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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

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

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

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

DOCUMENTS INCORPORATED BY REFERENCE

        The information required by certain items of Part III of this Report (Items 10, 11, 12 and 13) is incorporated by reference from the registrant's proxy statement to be filed pursuant to Regulation 14A with respect to the 2003 annual meeting of stockholders.

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

        Glossary of Terms

PART I

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

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General

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

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

Recent Developments

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

•

From 1999-2001, we expanded our Appalachian infrastructure, which collectively increased our total natural gas design processing capacity by 127,000 Mcf/d. During this time, we assumed operation of a processing plant (Boldman), acquired another plant (Cobb), built two more (Maytown and Kermit) and expanded another (Kenova). We also expanded our Siloam fractionator. The entire $28.9 million expansion project was completed in mid-2001.

•

In August 2001, we acquired two privately owned, independent Canadian exploration and production companies for over $50 million. The acquisition more than doubled our reserves at the time. It is also provided us with the necessary size and cash flow needed to form MarkWest Energy Partners. The acquisition included significant undeveloped acreage, approximately 50,000 gross acres as of December 31, 2002, that we believe, and our drilling results to date indicate, holds significant reserves.

•

In May 2002, we spun off the majority of our gathering and processing assets into a master limited partnership, MarkWest Energy Partners, L.P. (MarkWest Energy Partners), while simultaneously completing its initial public offering. The limited partnership structure reduces our cost of capital and provides a platform to efficiently grow our midstream business. As of December 31, 2002, we own a 46.7% interest in MarkWest Energy Partners consisting of 2,479,762 subordinated units and a 2% general partner interest. Through our ownership of the general partner, we control and operate MarkWest Energy Partners.

•

In March 2003, we began delivering on the growth potential of MarkWest Energy Partners when it was announced MarkWest Energy Partners had entered into an agreement to merge with Pinnacle Natural Gas Company and certain affiliates for approximately $38 million. The acquired assets, primarily located in Texas, are comprised of (a) three lateral natural gas

pipelines transporting up to 1.1 Bcf/day of natural gas under firm contracts to power plants and (b) eighteen gathering systems gathering more than 44,000 Mcf/d. The acquisition complements and expands MarkWest Energy Partners' core fee-based business, while providing geographic and customer diversification. The acquisition will be financed primarily through borrowings under the Partnership's credit facility, which was recently expanded by $15 million.

Strategy

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

•

Execute our Canadian and U.S. drilling program—For the year ended December 31, 2002, our production increased 122% over the prior year. We also added reserves equal to 149% of production. We favor low-risk exploitation drilling, and between the U.S. and Canada, we have a multi-year inventory of projects. In 2003, we plan to drill 21 (8.9 net) wells in the U.S. and 50 (37.5 net) in Canada with our $17 million capital budget. Our goal is to add 150% of our 2003 production volumes to our year-end 2003 reserves.

•

Grow MarkWest Energy Partners—We intend to grow MarkWest Energy Partners through acquisitions and internal growth. Our ability to grow through acquisitions is evidenced by our March 2003 acquisition of the Pinnacle companies. The potential for internal growth is evidenced by the January 2003 connection of a new gatherer upstream of our Kenova NGL extraction plant. MarkWest Energy Partners has sufficient capacity to process the expected additional 10,000 Mcf/d of natural gas and the resulting 20,000 gallons per day of NGLs.

Business

        Our business activities are segregated into three segments:

•

Exploration and production;

•

Gathering and processing; and

•

Marketing.

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

Exploration and Production

        Our exploration and production business includes development, exploration, production and acquisition of natural gas and, to a lesser extent, oil. Our E&P segment produces natural gas in the Rocky Mountains of southern Colorado and northern New Mexico (San Juan Basin), Michigan and, as a result of our August 2001 acquisition, Alberta, Canada. We focus on low-risk exploitation of natural gas in existing, proven fields.

Reserves

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

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

Production

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

(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, 2002:

(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.

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.

(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 producing well, in addition to the existing producing horizon. These are dually completed wells.

(5)

A recompletion well is a well which 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 Hydrocarbon at December 31, 2002.

(1)

Developed acres are those acres that 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 74,240 gross and 59,946 net acres through the year 2003.

Gathering and Processing

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

Appalachia

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

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

(1)

Represents MarkWest Hydrocarbon until May 23, 2002, and MarkWest Energy Partners from May 24, 2002—the date its IPO closed.

(2)

Kenova also extracts NGLs from natural gas previously extracted at our Kermit processing plant. Kermit volumes require further processing. 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.

(3)

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

(4)

MarkWest Energy Partners' processing plants were constructed to accommodate gas volumes somewhat in excess of their design throughput capacity.

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

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

Michigan

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

NA—Not applicable

(1)

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

(2)

Represents MarkWest Hydrocarbon until May 23, 2002, and MarkWest Energy Partners from May 24, 2002—the date its IPO closed.

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

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

Marketing

        Our marketing group markets our NGL production in Appalachia. In 2002, we sold 183 million gallons of NGLs extracted at our Siloam facility. We ship NGL products from Siloam by truck, rail and barge. We sell our own propane and purchase propane from third parties for resale to our wholesale customers. Our marketing customers include propane retailers, refineries, petrochemical plants and NGL product resellers. Most marketing sales contracts have terms of one year or less, are made on best efforts basis and are priced in reference to Mt. Belvieu index prices or plant posting prices. In addition to our NGL product sales, our marketing operations are also responsible for the purchase of natural gas delivered for the account of producers pursuant to our keep-whole processing contracts.

        We strive to maximize the value of our NGL output by marketing directly to our customers. We minimize the use of third-party brokers and instead support a direct marketing staff focused on multi- state and independent dealers. Additionally, we use our own trailer and railcar fleet, as well as our own terminals and owned and leased storage facilities, to enhance supply reliability to our customers. These efforts have allowed us to maintain premium pricing for the majority of our NGL products compared to Gulf Coast spot prices.

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

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

        As compensation for providing processing services to our Appalachian producers (we have since outsourced these services to MarkWest Energy Partners as discussed below), we earn both a fee and the NGLs produced. In return, we are required to replace, in dry natural gas, the Btu value of the NGLs extracted. This Btu replacement obligation is referred to in the industry as a "keep-whole" arrangement. In keep-whole arrangements, our principal cost is the replacement of the Btus extracted from the gas stream in the form of NGLs or consumed as fuel during processing with dry gas of an equivalent Btu content. Generally, the value of the NGLs extracted is greater than the cost of replacing those Btus with dry gas, resulting in positive operating margins under these contracts. In the event natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, the cost of keeping the producer "whole" results in operating losses. The spread between the NGL product sales price and the purchase price of natural gas with an equivalent Btu content is called the "frac spread".

        At the closing of its MarkWest Energy Partners' IPO on May 24, 2002, we outsourced our midstream services to the Partnership, which performs natural gas gathering and processing and NGL transportation, fractionation and storage services for us for a fee pursuant to the terms of our operating agreements with the Partnership. Under those agreements, we retained all the benefits and associated risks of our keep-whole contracts with producers. Our NGL and gas marketing operations were not contributed to MarkWest Energy Partners.

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

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

Factors Affecting our Operations

Seasonality

        A substantial portion of our midstream revenues and, as a result, our midstream gross margin, remains dependent upon the volume and sales price of NGL products, particularly propane. The volume and sales price of NGL products fluctuate with the winter weather conditions and other supply and demand determinants. The strongest demand for propane and the highest propane sales margins generally occur during the winter heating season. As a result, we recognize a substantial portion of our annual income from our marketing segment during the first and fourth quarters of the year.

Competition

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

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

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

•

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.

Operational Risks and Insurance

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

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

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

Government Regulation

United States

        In the Michigan area of our gathering, processing and marketing segment, we own and operate a gathering pipeline in conjunction with our processing plant. Under the Natural Gas Act of 1938, facilities that have as their "primary function" the performance of gathering activities and are not owned by interstate gas pipeline companies are wholly exempt from Federal Energy Regulatory Commission jurisdiction. State and local regulatory authorities oversee intrastate gathering and other natural gas pipeline operations. The Michigan Public Service Commission (MPSC) regulates the construction, operation, rates and safety of certain natural gas gathering and transmission pipelines pursuant to state regulatory statutes. We conduct gas pipeline operations in Michigan through an affiliate, which is subject to this regulation by the MPSC. The design, construction, operation and maintenance of the pipeline are also subject to safety regulations.

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

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

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

Canada

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

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

        In Alberta, we are entitled to a credit against Crown royalties on most of the properties in which we have an interest in by virtue of the Alberta Royalty Tax Credit (ARTC). The credit is determined by applying a rate to a maximum of CDN$2.0 million of Crown royalties payable in Alberta for each company or associated group of companies. The rate is a function of the royalty tax credit par prices, which is determined quarterly by the Alberta Department of Energy. The rate ranges from 25% to 75% depending upon petroleum prices for the previous quarter.

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

Environmental Matters

United States

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

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

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

Canada

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

Employee Safety

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

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

Employees

        As of December 31, 2002, we had 120 employees. At our fractionation facility in South Shore, Kentucky, the Paper, Allied Industrial, Chemical, and Energy Workers International Union Local 5-0372 represent 15 employees. We entered into our collective bargaining agreement with this Union on June 29, 2001 and it expires in June 2004. The agreement covers only hourly, non-supervisory employees. We consider our labor relations to be good.

Available Information

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

Forward-Looking Information

        Statements included in this Annual Report on Form 10-K and documents incorporated by reference to this report that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. We use words such as "may," "believe," "estimate," "expect," "plan," "intend," "project," "anticipate," and similar expressions to identify forward-looking statements. We have based these forward-looking statements on our current expectations and projections about future events, activities or developments. Our actual results could differ materially from those discussed in our forward-looking statements. Forward-looking statements include statements relating to, among other things:

•

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 Hydrocarbon'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 Hydrocarbon 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;



•

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

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

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

        There were no matters submitted to a vote of security holders during the quarter ended December 31, 2002.

PART II

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

        Our common stock trades on the American Stock Exchange national market under the symbol "MWP." As of December 31, 2002, there were 8,510,913 shares of common stock outstanding held by approximately 550 holders of record. The following table sets forth quarterly high and low sales prices as reported by the American Stock Exchange for the periods indicated.

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

ITEM 6. SELECTED FINANCIAL DATA

        The following table sets forth selected consolidated historical financial and operating data for MarkWest Hydrocarbon. Certain prior year amounts have been reclassified to conform to the 2002 presentation. The selected consolidated statement of operations and balance sheet data for the years ended December 31, 2002, 2001, and 2000, and as of December 31, 2002 and 2001, are derived from, and are qualified by reference to, our audited Consolidated Financial Statements included elsewhere in this Form 10-K. The selected consolidated statement of operations and balance sheet data set forth below for the years ended December 31, 1999 and 1998, and as of December 31, 2000, 1999 and 1998, have been derived from audited financial statements not included in this Form 10-K. You should read this in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our Consolidated Financial Statements and accompanying Notes included elsewhere in this Form 10-K.

(1)

Includes gas marketing revenues of $56,400, $62,700, $89,700 and $34,100 for the years ended December 31, 2002, 2001, 2000 and 1999 respectively. Our gas marketing operations originated in 1998. Gas marketing activities are low-margin; these activities are undertaken in support of our processing business.

(2)

Represents MarkWest Hydrocarbon until May 23, 2002, and MarkWest Energy Partners from May 24, 2002—the date its initial public offering closed.

(3)

Represents throughput at the Kenova, Cobb, Boldman and Maytown processing plants.

(4)

Prior to May 24, 2002, this represents NGL product production at the Siloam fractionator.

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

        The following discussion and analysis relates to factors that have affected our consolidated financial condition and results of operations for the three years ended December 31, 2002, 2001 and 2000. Certain prior year amounts have been reclassified to conform to the presentation used in 2002. In conjunction with the following discussion and analysis, you should also read our Consolidated Financial Statements and related Notes thereto and the "Selected Financial Data" included elsewhere in this Form 10-K.

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

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

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

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

Recent Developments

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

Results of Operations

Year Ended December 31, 2002 Compared to the Year Ended December 31, 2001

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

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

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

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

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

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

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

•

A decrease in the average NGL product sales price from our keep-whole contract, or "frac spread", business, net of volume increases, which accounted for approximately $3.6 million of the overall decrease. The average NGL sales price was $0.43 per gallon for the year ended December 31, 2002, compared to $0.55 per gallon for the year ended December 31, 2001, a decrease of $0.12 per gallon, or 22%.



•

We recognized a $2.4 million hedging ineffectiveness charge in 2002.



•

A decrease in gas marketing revenues, which accounted for approximately $6.2 million of the decrease. Gas marketing revenues declined in 2002 as natural gas prices retreated from above average levels that existed in 2001, more than offsetting volume increases.



•

A net $5.4 million decrease from our Michigan operations, primarily a function of the sales of an unusual amount of NGL products in the first quarter of 2001.

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

•

A decrease in our gas marketing cost of goods sold, which accounted for $8.2 million of the overall decrease. Gas marketing costs declined in 2002 as natural gas prices retreated from above average levels that existed in 2001, more than offsetting volume increases.



•

A net $5.6 million decrease from our Michigan operations, primarily a function of the sales of an unusual amount of NGL products in the first quarter of 2001.

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

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

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

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

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

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

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

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

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

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

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

•

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.

        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,

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.

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

•

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, a 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.

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

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

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

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

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

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

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

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

Seasonality

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

Liquidity and Capital Resources

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

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

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

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

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

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

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

Cash Flow

        Net cash provided by operating activities was $35.9 million, $13.0 million and $13.3 million for the years ended December 31, 2002, 2001 and 2000, respectively. Net cash provided by operations increased during 2002 because 2002 represented the first full year of our Canadian E&P operations. Net cash provided by 2001 operating activities was almost the same amount as it was in 2000. Favorable timing of cash flows from receivables and payables offset lower net income in 2001.

        Net cash used in investing activities was $22.5 million, $77.6 million and $12.3 million for the years ended December 31, 2002, 2001 and 2000, respectively. Net cash used in investing activities was much higher in 2001 due to our acquisition of two related E&P companies in Canada. Net of cash acquired, we paid $46.1 million for the acquisition.

        Net cash used in financing activities was $9.3 million for the year ended December 31, 2002. Net cash provided by financing activities was $66.1 million for the year ended December 31, 2001. Net cash used in financing activities were $1.5 million for the year ended December 31, 2000. Net cash used in financing activities in 2002 was primarily the result of using the proceeds from the Partnership's IPO to pay down debt. Net cash provided by financing activities was much higher in 2001 principally due to borrowings used to purchase two Canadian E&P companies. Net cash used in 2000 financing activities was a result of, despite our extensive Appalachian expansion, our ability to pay down our line of credit a modest amount because of strong cash flows from operations, which was a function of above average processing margins and record sales volumes in 2000.

Total Contractual Cash Obligations

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

Credit Facilities

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

Outlook

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

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

Related Parties

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

Critical Accounting Policies

        The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment, to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical. Our critical accounting policies are discussed below. You should also read Note 2 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

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 there from may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our gas and oil properties and/or the rate of depletion of the gas and oil properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Impairment of Long-Lived Assets

        In accordance with Statement of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we evaluate the long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on our estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is recalculated when related events or circumstances change.

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

Commodity Price Risk Management Activities

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

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

Recent Accounting Pronouncements

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

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

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

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

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

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

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Commodity Price Risk

Overview

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

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

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

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

        We enter OTC swaps with counterparties that are primarily financial institutions. We use standardized swap agreements that allow for offset of positive and negative exposures. Net credit exposure is marked to market daily. We are subject to margin deposit requirements under OTC agreements (with non-bank counterparties) and NYMEX positions.

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

Types of Price Risk

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

•

Under "keep-whole" contracts, we take title to and sell the NGLs produced in our processing operations. We also reimburse or "keep whole" the producers for the Btu content of the NGLs removed through the re-delivery to the producers of an equivalent amount (on a Btu basis) of

dry natural gas. Keep-whole contracts therefore expose us to NGL product price risk (on the sales side) and natural gas price risk (on the purchase or reimbursement side).

•

Under "percent-of-proceeds" contracts, we take title to the NGLs produced in our processing operations, we sell the NGLs to third parties and pay the producer a specified percentage of the proceeds received from the sales. Percent-of-proceeds contracts therefore expose us to NGL product price risk. All of our Michigan processing business is also governed by percent-of-proceeds contracts.

Natural Hedge and Basis Risk

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

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

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

        We are generally unable to hedge our basis risk for NGL products. We have two different types of NGL product basis risk. First, NGL product basis risk stems from the geographic price differentials between our sales locations and hedging contract delivery locations. We cannot hedge our geographic basis risk because there are no readily available products or markets. Second, NGL product basis risk also results from the difference in relative price movements between crude oil and NGL products. We may use crude oil, instead of NGL products, in our hedges because the NGL hedge products and markets are limited. Crude oil is highly correlated with certain NGL products.

Natural Gas Price Risk

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

(1)

Reflects our hedged natural gas prices as if natural gas was sold at Henry Hub (NYMEX).

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

NGL Product Price Risk

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

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

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

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

Sensitivities

        Our hedging program reduces our annual sensitivity to changes in NGL product sales prices. In our marketing segment, net income would have been higher by $6.0 million, lower by $4.0 million and higher by $1.7 million for the years ended December 31, 2002, 2001 and 2000, respectively, if we had not hedged. These figures consider only hedges of Appalachian processing margin and do not reflect other decisions made concerning when to buy natural gas or store NGL production for sale in later months. In our E&P segment, without hedging, net income would have been lower by $1.9 million, lower by $0.4 million and higher by $0.6 million for the years ended December 31, 2002, 2001 and 2000, respectively.

        Our annual sensitivities to changes in commodity prices considering our hedge position are as follows. For every $0.10 per MMBtu increase in the natural gas price, our gross margin (defined as revenue less purchased product costs) would decrease by $0.6 million. For every $1.00 per barrel reduction in the crude oil price, or $0.02 per gallon reduction in NGL prices, our gross margin would decrease by $1.3 million.

Credit Risk

        Counterparties pursuant to the terms of their contractual obligations expose us to potential losses as a result of nonperformance. We maintain credit policies with regard to our counterparties that we believe minimize overall credit risk. Such policies include the evaluation of a prospective counterparty's financial condition, collateral requirements where deemed necessary, and the use of standardized agreements, which facilitate the netting of cash flows associated with a single counterparty. We also monitor the financial condition of existing counterparties on an ongoing basis. In general, our risk of default by these counterparties is low. However, we experienced a loss in 2001 as described below.

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

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

Foreign Currency Exchange Risk

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

Interest Rate Risk

        We are exposed to changes in interest rates, primarily as a result of our long-term debt with floating interest rates. We may make use of interest rate swap agreements expiring June 7, 2004 to adjust the ratio of fixed and floating rates in the debt portfolio. As of December 31, 2002, we are a party to contracts to fix interest rates on $10.0 million of our debt at 5.28% compared to floating LIBOR, plus an applicable margin. The impact of a 100 basis point increase in interest rates on our debt would result in an increase in interest expense and a decrease in income before taxes of approximately $0.5 million. This amount has been determined by considering the impact of the hypothetical interest rates on our variable-rate debt balances as of December 31, 2002.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

REPORT OF INDEPENDENT ACCOUNTANTS

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

        In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of cash flows and of changes in stockholders' equity present fairly, in all material respects, the financial position of MarkWest Hydrocarbon, Inc., a Delaware corporation, and its subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        As discussed in Note 2 to the financial statements, MarkWest Hydrocarbon, Inc. changed its method of accounting for inventory effective January 1, 2002. As discussed in Note 10, MarkWest Hydrocarbon, Inc. changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001.

/s/    PricewaterhouseCoopers LLP

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED BALANCE SHEETS

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS