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MarkWest Hydrocarbon, Inc. Form 10-K Table of Contents
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

FORM 10-K

Commission File Number 1-11566

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

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

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

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

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

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

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

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

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

DOCUMENTS INCORPORATED BY REFERENCE

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

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

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PART I

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

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

a.)  General Development of Business

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

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

Gathering, Processing and Marketing

        In our GPM segment, we are engaged in the gathering and processing of natural gas and the transportation, fractionation and storage of natural gas liquids (NGLs) for the benefit of natural gas producers and pipeline companies. Additionally, we purchase and market third-party natural gas and NGLs as part of our gas marketing business. We are the largest processor of natural gas in the northeastern United States, processing gas from the Appalachian basin, one of the country's oldest natural gas producing regions, from Michigan and from Alberta, Canada. Our GPM assets include:

Appalachia

•

five natural gas processing plants in Kentucky and West Virginia, which extract NGLs from natural gas, with an aggregate design throughput capacity of approximately 352,000 Mcf/d of natural gas, and which processed an average of 276,000 Mcf/d of natural gas for the year ended December 31, 2001;



•

136 miles of NGL pipeline that transported approximately 360,000 gallons of NGLs per day to our fractionation plant for the year ended December 31, 2001;



•

a fractionation plant in Kentucky with a design throughput capacity of 600,000 gallons per day, which separates, or fractionates, NGLs into individual NGL products, and which produced approximately 155 million gallons of NGL products (equivalent to 425,000 gallons per day) for the year ended December 31, 2001; and



•

an eleven million-gallon underground NGL storage facility adjacent to our fractionation plant.

Michigan

•

a 90-mile gas gathering pipeline with a design throughput capacity of 35,000 Mcf/d, which transports natural gas produced from a three county area in western Michigan to our natural gas processing plant, and which transported an average of approximately 8,800 Mcf/d of natural gas for the year ended December 31, 2001; and



•

a natural gas processing plant in western Michigan, with a design throughput capacity of 35,000 Mcf/d of natural gas, and which produced approximately eight million gallons of NGL products for the year ended December 31, 2001.

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Canada

•

a plant with six miles of pipelines and compression facilities that was expanded and gathered 10,000 Mcf/d in early 2002; and



•

a gathering system, nearly complete, with 23 miles of pipelines that gathers approximately 17,000 Mcf/d and includes dehydration and compression facilities.

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

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

Exploration and Production

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

Rocky Mountains

•

over 12,000 net developed acres;



•

50 net gas wells; and



•

41.0 Bcfe estimated proved reserves.

Michigan

•

1,360 net developed acres and another 6,480 undeveloped acres; and



•

0.5 Bcfe estimated proved reserves

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Canada

•

38,512 net developed acres and another 15,188 undeveloped acres;



•

57 net natural gas wells and 6 net oil wells; and



•

29.3 Bcfe estimated proved reserves.

Strategy and Other Matters

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

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

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

b.)  Financial Information about Segments

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

c.)    Narrative Description of Business

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

Gathering, Processing and Marketing

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

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

Appalachia

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

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

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

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

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(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)

Kenova was expanded in July 2001 by the addition of a 40,000 Mcf/d plant.

(4)

Includes fractionation of NGLs extracted at Kenova, Boldman, Cobb, Kermit and Maytown listed above. Siloam has been continually upgraded since we acquired it in 1988.

(5)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Expansion Projects in Appalachia

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

•

the assumption of the operation of our Boldman processing plant from Columbia Gas in February 2000;



•

the construction of our Maytown processing plant, completed in February 2000;



•

the acquisition of our Cobb processing plant from Columbia Gas in March 2000;



•

the construction of our Kermit processing plant, completed in January 2001;



•

the expansion of our Kenova processing plant, completed in July 2001;



•

the acquisition of our 40-mile, Ranger to Kenova NGL pipeline, which together with our existing pipeline and a pipeline leased in 2000, form a continuous 136-mile pipeline network through the southern portion of Appalachia;



•

the expansion of our Siloam fractionation facility from a capacity of 130 million gallons per year to 220 million gallons per year; and



•

the acquisition of various marketing assets including terminals, tank railcars, pressurized trailers, and new and larger loading facilities.

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

Michigan

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

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

(1)

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

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

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

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

Canada

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

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

Exploration and Production

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

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Canada

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

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

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

Rocky Mountains

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

Michigan

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

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

Reserves

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

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

(1)

Canadian results are presented only for December 31, 2001, as our acquisition was effective in August 2001.

(2)

Oil and liquid production is converted to natural gas equivalents (Mcfe) at a rate of one barrel to six Mcf.

(3)

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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

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

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

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

Production

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

(1)

The results for 2001 reflect the result of our Canadian acquisition since August 2001. Production in Canada for August 1, 2001 to December 31, 2001 averaged 13,500 Mcfe/d.

(2)

Oil and liquid production is converted to natural gas equivalents (Mcfe) at a rate of one barrel to six Mcf.

Productive Wells

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

(1)

Each well completed to more than one producing zone is counted as a single well.

(2)

A gross well is a well in which a working interest is owned.

(3)

One net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interest owned in gross wells.

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Drilling and Recompletion Activity

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

(1)

The results for 2001 reflect the results of our Canadian acquisition since August 2001.

(2)

A gross well is a well in which a working interest is owned.

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(3)

A non-productive well is a well deemed to be incapable of producing either natural gas or oil in sufficient quantities to justify completion as a natural gas or oil well.

(4)

One net well is deemed to exist when the sum of the fractional ownership working interest in gross wells equals one.

(5)

A recompletion well is a well where within an existing wellbore, a different geological horizon with proved reserves is completed as a producing well, in addition to the existing producing horizon. These are dually completed wells.

Acreage

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

(1)

Developed acres are those acres which are spaced or assigned to productive wells.

(2)

Undeveloped acres are considered to be those acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. It should not be confused with undrilled acreage held by production under the terms of a lease.

(3)

A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(4)

A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres.

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

Factors Affecting our Operations

Seasonality

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

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Competition

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

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

•

major integrated oil companies;



•

major interstate and intrastate pipelines;



•

other large raw natural gas gatherers that gather, process and market natural gas and NGLs; and



•

a relatively large number of smaller gas gatherers of varying financial resources and experience.

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

Operational Risks and Insurance

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

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

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

Government Regulation

United States

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

17

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

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

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

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

Canada

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

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

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

18

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

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

Environmental Matters

United States

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

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

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

Canada

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

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Employee Safety

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

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

Employees

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

d.)  Financial Information about Geographic Areas

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

Forward-Looking Information

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

20

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

•

our plans for pursuing future exploration projects;



•

our production plans;



•

our expectations regarding gas prices;



•

our estimates of quantities of proven oil and gas reserves;



•

our projections of rates of production and timing of development expenditures;



•

our efforts to increase fee-based contract volumes



•

our ability to manage the natural hedge by balancing our production and our consumption volumes;



•

our ability to maximize the value of our NGL output;



•

the adequacy of our general public liability, property, and business interruption insurance;



•

our ability to comply with environmental and governmental regulations; and



•

our expectations regarding MarkWest Energy Partners, L.P.

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

•

changes in general economic conditions in regions in which our products are located;



•

the availability and prices of NGL and competing commodities;



•

the availability and prices of raw natural gas supply;



•

our ability to negotiate favorable marketing agreements;



•

the risks that third party or MarkWest's natural gas exploration and production activities will not occur or be successful;



•

our dependence on certain significant customers, producers, gatherers, treaters, and transporters of natural gas;



•

competition from other NGL processors, including major energy companies;



•

our ability to identify and consummate grass-roots projects or acquisitions complementary to our business;



•

winter weather conditions;



•

changes in foreign economics, currency, and laws and regulations in Canada where MarkWest has made direct investments;



•

our ability to integrate the recent Canadian acquisition to operate an exploration and production company in Canada, and to manage the Company as a more exploration and production focused enterprise;

21

•

our ability to estimate quantities of proven oil and gas reserves;



•

our ability to project rates of production;



•

our ability to project the timing of developmental expenditures; and



•

our ability to manage the risks inherent in drilling wells.

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

ITEM 3. LEGAL PROCEEDINGS

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

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

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

PART II

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

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

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

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

ITEM 6. SELECTED FINANCIAL DATA

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

22

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

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(1)

Includes gas marketing revenues of $65,700, $91,000 and $34,100 for the years ended December 31, 2001, 2000 and 1999, respectively. Our gas marketing business originated in 1998. Gas marketing activities are low margin; these activities are undertaken in support of our processing business.

(2)

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

(3)

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

(4)

Earnings before interest income, interest expense, income taxes, depreciation and depletion, and gain on sale of assets.

(5)

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

(6)

Includes cash of $2,340; $934; $1,356; $2,055 and $1,364, respectively.

(7)

At December 31, 2001 total debt is $112,821; giving effect to the March 29, 2002 amendments to our credit facility, the current portion of long term debt is $7,971 and this is included in working capital.

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

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

Results of Operations

Year Ended December 31, 2001 Compared to the Year Ended December 31, 2000

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

•

a decrease in the average Appalachian NGL sales price, which accounted for approximately $15.5 million of the overall decrease. The Appalachian average NGL sales price is based on both sales out of our Siloam fractionator as well as our Appalachian terminal outlets. The Appalachian average NGL sales price was $0.55 per gallon for the year ended December 31,

24

2001, compared to $0.65 per gallon for the year ended December 31, 2000, a decrease of $0.10 per gallon, or 15%.

•

a decrease in gas marketing revenues, which accounted for approximately $27.1 million of the decrease. Gas marketing revenues declined in 2001 as natural gas prices and volumes sold decreased from above average levels that existed in 2000.

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

•

our acquisition of two Canadian natural gas production companies during August 2001, accounting for $5.1 million of the increase.



•

natural gas sales prices increased, accounting for $1.6 million of the increase. For our combined Rocky Mountain and Michigan production, our average sales price was $3.59 per Mcfe in 2001 compared to $2.95 per Mcfe in 2000, an increase of $0.64 per Mcfe, or 22%.



•

our combined natural gas production and sales from our Rocky Mountain and Michigan properties increased 94% during 2001, accounting for $3.7 million of the increase. The increase in our production was a direct result of our ongoing capital program for our United States properties.

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

•

a decrease in the average cost of our Appalachian replacement natural gas, which accounted for $6.5 million of the overall decrease. The average cost of our Appalachian feedstock was equivalent to $0.40 per NGL gallon for the year ended December 31, 2001, compared to $0.44 per gallon for the year ended December 31, 2000, an decrease of $0.04 per gallon, or 9%.



•

a decrease in gas marketing cost of sales, which accounted for $26.1 million of the overall decrease. Gas marketing cost of sales decreased principally due to a decrease in natural gas costs and volumes sold in 2001.

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

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

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

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

25

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

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

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

Year Ended December 31, 2000, Compared to Year Ended December 31, 1999

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

•

an increase in our Appalachian NGL product sales volumes, which accounted for approximately $18.1 million of the overall increase. Appalachian sales volumes include volumes sold out of our Siloam fractionator as well as our terminals. The Siloam fractionation facility's NGL sales volumes were a record 153 million gallons for the year ended December 31, 2000, compared to 116 million gallons for the year ended December 31, 1999, an increase of 37 million gallons, or 32%. The increased volumes in 2000 were due to increased gas production behind our facilities and the natural gas processing plant and fractionation facility expansions in the Appalachia area. In particular, the Maytown gas processing facility commenced operations during 2000, providing a significant, new fee-based revenue stream.



•

an increase in our Appalachian average NGL sales price, which accounted for approximately $35.7 million of the overall increase. The Appalachian average NGL sales price was $0.65 per gallon for the year ended December 31, 2000, compared to $0.43 per gallon for the year ended December 31, 1999, an increase of $0.22 per gallon, or 51%.



•

an increase in gas marketing revenue, which accounted for $56.0 million of the overall increase. Gas marketing revenue was up due to above average natural gas prices and larger volumes sold in 2000.



•

a decrease in Michigan pipeline throughput and NGL sales volumes were offset by an increase in the Michigan average NGL sales price.

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

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

•

an increase in our Siloam fractionation facility's NGL sales volumes, which accounted for approximately $16.7 million of the overall increase.

26

•

an increase in our average Appalachian replacement natural gas cost, which accounted for approximately $19.5 million of the overall increase. The average cost of Appalachian replacement natural gas was equivalent to $0.44 per NGL gallon for the year ended December 31, 2000, compared to $0.27 per gallon for the year ended December 31, 1999, an increase of $0.17 per gallon, or 63%.



•

an increase in gas marketing cost of sales, which accounted for approximately $55.3 million of the overall increase. Gas marketing cost of sales increased due to above average natural gas prices in 2000.

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

•

increased operating costs associated with higher volumes processed through our new facilities in Appalachia. The recently constructed Maytown and recently acquired Boldman and Cobb extraction facilities and related pipeline added $1.7 million in expenses, and the expanded Siloam fractionation plant added $0.6 million in expenses.



•

higher natural gas costs and greater volumes in 2000 also increased fuel costs by $0.6 million at the Siloam fractionation facility in Appalachia.



•

our Appalachian expansion added $0.3 million in regional expenses.



•

lower Michigan pipeline throughput volumes decreased operating costs $0.5 million.

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

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

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

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

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

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

Critical Accounting Policies

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

Reserve Estimates

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

Impairment of Long-Lived Assets

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

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

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

Liquidity and Capital Resources

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

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

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

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

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

Cash Flows

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

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

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

Total Contractual Cash Obligations

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

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Capital Expenditures

        MarkWest's capital expenditures are summarized as follows: