------
EXPLORATION AND PRODUCTION
Rocky Mountains ................................      $   2.6    $   3.6    $   2.9
Western Michigan ...............................          1.4        0.8        0.1
Eastern Michigan ...............................          1.5        0.2       --
                                                      -------    -------    -------
         Exploration and production ............          5.5        4.6        3.0
                                                      -------    -------    -------
         Total capital expenditures ............      $  18.8    $  17.9    $  15.9
                                                      =======    =======    =======
</TABLE>

Looking ahead, MarkWest forecasts a baseline capital budget of $24.5 million in
2001: in its gathering, processing and marketing segment - $8 million for
completion of Appalachia's Phase II expansion, $2.5 million for marketing
infrastructure expansion and $1.5 million for maintenance capital; in its
exploration and production segment - $5 million for the acquisition of San Juan
Basin properties in January 2001, up to $4 million for infill drilling in the
San Juan Basin and up to $3.5 million for further expansion of the Au Gres,
Michigan property. These latter two expenditures are discretionary and could be
reduced depending on capital availability.

FINANCING FACILITIES

Financing activities consist primarily of net borrowings under the Company's
credit facility. At December 31, 2000, the Company had $65 million of available
credit, of which net debt (debt less cash) of $42.1 million had been utilized,
and working capital of $15.1 million. Depending on the timing and amount of the
Company's future projects beyond the level described above, and the outcome of
the Appalachia producer litigation and negotiations described in SIGNIFICANT
2000 AND 2001 DEVELOPMENTS in ITEMS 1 AND 2 - BUSINESS AND PROPERTIES and ITEM 3
- LEGAL PROCEEDINGS of this Form 10-K, MarkWest may be required to seek
additional sources of

                                       16
<PAGE>

capital. While the Company believes that it will be able to secure additional
financing on terms acceptable to the Company, if required, no assurance can be
given that it will be able to do so.

2001 OUTLOOK

In the gathering, processing and marketing segment, the Appalachia Phase II
expansion is expected to add 90,000 gallons per day of NGL production beginning
in the third quarter of 2001, with the expectation therefore that sales volumes
of NGLs from the Siloam fractionator will be approximately 170 million gallons,
up 10 percent from 2000. Michigan natural gas volumes transported and processed
are expected to be flat at approximately 11,000 Mcfd based on resolution in the
first quarter 2001 of third party litigation on several wells and hook up of a
new well by the fourth quarter 2001. As a result of these additions, the year
end flow rate is expected to be about 14,000 Mcfd.

As the Company reported in a current report on Form 8-K date February 22, 2001,
current and futures prices for natural gas have risen dramatically, and prices
for NGLs (propane, butane, etc.) have stayed essentially flat. A large portion,
about 75 percent, of MarkWest's processing services for gas producers in
Appalachia involves extracting NGLs from inlet gas streams and replacing the
equivalent heat content with dry natural gas purchased in the spot or forward
markets. This part of the Company's operating margin depends on a positive
spread between NGL prices and natural gas costs. (However, when feasible, the
Company hedges a portion of this processing margin - for example, as of February
27, 2001, the Company had hedged 17.4 million gallons for 2001 at a margin of
$0.22 per gallon.) Effective February 1, 2001, the Company provided producers
with an alternative processing contract that provides for additional
compensation when processing margins are low and reduced compensation when these
margins are high. To date, approximately 65 producers (accounting for a minority
share of the volume) out of approximately 325 have agreed to the new contract.
If producers elect to remain with the existing contract, the Company has stated
it will return the replacement natural gas at a later date as it believes is
permitted under the existing contract such that the Company can earn a
reasonable fee for its services. See also ITEM 3 - LEGAL PROCEEDINGS of this
Form 10-K. These high natural gas price conditions, of course, are not an
isolated situation with MarkWest - nationwide, producers and gas processors are
renegotiating their processing agreements for this reason.

In the exploration and production segment, volumes produced are expected to
increase over 100 percent to 8,000 Mcfd as a result of a January 2001
acquisition in the San Juan Basin, capital spending in the fourth quarter of
2000 and the full year 2001, startup of the first well in the Au Gres field in
eastern Michigan in the third quarter of 2000, and the expected recompletion of
a second Au Gres well in the first half of 2001. About 60 percent of the 2001
volumes have been hedged at a Henry Hub equivalent price of $3.85 per MMbtu.

Other key expectations for 2001 include: operating costs of $20 million, up from
$17 million in 2000 due to growth in Appalachia processing volumes and higher
per unit fuel costs, and increased natural gas production; general and
administrative expense of $9 million, unchanged from 2000; depreciation,
depletion and amortization expense $7 million, up from 2000's $6.3 million as a
result of capital expenditures; and a tax rate of 39 percent (one-third of which
is current, the balance deferred).

COMMODITY PRICE RISK MANAGEMENT ACTIVITIES

Reference is made to Notes 7 and 8 of the Company's Consolidated Financial
Statements in Item 8 of this Form 10-K.

The Company's hedging strategy limited the Company's after-tax earnings compared
to the situation of not hedging. In the gathering, processing and marketing
segment, net income would have been higher by $1.7 million, $0.9 million and $0
for the years ended December 31, 2000, 1999 and 1998, respectively. This impact
considers only hedges of Appalachia processing margin and does reflect other
decisions made concerning when to buy natural gas or store NGL production for
sale in later months. In the exploration and production segment, without
hedging, net income would have been higher by $0.6 million, $0.1 million and $0,
respectively, for the years ended December 31, 2000, 1999 and 1998.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company faces market risk from commodity price variations, primarily in the
NGLs it sells and in the natural gas it purchases. It also incurs, to a lesser
extent, credit risks and risks related to interest rate variations.

COMMODITY PRICE RISK. In the past, NGL prices and natural gas costs have
fluctuated widely in response to changing market forces. The impacts of these
price fluctuations on earnings from natural gas processing and natural gas
production activities have been significant and have varied from year to year.
The Company typically hedges a portion of its commodity price risk.

Prior to hedging activities, MarkWest's Appalachian operations' cash flow has an
annual sensitivity to NGL prices equal to $1.3 million in pretax income for
every $0.01 per gallon change in NGL prices and an annual sensitivity to natural
gas prices equal to $1.3 million

                                       17
<PAGE>

in pretax income for every $0.10 per MMBtu change in natural gas prices. For
2001, the Company has hedged approximately 13 percent of its Appalachian
keep-whole volumes as of February 27, 2001, reducing the annual sensitivity
accordingly.

With the growth in the Company's exploration and production activities, the
impact of variable natural gas prices on its revenues is increasing, which the
Company mitigates through an extensive hedging program. As of February 27, 2001,
the Company has hedged approximately 53 percent of its expected production for
the year 2001. Accordingly, MarkWest's annual sensitivity to natural gas prices
for 2001 is $0.1 million for each $0.10 per MMBtu change in natural gas prices.

Gains and losses experienced on hedging transactions are generally offset by the
related gains or losses on the sale of the underlying product in the physical
market. See related discussion in Note 7 to the Company's Consolidated Financial
Statements.

CREDIT RISK. The Company is exposed to potential losses as a result of
nonperformance by counterparties pursuant to the terms of their contractual
obligations. The Company maintains credit policies with regard to its
counterparties that management believes 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. The Company also monitors the financial condition of
existing counterparties on an ongoing basis.

INTEREST RATE RISK. The Company is exposed to changes in interest rates,
primarily as a result of its long-term debt with floating interest rates. The
Company may make use of interest rate swap agreements to adjust the ratio of
fixed and floating rates in the debt portfolio, although no such agreements are
currently in place. The impact of a 100 basis point increase in interest rates
on the Company's debt would result in an increase in interest expense and a
decrease in income before taxes of approximately $0.4 million. This amount has
been determined by considering the impact of the hypothetical interest rates on
the Company's variable-rate debt balances as of December 31, 2000.

                                       18
<PAGE>

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


<TABLE>
<CAPTION>
                                                                               Page
                                                                               ----
<S>                                                                            <C>
Report of Independent Accountants .........................................      19

Consolidated Balance Sheet at December 31, 2000 and 1999 ..................      20

Consolidated Statement of Operations for each of the three
     years in the period ended December 31, 2000 ..........................      21


Consolidated Statement of Cash Flows for each of the three
     years in the period ended December 31, 2000 ..........................      22


Consolidated Statement of Changes in Stockholders' Equity
     for each of the three years in the period ended December 31, 2000 ....      23


Notes to Consolidated Financial Statements ................................      24

</TABLE>


                        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, 2000 and 1999, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2000 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.



PricewaterhouseCoopers LLP

Denver, Colorado
February 7, 2001, except for Note 13(b),
as to which the date is March 26, 2001

                                       19
<PAGE>

                           MARKWEST HYDROCARBON, INC.
                           CONSOLIDATED BALANCE SHEET
                          (000s, EXCEPT PER SHARE DATA)

<TABLE>
<CAPTION>
                                                                                       December 31,
                                                                                -------------------------
                                                                                  2000            1999
                                                                                ---------       ---------
<S>                                                                             <C>             <C>
                                     ASSETS
Current assets:
    Cash and cash equivalents ............................................      $     934       $   1,356
    Receivables ..........................................................         36,695          16,360
    Inventories ..........................................................          8,058           6,043
    Prepaid feedstock ....................................................             --           1,895
    Other assets .........................................................            913             327
                                                                                ---------       ---------
          Total current assets ...........................................         46,600          25,981

Property and equipment:
    Gas processing, gathering, storage and marketing equipment ...........         97,311          78,476
    Oil and gas properties and equipment .................................         18,037          14,518
    Land, buildings and other equipment ..................................          6,463          11,409
    Construction in progress .............................................          6,241          10,697
                                                                                ---------       ---------
                                                                                  128,052         115,100
    Less: accumulated depreciation, depletion and amortization ...........        (27,833)        (22,789)
                                                                                ---------       ---------
          Total property and equipment, net ..............................        100,219          92,311

Intangible assets, net of accumulated amortization of
    $708 and $438, respectively ..........................................            468             951
                                                                                ---------       ---------
          Total assets ...................................................      $ 147,287       $ 119,243
                                                                                =========       =========

                      LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
    Accounts payable .....................................................      $  17,713       $  10,031
    Accrued liabilities ..................................................         13,740           4,335
    Current portion of long-term debt ....................................             --             104
                                                                                ---------       ---------
          Total current liabilities ......................................         31,453          14,470

Deferred income taxes ....................................................         11,240           8,019
Long-term debt ...........................................................         43,000          44,035

Commitments and contingencies (see Note 13b) .............................             --              --

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, 8,561,206 and 8,531,206 shares issued, respectively....             86              85
    Additional paid-in capital ...........................................         42,471          42,222
    Retained earnings ....................................................         19,679          10,801
    Treasury stock;  104,093 and 69,504 shares, respectively .............           (642)           (389)
                                                                                ---------       ---------
          Total stockholders' equity .....................................         61,594          52,719
                                                                                ---------       ---------
          Total liabilities and stockholders' equity .....................      $ 147,287       $ 119,243
                                                                                =========       =========

</TABLE>

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

                                       20
<PAGE>

                           MARKWEST HYDROCARBON, INC.
                      CONSOLIDATED STATEMENT OF OPERATIONS
                          (000s, EXCEPT PER SHARE DATA)

<TABLE>
<CAPTION>
                                                                             For the Year Ended December 31,
                                                                        -----------------------------------------
                                                                          2000            1999            1998
                                                                        ---------       ---------       ---------
<S>                                                                     <C>             <C>             <C>
Revenue:
    Gathering, processing and marketing revenue ..................      $ 217,393       $ 105,150       $  63,190
    Exploration and production revenue ...........................          4,161           1,860           1,415
                                                                        ---------       ---------       ---------
               Total revenues ....................................        221,554         107,010          64,605
                                                                        ---------       ---------       ---------
Operating expenses:
    Cost of sales ................................................        173,281          77,314          43,866
    Operating expenses ...........................................         17,339          12,657          10,785
    General and administrative expenses ..........................          8,761           6,986           5,319
    Depreciation, depletion and amortization .....................          6,314           5,070           4,594
                                                                        ---------       ---------       ---------
               Total operating expenses ..........................        205,695         102,027          64,564
                                                                        ---------       ---------       ---------

               Income from operations ............................         15,859           4,983              41
                                                                        ---------       ---------       ---------
Other income and expense:
     Interest income .............................................            101              53             200
     Interest expense ............................................         (3,110)         (2,745)         (2,095)
     Gain on sale of assets ......................................          1,000           2,509              --
     Other income (expense) ......................................            (84)           (276)           (124)
                                                                        ---------       ---------       ---------
               Income (loss) before income taxes .................         13,766           4,524          (1,978)
                                                                        ---------       ---------       ---------
Provision (benefit) for income taxes:
    Current ......................................................          1,666             759          (2,235)
    Deferred .....................................................          3,222             942           1,468
                                                                        ---------       ---------       ---------
               Provision for income taxes ........................          4,888           1,701             767
                                                                        ---------       ---------       ---------
               Net income (loss) .................................      $   8,878       $   2,823       $  (1,211)
                                                                        =========       =========       =========
Basic earnings (loss) per share of common stock ..................      $    1.05       $    0.33       $   (0.14)
                                                                        =========       =========       =========
Earnings (loss) per share assuming dilution ......................      $    1.05       $    0.33       $   (0.14)
                                                                        =========       =========       =========
Weighted average number of outstanding shares of common stock:
               Basic .............................................          8,452           8,475           8,490
                                                                        =========       =========       =========
               Assuming dilution .................................          8,492           8,481           8,490
                                                                        =========       =========       =========
</TABLE>

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

                                       21
<PAGE>

                           MARKWEST HYDROCARBON, INC.
                      CONSOLIDATED STATEMENT OF CASH FLOWS
                                     (000s)

<TABLE>
<CAPTION>
                                                                                    For the Year Ended December 31,
                                                                                 --------------------------------------
                                                                                   2000           1999           1998
                                                                                 --------       --------       --------
<S>                                                                              <C>            <C>            <C>
Cash flows from operating activities:
    Net income (loss) .....................................................      $  8,878       $  2,823       $ (1,211)
    Add income items that do not affect working capital:
        Depreciation, depletion and amortization ..........................         6,314          5,070          4,594
        Deferred income taxes .............................................         3,222            942          1,468
        Gain on sale of assets ............................................        (1,000)        (2,509)            --
        Other .............................................................          (155)            67            (56)
                                                                                 --------       --------       --------
                                                                                   17,259          6,393          4,795
    Adjustments to working capital:
        (Increase) decrease in receivables ................................       (20,335)        (8,622)         2,541
        (Increase) decrease in inventories ................................        (2,015)        (1,460)           558
        (Increase) decrease in prepaid expenses and other assets ..........         1,301          2,787            379
        Increase (decrease) in accounts payable and accrued liabilities ...        17,125          7,042            160
                                                                                 --------       --------       --------
                                                                                   (3,924)          (253)         3,638
               Net cash flow provided by operating activities .............        13,335          6,140          8,433
Cash flows from investing activities:
        Capital expenditures ..............................................       (18,765)       (17,898)       (15,890)
        Proceeds from sale/leaseback transaction ..........................            --             --          4,281
        Proceeds from sale of assets ......................................         6,492          6,014             --
        Change in note receivable and other ...............................            --             --             50
                                                                                 --------       --------       --------
               Net cash used in investing activities ......................       (12,273)       (11,884)       (11,559)
Cash flows from financing activities:
        Proceeds from long-term debt ......................................        55,000         48,056         39,200
        Repayments of long-term debt ......................................       (56,139)       (42,577)       (34,627)
        Debt issuance costs ...............................................          (342)          (295)          (454)
        Exercise of stock options .........................................            38             --             --
        Acquisition of treasury stock .....................................          (251)        (1,035)          (690)
        Reissuance of treasury stock ......................................           210            896            296
        Proceeds from exercise of options and payment on share
            purchase notes ................................................            --             --             92
                                                                                 --------       --------       --------
               Net cash provided by financing activities ..................        (1,484)         5,045          3,817
                                                                                 --------       --------       --------
               Net increase (decrease) in cash and cash equivalents .......          (422)          (699)           691
Cash and cash equivalents at beginning of year ............................         1,356          2,055          1,364
                                                                                 --------       --------       --------
Cash and cash equivalents at end of year ..................................      $    934       $  1,356       $  2,055
                                                                                 ========       ========       ========
</TABLE>

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

                                       22
<PAGE>

                           MARKWEST HYDROCARBON, INC.
                      CONSOLIDATED STATEMENT OF CHANGES IN
                              STOCKHOLDERS' EQUITY
                                     (000s)

<TABLE>
<CAPTION>
                                     SHARES OF      SHARES OF             ADDITIONAL                                TOTAL
                                       COMMON       TREASURY    COMMON     PAID-IN      RETAINED     TREASURY    STOCKHOLDERS'
                                       STOCK         STOCK      STOCK      CAPITAL      EARNINGS      STOCK         EQUITY
                                     ---------      --------   --------   ----------    --------     --------    ------------
<S>                                  <C>            <C>        <C>        <C>           <C>          <C>         <C>
Balance, December 31, 1997 .......       8,520         (28)    $     85    $ 42,729     $  9,189     $   (455)    $ 51,548

Net loss .........................          --          --           --          --       (1,211)          --       (1,211)
Exercise of options ..............          11          --           --          89           --           --           89
Acquisition of treasury stock ....          --         (63)          --          --           --         (690)        (690)
Reissuance of treasury stock .....          --          31           --         (79)          --          375          296
Other ............................          --          --           --         (46)          --           49            3
                                       -------      ------     --------    --------     --------     --------     --------
Balance, December 31, 1998 .......       8,531         (60)    $     85    $ 42,693     $  7,978     $   (721)    $ 50,035

Net income .......................          --          --           --          --        2,823           --        2,823
Acquisition of treasury stock ....          --        (156)          --          --           --       (1,035)      (1,035)
Reissuance of treasury stock .....          --         147           --        (471)          --        1,367          896
                                       -------      ------     --------    --------     --------     --------     --------
Balance, December 31, 1999 .......       8,531         (69)    $     85    $ 42,222     $ 10,801     $   (389)    $ 52,719

Net income .......................          --          --           --          --        8,878           --        8,878
Issuance of common stock .........          30         (30)           1         197           --         (198)          --
Exercise of options ..............          --           5           --          10           --           28           38
Acquisition of treasury stock ....          --         (39)          --          --           --         (251)        (251)
Reissuance of treasury stock .....          --          29           --          42           --          168          210
                                       -------      ------     --------    --------     --------     --------     --------
Balance, December 31, 2000 .......       8,561        (104)    $     86    $ 42,471     $ 19,679     $   (642)    $ 61,594
                                       =======      ======     ========    ========     ========     ========     ========

</TABLE>

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

                                       23
<PAGE>

                           MARKWEST HYDROCARBON, INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. NATURE OF OPERATIONS

MarkWest Hydrocarbon, Inc. ("MarkWest" or the "Company"), provides natural gas
processing and related services. The Company's activities include compression,
gathering, treatment and natural gas liquids ("NGLs") extraction services for
natural gas producers and pipeline companies and fractionation of NGLs into
marketable products. The Company also purchases, stores and markets natural gas
and NGLs and conducts strategic exploration for natural gas sources for its
processing services. The Company's operations are concentrated in three core
areas: the southern Appalachian region of eastern Kentucky, southern West
Virginia, and southern Ohio; Michigan; and the Rocky Mountains.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements include the accounts of the Company and
its wholly owned subsidiaries: MarkWest Resources, Inc.; MarkWest Michigan,
Inc.; Basin Pipeline, LLC; West Shore Processing Company, LLC; and Matrex, LLC.
All significant intercompany accounts and transactions have been eliminated in
consolidation.

CASH AND CASH EQUIVALENTS

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

INVENTORIES

Inventories comprise the following (in 000s):

<TABLE>
<CAPTION>
                                                At December 31,
                                               ------------------
                                                2000        1999
                                               ------      ------
<S>                                            <C>         <C>
     Product inventory ..................      $7,973      $5,629
     Materials and supplies inventory ...          85         414
                                               ------      ------
                                               $8,058      $6,043
                                               ======      ======
</TABLE>

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

PREPAID FEEDSTOCK

Prepaid feedstock consists of natural gas purchased in advance of its actual
use. It is valued using the first-in/first-out method.

PROPERTY AND EQUIPMENT

Property and equipment is recorded at cost. Expenditures that extend the useful
lives of assets are capitalized. Repairs, maintenance and renewals that do not
extend the useful lives of the assets are expensed as incurred. Interest costs
for the construction or development of long-term assets are capitalized and
amortized over the related asset's estimated useful life. Depreciation is
provided principally on the straight-line method over the following estimated
useful lives: plant facilities and pipelines, 20 years; buildings, 40 years;
furniture, leasehold improvements and other, 3 to 10 years.

Oil and gas properties and equipment consist of leasehold costs, producing and
non-producing properties, oil and gas wells, equipment and pipelines. The
Company uses 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, 2000 and 1999,
approximately $0.6 million and $1.2 million of investments in unproved
properties were excluded from amortization.

                                       24
<PAGE>

                           MARKWEST HYDROCARBON, INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 percent discount rate, of the future net revenues from proved
reserves, based on current economics and operating conditions. No impairment
existed during the three years ended December 31, 2000.

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.

INTANGIBLE ASSETS

Intangible assets consist primarily of deferred financing costs that are
amortized over the anticipated term of the associated agreement.

HEDGING ACTIVITIES

The Company limits its exposure to natural gas and propane price fluctuations
related to future purchases and production with futures contracts. These
contracts are accounted for as hedges in accordance with the provisions of
Statement of Financial Accounting Standards ("SFAS") No. 80, ACCOUNTING FOR
FUTURES CONTRACTS. Gains and losses on such hedge contracts are deferred and
included as a component of revenues or cost of sales when the hedged production
is sold. See also Note 8, Adoption of SFAS No. 133.

FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company's 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, 2000 and
1999, 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 RECOGNITION

Revenue for sales or services provided under contractual arrangements, is
recognized at the time the title is transferred or at the time the service is
performed.

INCOME TAXES

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.

CONCENTRATION OF CREDIT RISK

Financial instruments that potentially subject the Company to concentrations of
credit risk consist principally of trade accounts receivable. The trade accounts
receivable risk is limited due to the large number of entities comprising the
Company's customer base and their dispersion across industries and geographic
locations. At December 31, 2000 and 1999, the Company had no significant
concentrations of credit risk.

STOCK COMPENSATION

As permitted under SFAS No. 123, ACCOUNTING FOR STOCK-BASED COMPENSATION, the
Company has elected to continue to measure compensation costs for stock- based
employee compensation plans as prescribed by Accounting Principles Board Opinion
No. 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES. See Note 10 for the applicable
disclosures required by SFAS No. 123.

EARNINGS PER SHARE

Basic earnings per share are determined by dividing net income (loss) 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.

                                       25
<PAGE>

                           MARKWEST HYDROCARBON, INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


SEGMENT REPORTING

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 the
Company's reportable segments (see Note 12, SEGMENT REPORTING).

SUPPLEMENTAL CASH FLOW INFORMATION

<TABLE>
<CAPTION>
                                                                          Year Ended December 31,
                                                                            (in millions)
                                                                     ---------------------------
                                                                      2000      1999       1998
                                                                     ------    ------     ------
<S>                                                                  <C>       <C>        <C>
     Interest paid ............................................      $  2.5    $  2.7     $  2.4
     Interest expense capitalized to various construction
        projects ..............................................      $  0.1    $  0.2     $  0.3
     Income taxes paid (net of refunds) .......................      $  2.0    $ (1.5)    $  0.5
</TABLE>

Non-cash investing activities in 1998 included the forgiveness of a note and
related interest receivable valued at $10.1 million in exchange for the title to
a 32-mile pipeline in Michigan.

RECENT ACCOUNTING PRONOUNCEMENTS

In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards (`SFAS") No. 133, ACCOUNTING FOR DERIVATIVE
INSTRUMENTS AND HEDGING ACTIVITIES. This statement, as amended by SFAS Nos. 137
and 138, is effective for fiscal years beginning after June 15, 2000. SFAS No.
133 requires an entity to recognize all derivatives as assets or liabilities in
the balance sheet and measure those instruments at fair value. The Company has
adopted SFAS No. 133, as amended, on January 1, 2001. See Note 8, Adoption of
SFAS 133.

In December 1999, the Securities and Exchange Commission ("SEC") issued Staff
Accounting Bulletin ("SAB") No. 101, REVENUE RECOGNITION IN FINANCIAL
STATEMENTS, that provides guidance on the recognition, presentation and
disclosure of revenue in financial statements filed with the SEC. The adoption
of the SAB had no effect on the Company's financial position or net income.

The Emerging Issues Task Force of FASB, issued EITF Issue No. 00-10 "Accounting
for Shipping and Handling Fees and Costs". This issue addresses the statement of
income classification of shipping and handling costs billed to customers and was
effective for the fourth quarter of 2000. This has been adopted and prior period
amounts were reclassified to conform to the new requirement.

USE OF ESTIMATES

The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.

RECLASSIFICATIONS

Certain prior year amounts have been reclassified to conform to the 2000
presentation.

NOTE 3. DEBT

CREDIT FACILITY

Effective May 26, 2000, the Company amended its existing credit agreement. The
amended agreement has been extended for an additional year, through the year
2006, and provides for a $15 million increase to the maximum borrowing amount,
now $65 million, pursuant to a revolving loan commitment. Actual borrowing
limits may be a lesser amount, depending on trailing cash flow, as defined in
the agreement. The credit facility permits the Company to borrow money using
either a base rate loan or a London Interbank Offered Rate loan option, plus an
applicable margin of between 0 percent and 2.75 percent, based on a certain
Company debt to earnings ratio. At December 31, 2000, the Company had $43
million outstanding under the credit facility bearing interest at a weighted
average rate of 8.27 percent. At December 31, 1999, the Company had $40.5
million outstanding under the credit facility bearing interest at a weighted
average rate of 9.25 percent. The Company pays a fee at a rate between 0.25
percent and 0.50

                                       26
<PAGE>

                           MARKWEST HYDROCARBON, INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

percent per annum on the unused commitment, based on a certain Company debt to
earnings ratio. The credit facility is collateralized by a first mortgage on the
Company's major assets. The loan agreement restricts certain activities and
requires the maintenance of certain financial ratios and other conditions.

155 INVERNESS BUILDING LOAN

Effective January 14, 1998, the Company's wholly owned subsidiary, 155
Inverness, Inc., obtained a $3.7 million loan from an insurance company to
refinance an office building. As of December 31, 1999, approximately $3.6
million was outstanding under the note. The Company sold the office building in
February 2000 for net cash proceeds of $5.0 million and repaid the loan.

SCHEDULED DEBT MATURITIES

Scheduled debt maturities as of December 31, 2000, are as follows (in 000s):

<TABLE>
<S>                                               <C>
     2001 .................................        $        0
     2002 .................................                 0
     2003 .................................                 0
     2004..................................            10,500
     2005 and thereafter...................            32,500
                                                   ----------
     Total.................................        $   43,000
                                                   ==========
</TABLE>

NOTE 4. RELATED PARTY TRANSACTIONS

The Company, through its wholly owned subsidiary, MarkWest Resources, Inc.
("Resources"), holds varied undivided interests in several exploration and
production assets owned jointly with MAK-J Energy Partners Ltd. ("MAK-J"), which
owns a 51 percent undivided interest in such properties. The general partner of
MAK-J is a corporation owned and controlled by the President and Chief Executive
Officer of the Company. 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 for all
such expenses. As of December 31, 2000 and 1999, the Company has receivables due
from MAK-J for approximately $2,242,000 and $426,000, and payables to MAK-J for
approximately $773,000 and $400,000, respectively.

The Company made contributions of $475,000, $328,000 and $164,000 to a
profit-sharing plan for the years ended December 31, 2000, 1999 and 1998,
respectively. The plan is discretionary, with annual contributions determined by
the Company's Board of Directors.

NOTE 5. LEASE OBLIGATIONS

The Company has various non-cancelable operating lease agreements for equipment
and office space expiring at various times though fiscal 2015. Annual rent
expense under these operating leases was approximately $1,755,000, $893,000 and
$222,000 for the years ended December 31, 2000, 1999 and 1998, respectively. The
Company's minimum future lease payments under these operating leases as of
December 31, 2000 are as follows (in 000s):

<TABLE>
<S>                                               <C>
     2001 .................................       $    1,984
     2002 .................................            1,910
     2003..................................            1,853
     2004..................................            1,736
     2005..................................            1,748
     2006 and thereafter...................            5,562
                                                  ----------
     Total.................................       $   14,793
                                                  ==========
</TABLE>

NOTE 6. SIGNIFICANT CUSTOMERS

For the year ended December 31, 2000, sales to one customer accounted for
approximately 11 percent of total revenues. Management believes the loss of this
customer would not adversely impact operations, because alternative markets are
available. There were no significant customers in 1999 and 1998.

                                       27
<PAGE>

                           MARKWEST HYDROCARBON, INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 7. COMMODITY PRICE RISK MANAGEMENT

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

MarkWest achieves its goals utilizing a combination of fixed-price forward
contracts and fixed-for-float price swaps 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 the Company to protect
margins, because gains or losses in the physical market are generally offset by
corresponding losses or gains in the value of financial instruments.

The Company enters OTC swaps with counterparties that are primarily other energy
companies. The Company conducts a standard credit review and has agreements with
such parties that contain collateral requirements. The Company uses standardized
swap agreements that allow for offset of positive and negative exposures. Net
credit exposure is marked to market daily. The Company is subject to margin
deposit requirements under OTC agreements (and NYMEX positions).

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

MarkWest hedges its basis risk for natural gas but is generally unable to do so
for NGLs. The Company's basis risk stems from the geographic price differentials
between MarkWest's sales locations and hedging contract delivery locations.
Basis risk is the risk that an adverse change in the hedging market will not be
completely offset by an equal and opposite change in the price of the physical
commodity being hedged.

In its gathering, processing and marketing segment, the Company hedges
Appalachia processing margins by using a combination of methods. MarkWest
protects margins by purchasing natural gas priced on predetermined Btu
differentials to propane or crude, by simultaneously selling propane or crude
oil and purchasing natural gas, and by using swaps. Crude oil is highly
correlated with certain NGL products. All projected margins on open positions
assume the basis differentials between the Company's sales location and the
hedging contract's specified location and assume the correlation between crude
oil and NGLs is consistent with historical averages. As of December 31, 2000,
the Company had hedged 17,500,000 NGL gallons at a $0.22 per gallon processing
margin for 2001.

For certain Appalachia natural gas sales, as of December 31, 2000, the Company
had hedged 650,000 and 54,000 MMBtu at $4.86 and $5.19 per MMBtu for 2001 and
2002 respectively.

In addition to these risk management tools, MarkWest utilizes its NGL storage
facilities and contracts for third-party storage to build product inventories
during historically lower-priced periods for resale during higher-priced
periods. Also, MarkWest has contracts to purchase certain quantities of its
natural gas feedstock in advance of physical needs.

In its exploration and production segment, the Company also hedges its exposure
to changes in market prices for its natural gas production. As of December 31,
2000, the Company had hedged 1,226,000, 530,000 and 273,000 MMBtu of natural gas
sales at prices of $3.28, $3.45 and $3.92 per MMBtu for 2001, 2002 and 2003,
respectively.

The Company enters into speculative transactions on an infrequent basis.
Specific approval by the Board of Directors is necessary prior to executing such
transactions. Speculative transactions are marked to market at the end of each
accounting period, and any gain or loss is recognized in income for that period.
There were no such speculative activities for the years ended 2000, 1999 and
1998.

NOTE 8. ADOPTION OF SFAS NO. 133

The company is adopting Statement of Financial Accounting Standards No. 133
(SFAS 133), ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES, as
amended, on January 1, 2001. In accordance with the transition provisions of
SFAS 133, the Company will record 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. The Company expects to reclassify as

                                       28
<PAGE>

                           MARKWEST HYDROCARBON, INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


earnings during the next twelve months approximately $0.8 million loss from the
transition adjustment that was recorded in other comprehensive income.

SFAS 133 establishes accounting and reporting standards requiring derivative
instruments to be recorded in the balance sheet as either an asset of liability
measured at fair value. Changes in the derivative instruments' fair value are
recognized in earnings unless specific hedge accounting criteria are met.

SFAS 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 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 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. The Company expects its hedging activities
will generally qualify as cash-flow hedges. The Company formally documents,
designates and assesses the effectiveness of transactions receiving hedge
accounting treatment.

In its gathering, processing and marketing segment, the Company enters into
fixed-price contracts for the sale of NGLs and fixed-price purchases for the
purchase of natural gas, the difference in value being the "processing margin".
At January 1, 2001, a derivative asset of approximately $2.1 million will be
recorded in the balance sheet with an offsetting amount recorded, less a
deferred tax liability of approximately $0.7 million, in other comprehensive
income, approximately $1.3 million gain.

In its exploration and production segment, the Company enters into fixed price
contracts for the sale of natural gas. At January 1, 2001, a derivative
liability of approximately $3.9 million will be recorded in the balance sheet
with an offsetting amount recorded, less a deferred tax recovery of
approximately $1.4 million, in other comprehensive income, approximately $2.5
million loss.

Together, these amounts comprise the above net-of-tax cumulative effect
adjustment of approximately $1.2 million loss to other comprehensive income.

                                       29
<PAGE>

                           MARKWEST HYDROCARBON, INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 9. INCOME TAXES

The provision (benefit) for income taxes is comprised of (in 000s):

<TABLE>
<CAPTION>
                                       Year Ended December 31,
                                  ----------------------------------
                                   2000         1999          1998
                                  -------      -------       -------
<S>                               <C>          <C>           <C>
Current:
     Federal ...............      $ 1,260      $   788       $(1,921)
     State .................          406          (29)         (314)
                                  -------      -------       -------
     Total current .........        1,666          759        (2,235)
                                  -------      -------       -------

Deferred:
     Federal ...............        2,697          664         1,413
     State .................          525          278            55
                                  -------      -------       -------
     Total deferred ........        3,222          942         1,468
                                  -------      -------       -------

     Total tax provision ...      $ 4,888      $ 1,701       $  (767)
                                  =======      =======       =======

</TABLE>

The deferred tax liabilities (assets) are comprised of the tax effect of the
following at December 31 (in 000s):

<TABLE>
<CAPTION>
                                                                2000           1999
                                                              --------       --------
<S>                                                           <C>            <C>
Property and equipment .................................      $ 13,030       $  9,840
Other assets ...........................................           296            224
                                                              --------       --------
     Total deferred income tax liabilities .............        13,326         10,064
                                                              --------       --------
Alternative minimum tax ("AMT") credit carryforward ....        (2,031)        (1,888)
State net operating loss ("NOL") carryforwards .........           (49)          (151)
Intangible assets ......................................            (6)            (6)
                                                              --------       --------
     Total deferred income tax assets ..................        (2,086)        (2,045)
                                                              --------       --------
     Net deferred tax liability ........................      $ 11,240       $  8,019
                                                              ========       ========
</TABLE>

The differences between the provision for income taxes at the statutory rate and
the actual provision for income taxes subsequent to reorganization, are
summarized as follows (in 000s):

<TABLE>
<CAPTION>
                                                       2000           %          1999           %          1998           %
                                                      -------       ------      -------       ------      -------       ------
<S>                                                   <C>           <C>         <C>           <C>         <C>           <C>
Income tax (benefit) at statutory rate .........      $ 4,818         35.0%     $ 1,583         35.0%     $  (672)       (34.0%)
State income taxes, net of federal benefit .....          603          4.4%         168          3.7%        (102)        (5.1%)
Credits ........................................         (558)        (4.1%)        (75)        (1.7%)         --         --
Other ..........................................           25          0.2%          25          0.6%           7          0.3%
                                                      -------       ------      -------       ------      -------       ------
      Total ....................................      $ 4,888         35.5%     $ 1,701         37.6%     $  (767)       (38.8%)
                                                      =======       ======      =======       ======      =======       ======
</TABLE>

                                       30
<PAGE>

                           MARKWEST HYDROCARBON, INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


At December 31, 2000, the Company had state NOL carryforwards for state income
tax purposes and AMT credit carryforwards for federal income tax purposes of
approximately $1.1 million and $2.0 million, respectively. These carryforwards
expire as follows (000s):

<TABLE>
<CAPTION>
                                         State
     Expiration Dates                     NOL            AMT
     ----------------                   -------        --------
<S>                                     <C>            <C>
     2014..........................     $   160        $     --
     2015..........................         895              --
     No expiration.................          --           2,031
                                        -------        --------
          Total....................     $ 1,055        $  2,031
                                        =======        ========
</TABLE>

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

NOTE 10. STOCK COMPENSATION PLANS

At December 31, 2000, the Company has two stock-based compensation plans, which
are described below. The Company applies APB Opinion No. 25, ACCOUNTING FOR
STOCK ISSUED TO EMPLOYEES, and related Interpretations in accounting for its
plans. Accordingly, no compensation cost has been recognized for its fixed stock
option plans. Had compensation cost for the Company's 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, the Company's pro forma net income and
earnings per share would have been reduced to the pro forma amounts listed below
(in 000s, except per share data):

<TABLE>
<CAPTION>
                                                                2000         1999        1998
                                                              -------      -------     --------
<S>                                                           <C>          <C>         <C>
Net income (loss)                  As reported.............   $ 8,878      $ 2,823     $ (1,211)
                                   Pro forma...............     8,409        2,428       (1,483)
Basic earnings (loss) per share    As reported.............   $  1.05      $  0.33     $  (0.14)
                                   Pro forma...............      0.99         0.29        (0.17)
Earnings (loss) per share          As reported.............    $ 1.05      $  0.33     $  (0.14)
   assuming dilution               Pro forma...............      0.99         0.29        (0.17)
</TABLE>

Under the 1996 Stock Incentive Plan, the Company may grant options to its
employees for up to 850,000 shares of common stock in the aggregate. Under this
plan, the exercise price of each option equals the market price of the Company's
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
percent per year for options granted in 1999 and after, and 20 percent per year
for options granted prior to 1999.

Under the 1996 Non-employee Director Stock Option Plan, the Company may grant
options to its non-employee directors for up to 20,000 shares of common stock in
the aggregate. Under this plan, the exercise price of each option equals the
market price of the Company's 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 percent per
year. Biannual options vest 100 percent on the first anniversary of the option
grant date.

On October 1, 1998, the Company repriced all stock options granted in 1997 and
mid-1998. The stock options were repriced at $10.75 per share, the fair market
value on October 1, 1998.

The fair value of each option is estimated on the date of grant using the
Black-Scholes Option Pricing model with the following weighted-average
assumptions: dividend yield of $0/share for options granted in 2000, 1999 and
1998; expected volatility of 43 percent for the 2000 option grants, 40 percent
for the 1999 option grants and 34 percent for 1998 option grants; risk-free
interest rate of 5.93 percent for 2000 option grants, 6.22 percent for 1999
option grants and 4.35 percent for 1998 option grants; expected lives of 6 years
for 2000, 1999 and 1998 option grants.

                                       31
<PAGE>

                           MARKWEST HYDROCARBON, INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


A summary of the status of the Company's two fixed stock option plans as of
December 31, 2000, 1999 and 1998, and changes during the years ended on those
dates are presented below:

<TABLE>
<CAPTION>
                                                             2000                       1999                        1998
                                                    ------------------------    --------------------       -----------------------
                                                                   Weighted-                Weighted-                   Weighted-
                                                                   Average                  Average                      Average
                                                                   Exercise                 Exercise                     Exercise
                                                     Shares         Price        Shares      Price         Shares         Price
                                                    --------       --------     --------    --------      --------      ---------
<S>                                                 <C>           <C>           <C>         <C>           <C>           <C>
FIXED OPTIONS

Outstanding at beginning of year ............       621,117       $   9.15       514,503    $   9.78       383,490       $   12.50
Granted .....................................       150,317           9.94       141,672        7.03       374,162           11.53
Exercised ...................................        (4,655)          9.92            --          --       (11,482)           7.73
Canceled ....................................       (26,533)          9.10       (35,058)       9.86      (231,667)          17.21
                                                   --------       --------      --------    --------      --------       ---------
Outstanding at end of year ..................       740,246       $   9.15       621,117    $   9.15       514,503       $    9.78
                                                   ========       ========      ========    ========      ========       =========
Options exercisable at December 31, 2000,
   1999 and 1998, respectively ..............       342,914                      230,808                   148,840
Weighted-average fair value of
   options granted during the year ..........      $   4.93                     $   3.42                  $   4.72
</TABLE>

The following table summarizes information about fixed stock options outstanding
at December 31, 2000:

<TABLE>
<CAPTION>
                                             Options Outstanding                          Options Exercisable
                              -------------------------------------------------      -----------------------------
                                                   Weighted-
                                                   Average            Weighted-                          Weighted-
                                Number             Remaining           Average         Number             Average
                              Outstanding         Contractual          Exercise      Exercisable          Exercise
Range of Exercise Prices      at 12/31/00            Life               Price        At 12/31/00           Price
------------------------      -----------         -----------         ---------      -----------         ---------
<S>                           <C>                 <C>                 <C>            <C>                 <C>
$ 5.38 to $7.25.............    148,790                5.4             $  6.29           98,862           $  6.71
$ 7.28 to $8.75.............    150,761                8.2                8.54           32,386              8.12
$ 9.00 to $10.50............    170,755                5.7               10.18          102,475             10.13
$10.75 to $10.75............    196,754                6.7               10.75          109,191             10.75
$11.25 to $11.25............     73,186                9.6               11.25                0              0.00
                              ---------              -----             -------        ---------           -------
$ 5.38 to $11.25............    740,246                6.8             $  9.32          342,914           $  9.15
                              =========              =====             =======        =========           =======

</TABLE>

NOTE 11. 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, 2000, 1999 and 1998 (in 000s, except per share data):

<TABLE>
<CAPTION>
                                                    For the Year Ended December 31,
                                                   ---------------------------------
                                                    2000         1999         1998
                                                   -------      -------      -------
<S>                                                <C>          <C>          <C>
Net income (loss) ...........................      $ 8,878      $ 2,823      $(1,211)
                                                   =======      =======      =======
Weighted average number of outstanding
  shares of common stock used in earnings
  per share .................................        8,452        8,475        8,490
Effect of dilutive securities:
  Stock options .............................           40            6           --
                                                   -------      -------      -------

Weighted average number of outstanding
  shares of common stock used in earnings
  per share assuming dilution ...............        8,492        8,481        8,490
                                                   =======      =======      =======
</TABLE>

                                       32
<PAGE>

                           MARKWEST HYDROCARBON, INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 12. SEGMENT REPORTING

The Company's operations are classified into two principal reportable segments,
as follows:

     (1)  Gathering, Processing and Marketing-provide compression, gathering,
          treatment, NGL extraction and fractionation services; also purchase
          and market natural gas and NGLs; and

     (2)  Exploration and Production-explore for and produce natural gas.

MarkWest evaluates the performance of its segments and allocates resources to
them based on expected gross operating income. There are no intersegment
revenues. MarkWest's business is conducted solely in the United States.

The table below presents information about operating income for the reported
segments for the three years ended December 31, 2000. Operating income for each
segment includes total revenues less operating expenses, and excludes
depreciation, depletion and amortization, corporate administrative expenses,
interest expense, interest income and income taxes. Asset information by
reportable segment is not reported, since MarkWest does not produce such
information internally.

<TABLE>
<CAPTION>
                                        Gathering, Processing     Exploration and
                                            and Marketing           Production           Total
                                               (000s)                 (000s)             (000s)
                                        ---------------------     ---------------      ---------
<S>                                     <C>                       <C>                  <C>
FOR THE YEAR ENDED DECEMBER 31, 2000
Revenues ...........................            $217,393            $  4,161            $221,554
Segment operating income ...........            $ 29,035            $  1,899            $ 30,934

FOR THE YEAR ENDED DECEMBER 31, 1999
Revenues ...........................            $105,150            $  1,860            $107,010
Segment operating income ...........            $ 16,419            $    620            $ 17,039

FOR THE YEAR ENDED DECEMBER 31, 1998
Revenues ...........................            $ 63,190            $  1,415            $ 64,605
Segment operating income ...........            $  9,593            $    361            $  9,954
</TABLE>

A reconciliation of total segment operating income to total consolidated income
(loss) before taxes is as follows (000s):

<TABLE>
<CAPTION>
                                               2000           1999           1998
                                             --------       --------       --------
<S>                                          <C>            <C>            <C>
Total segment operating income ........      $ 30,934       $ 17,039       $  9,954
General and administrative expenses ...        (8,761)        (6,986)        (5,319)
Depreciation and amortization .........        (6,314)        (5,070)        (4,594)
Interest income .......................           101             53            200
Interest expense ......................        (3,110)        (2,745)        (2,095)
Gain on sale of assets ................         1,000          2,509
Other income (expense) ................           (84)          (276)          (124)
                                             --------       --------       --------
     Income (loss) before taxes .......      $ 13,766       $  4,524       $ (1,978)
                                             ========       ========       ========

</TABLE>

NOTE 13. SUBSEQUENT EVENTS

a)   In January 2001, MarkWest Hydrocarbon, Inc. purchased natural gas
     properties in San Juan County, New Mexico, for $5.6 million.

b)   In February 2001, three complaints were filed against MarkWest Hydrocarbon,
     Inc. in the Circuit Court of Wayne County, West Virginia, by Columbia Gas
     Transmission Corporation and Columbia Natural Resources, Inc.; Equitable
     Production Company and Equitable Energy LLC; and Cobra Petroleum Company et
     al. These complaints each allege breach of contract and seek various forms
     of relief (including injunctive relief) and damages. The parties have
     agreed to a temporary standstill to the litigation and are currently
     negotiating a resolution to this dispute. There can be no assurance that
     these negotiations will be successful or that the outcome of the litigation
     or the settlement discussions will be favorable to the Company. Losses, if
     any, with regard to these complaints are undeterminable.

                                       33
<PAGE>


                           MARKWEST HYDROCARBON, INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 14. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

The following summarizes certain quarterly results of operations (in 000s):


<TABLE>
<CAPTION>

                                               First          Second        Third         Fourth
                                               -----          ------        -----         ------
<S>                                           <C>            <C>           <C>           <C>
2000
----
Operating revenue ......................      $ 45,125       $ 39,328      $ 56,518      $   80,583
Income from operations (1) .............         6,034          1,343         3,005           5,477
Net income (2) .........................         3,255          1,107         1,325           3,191

Basic earnings per share ...............          0.39           0.13          0.16            0.38
Earnings per share assuming dilution ...          0.38           0.13          0.16            0.38

1999
----
Operating revenue ......................      $ 22,093       $ 17,978      $ 30,484      $   36,455
Income (loss) from operations (1) ......           960           (908)          542           4,389
Net income (3) .........................           110            577            59           2,077

Basic earnings per share ...............      $   0.01       $   0.07      $   0.01      $     0.24
Earnings per share assuming dilution ...      $   0.01       $   0.07      $   0.01      $     0.24
</TABLE>

-------------------

(1)  Excludes interest income and expense, other income and expense, and gain on
     sale of assets.

(2)  Includes $1.0 million gain ($0.6 million, or $0.07 per share, after tax) on
     the sale of an asset, second quarter of 2000.

(3)  Includes $2.5 million gain ($1.5 million, or $0.18 per share, after tax) on
     the sale of an asset, second quarter of 1999.

NOTE 15. SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
         (UNAUDITED)

COSTS

The following tables set forth capitalized costs at December 31, 2000, 1999 and
1998, and costs incurred for exploration and production activities for the years
ended December 31, 2000, 1999 and 1998 (in 000s):

<TABLE>
<CAPTION>
                                                              2000           1999           1998
                                                            --------       --------       --------
<S>                                                         <C>            <C>            <C>
Capitalized costs:
        Proved properties ............................      $ 12,481       $ 11,167       $  8,001
        Unproved properties ..........................         4,072          1,972          1,206
        Equipment and facilities .....................         1,484          1,379          1,349
                                                            --------       --------       --------
Total ................................................        18,037         14,518         10,556
        Less accumulated depreciation, depletion and
               amortization ..........................        (2,018)        (1,362)          (801)
                                                            --------       --------       --------
Net capitalized costs ................................      $ 16,019       $ 13,156       $  9,755
                                                            ========       ========       ========
Costs incurred:
Acquisition of properties
        Proved .......................................      $  1,191       $  1,503       $  2,632
        Unproved .....................................           166            728             12
Development costs ....................................         1,818          1,776            559
Exploration costs ....................................           971            435            284
                                                            --------       --------       --------
Total costs incurred .................................      $  4,146       $  4,442       $  3,487
                                                            ========       ========       ========

</TABLE>

                                       34
<PAGE>

                           MARKWEST HYDROCARBON, INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


RESULTS OF OPERATIONS

The results of operations for exploration and production activities, excluding
corporate overhead and interest costs, for the years ended December 31, 2000,
1999 and 1998 are as follows (in 000s):

<TABLE>
<CAPTION>
                                               2000          1999          1998
                                              -------       -------       -------
<S>                                           <C>           <C>           <C>
Revenues:
   Sales, net of taxes .....................  $ 3,874       $ 1,678       $ 1,375
   Other ...................................      287           182            40
                                              -------       -------       -------
   Total ...................................    4,161         1,860         1,415

Cost of sales ..............................     (833)         (322)         (231)
Lease operating expense ....................   (1,429)         (918)         (823)
                                              -------       -------       -------
Cash operating income ......................    1,899           620           361

Depreciation, depletion and amortization ...     (658)         (561)         (431)
Income tax benefit .........................      185            53            27
                                              -------       -------       -------
Results of operations ......................  $ 1,426       $   112       $   (43)
                                              =======       =======       =======
</TABLE>

RESERVE QUANTITY INFORMATION

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 the Company's financial condition and results of
operations.

The following table sets forth information for the years ended December 31,
2000, 1999 and 1998, with respect to changes in the Company's proved reserves,
all of which are in the United States.

<TABLE>
<CAPTION>
                                                    2000             1999              1998
                                                -----------       -----------       -----------
                                                Natural Gas       Natural Gas       Natural Gas
                                                   (Mcfe)            (Mcfe)           (Mcfe)
                                                -----------       -----------       -----------
<S>                                              <C>               <C>               <C>
Proved developed and undeveloped reserves:
Beginning of year ..........................     32,719,560        26,048,300        23,155,910
Revisions of previous estimates ............        (60,116)        1,031,719         1,164,111
Purchase of minerals in place ..............      1,524,400         2,252,853         3,029,036
Extensions and discoveries .................      2,253,000         4,355,359           129,029
Production .................................     (1,375,506)         (968,671)         (850,041)
Sale of minerals in place ..................       (475,800)               --          (579,745)
                                                -----------       -----------       -----------
End of year ................................     34,585,538        32,719,560        26,048,300
                                                ===========       ===========       ===========
Proved developed reserves:
Beginning of year ..........................     22,113,900        13,664,760        11,025,140
                                                ===========       ===========       ===========
End of year ................................     22,803,688        22,113,900        13,664,760
                                                ===========       ===========       ===========

</TABLE>

There were no significant oil reserves in any of the years presented.

STANDARDIZED MEASURES 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

                                       35
<PAGE>

                           MARKWEST HYDROCARBON, INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


reserves and their inherent limitations are discussed below. The Company
believes 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 the Company's 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.

The assumptions used to compute estimated future net revenues do not necessarily
reflect the Company's 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 the Company's 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 computed by applying the appropriate year-end
statutory tax rates, with consideration of future tax rates already legislated,
to the future pretax net cash flows relating to the Company's proved reserves.
Permanent differences in natural gas-related tax credits and allowances are
recognized.

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

Information with respect to the Company's estimated discounted future net cash
flows from its natural gas properties for the years ended December 31, 2000,
1999 and 1998, is as follows (in 000s):

<TABLE>
<CAPTION>
                                                                    2000            1999            1998
                                                                  ---------       ---------       ---------
<S>                                                               <C>             <C>             <C>
Future cash inflows ........................................      $ 296,454       $  75,290       $  51,055
Future production costs ....................................        (52,047)        (32,541)        (26,886)
Future development costs ...................................         (1,484)         (2,970)         (3,623)
Future income tax expense ..................................        (90,103)        (12,982)         (7,302)
                                                                  ---------       ---------       ---------
Future net cash flows ......................................        152,820          26,797          13,244
10% annual discount for estimated timing of cash flows .....        (87,770)        (15,332)         (8,271)
                                                                  ---------       ---------       ---------
Standardized measure of discounted future net cash flows
        relating to proved reserves ........................      $  65,050       $  11,465       $   4,973
                                                                  =========       =========       =========
Discounted future cash flows excluding income taxes ........      $  97,953       $  16,122       $  11,731
                                                                  =========       =========       =========

</TABLE>

Principal changes in the Company's estimated discounted future net cash flows
for the years ended December 31, 2000, 1999 and 1998, are as follows (in 000s):

<TABLE>
<CAPTION>
                                                                                     2000            1999           1998
                                                                                    --------       --------       --------
<S>                                                                                 <C>            <C>            <C>
January 1 ....................................................................      $ 11,465       $  4,973       $  8,060
   Sales and transfers of natural gas produced, net of production costs ......        (1,899)          (620)          (361)
   Net changes in prices and production costs related to future production ...        72,526          3,332         (3,158)
   Previously estimated development costs incurred during the period .........         1,816            654            355
   Changes in estimated future development costs .............................          (315)            --           (339)
   Extensions and discoveries ................................................         7,429          3,260             81
   Revisions of previous quantity estimates ..................................           213            492            316
   Purchases of reserves in place ............................................         4,468          1,432          1,471
   Sales of reserves in place ................................................          (177)            --           (673)
   Changes in production rates and other .....................................        (3,841)          (708)        (2,116)
   Accretion of discount .....................................................         1,612            753          1,086
   Net change in income taxes ................................................       (28,247)        (2,103)           251
                                                                                    --------       --------       --------
December 31 ..................................................................      $ 65,050       $ 11,465       $  4,973
                                                                                    ========       ========       ========

</TABLE>

                                       36
<PAGE>

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

None.

                                    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

Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12 and 13 are omitted
because the Company will file a definitive proxy statement pursuant to
Regulation 14A under the Exchange Act of 1934 not later than 120 days after the
close of the fiscal year. The information required by such Items will be
included in the definitive proxy statement to be so filed for the Company's 2001
annual meeting of stockholders hereby incorporated by reference.

                                     PART IV

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

(a)  The following documents are filed as part of this report:

     (1)  Financial Statements:

          Reference is made to the Index to Consolidated Financial Statements
          included in this Form 10-K for a list of all financial statements
          filed as a part of this report.

     (2)  Financial Statement Schedules:

          None required.

     (3)  Exhibits:

          See (c) below.

(b)  Reports on Form 8-K:

     A report on Form 8-K was filed on February 22, 2001, concerning the
     litigation described in Item 3-Legal Proceedings. A report on Form 8-K was
     filed on November 15, 2000, announcing the acquisition of additional coal
     bed methane properties in New Mexico's San Juan Basin. The deal closed
     January 2001.

(c)  Exhibits required by Item 601 of Regulation S-K. See (a) (3) above.

<TABLE>
<S>       <C>
     2.1  Purchase and Sale Agreement between MarkWest Hydrocarbon, Inc., and
          Michigan Energy Company, L.L.C., dated November 21, 1997 (filed as
          Exhibit 2.1 to MarkWest Hydrocarbon, Inc.'s Form 8-K filed on January
          29, 1998, and incorporated herein by reference).

     3.1  Certificate of Incorporation of MarkWest Hydrocarbon, Inc. (filed as
          Exhibit 3.1). (1)

     3.2  Bylaws of MarkWest Hydrocarbon, Inc. (1)

    10.1  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. (1)

    10.2  1996 Incentive Compensation Plan (filed as Exhibit 10.25). (1)

    10.3  1996 Stock Incentive Plan (filed as Exhibit 10.26). (1)

    10.4  1996 Non-employee Director Stock Option Plan (filed as Exhibit 10.27).
          (1)

    10.5  Form of Non-Compete Agreement between John M. Fox and MarkWest
          Hydrocarbon, Inc. (filed as Exhibit 10.28). (1)

    10.6  MarkWest Hydrocarbon, Inc., 1997 Severance and Non-Compete Plan (filed
          as Exhibit 10.1 to MarkWest Hydrocarbon, Inc.'s Form 10-Q for the
          three months ended September 30, 1997, and incorporated herein by
          reference).

    10.7  Second Amended and Restated Credit Agreement, dated as of September
          29, 1999, among MarkWest Hydrocarbon, Inc., as the Borrower; and
          Certain Commercial Lending Institutions as the Lenders; and Bank of
          America, N.A., as the Administrative Agent and the Syndication Agent
          for the Lenders (filed as Exhibit 10 to MarkWest Hydrocarbon, Inc.'s
          Form 10-Q for the three months ended September 30, 1999, and
          incorporated herein by reference).

    10.8  First Amendment to Second Amended and Restated Credit Agreement, dated
          as of May 26, 2000 among MarkWest Hydrocarbon, Inc., as the Borrower
          and Certain Commercial Lending Institutions, as the Lenders, and Bank
          of America, N.A., as the Administrative and Syndication Agent for the
          Lenders.

    11.   Statement regarding computation of earnings per share.

    21.   List of Subsidiaries of MarkWest Hydrocarbon, Inc.

    23.1  Consent of PricewaterhouseCoopers LLP

    23.2  Consent of Cawley, Gillespie & Associates, Inc.

</TABLE>

-------------------

(1)  Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Registration
     Statement on Form S-1, Registration No. 333-09513.

                                       37
<PAGE>

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 26, 2001.


                                        MarkWest Hydrocarbon, Inc.
                                              (Registrant)

                                        BY: /s/ John M. Fox
                                            ------------------------
                                                 John M. Fox
                                             President and Chief
                                              Executive Officer

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. Fox                  March 26, 2001
         -----------------------------------
                   John M. Fox
             President, Chief Executive
               Officer and Director


               /s/ Brian T. O'Neill               March 26, 2001
         -----------------------------------
                 Brian T. O'Neill
             Senior Vice President, Chief
             Operating Officer and Director


              /s/ Gerald A. Tywoniuk              March 26, 2001
         -----------------------------------
                Gerald A. Tywoniuk
             Chief Financial Officer and
             Vice President of Finance
             (Principal Financial and
               Accounting Officer)


               /s/ Arthur J. Denney               March 26, 2001
         -----------------------------------
                 Arthur J. Denney
        Senior Vice President of Engineering
        and Project Management and Director


             /s/ William A. Kellstrom             March 26, 2001
         -----------------------------------
               William A. Kellstrom
                     Director


               /s/ Karen L. Rogers                March 26, 2001
         -----------------------------------
                 Karen L. Rogers
                     Director


               /s/ Barry W. Spector               March 26, 2001
         -----------------------------------
                 Barry W. Spector
                     Director


                /s/ Donald D. Wolf                March 26, 2001
         -----------------------------------
                  Donald D. Wolf
                     Director

                                       38