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TABLE OF CONTENTS

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

FORM 10-Q

For the quarterly period ended March 31, 2002

OR

For the transition period from                              to                             

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

        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

        The registrant had 8,514,830 shares of common stock, $.01 per share par value, outstanding as of March 31, 2002.

Glossary of Terms

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

PART I—FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

MARKWEST HYDROCARBON, INC.
CONSOLIDATED BALANCE SHEET

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

MARKWEST HYDROCARBON, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(UNAUDITED)

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

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

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

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

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

MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1.    General

        The consolidated financial statements include the accounts of MarkWest Hydrocarbon, Inc. ("MarkWest"), and its wholly owned subsidiaries.

        Through consolidation, we have eliminated all significant intercompany accounts and transactions.

        We have prepared the unaudited financial statements presented herein in accordance with the instructions to Form 10-Q. The statements do not include all the information and note disclosures required by generally accepted accounting principles for complete financial statements. Please read the interim consolidated financial statements in conjunction with the Consolidated Financial Statements and attached notes for the year ended December 31, 2001, included in our Annual Report on Form 10-K, as filed with the Securities and Exchange Commission. In the opinion of management, we have made all necessary adjustments for a fair statement of the results for the unaudited interim periods. These are only normal recurring adjustments.

        We base the effective corporate tax rate for interim periods on the estimated annual effective corporate tax rate. The effective tax rate varies from statutory rates primarily due to Canadian resource allowances.

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

2.    Change in Inventory Accounting Method

        For the quarter ended March 31, 2002, the cost of natural gas liquids (NGL) product inventories was determined by the lower of market or weighted average cost. Prior to 2002, the cost of NGL product inventories was determined by the lower of market or first-in, first-out (FIFO) cost. The change in accounting method from FIFO to weighted average cost was made to better match cost of sales with revenues on a quarterly basis and to account for NGL product inventories on a consistent basis with other industry peer companies. The cumulative effect of the change in accounting was not material as of January 1, 2002. If we would have changed our method of accounting from FIFO to weighted average cost on January 1, 2001, income before income taxes, net income and basic earnings per share would have been as follows for the quarter ended March 31, 2002 on a pro forma basis (in thousands):

3.    Segment Reporting

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

(1)

Gathering, Processing and Marketing (GPM)—provide compression, gathering, treatment, NGL extraction and fractionation services; also purchase and market natural gas and NGL products; and



(2)

Exploration and Production (E&P)—explore for and produce natural gas.

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

        The table below presents information about operating income for the reported segments for the first quarter of 2002 and 2001. Operating income for each segment includes total revenues less operating expenses and depreciation, depletion and amortization and excludes selling, general and administrative expenses, interest expense, interest income and income taxes. We have not reported asset information by reportable segment, since we do not produce such information internally.

        Following is a reconciliation of total segment operating income to total consolidated income before taxes:

4.    Commitments and Contingencies

Legal

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

        On June 6, 2001, Level Propane Gases, Inc. filed suit against us in the Court of Common Pleas, Cuyahoga County, Ohio alleging breach of contract for failure to furnish a specified quantity of gallons of propane gas on a monthly basis from May 1, 2000 to April 30, 2001, and seeking direct and punitive damages. On July 25, 2001, we filed a motion to stay proceedings pending arbitration in Denver, Colorado in the Court of Common Pleas, Cuyahoga County, Ohio. The Court of Common Pleas granted the motion to stay proceedings. MarkWest filed a petition with the United States District Court for the District of Colorado seeking an order compelling Level Propane to comply with the arbitration provisions of its agreements with MarkWest. The United States District Court affirmed Level Propane's arbitration obligation. MarkWest has initiated an arbitration proceeding against Level Propane with the American Arbitration Association in Denver, Colorado seeking recovery of unpaid amounts owed by Level Propane for propane product received from MarkWest. Level Propane has filed a counterclaim in the arbitration proceeding seeking an award of $150,000 in actual damages and unspecified punitive damages. The agreements between the parties contain limitation of liability provisions, including a prohibition on recovery of punitive damages, and MarkWest believes that Level's breach of contract claim has no merit.

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

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Information

        Statements included in this Management's Discussion and Analysis 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's natural gas exploration and production activities will not occur or be successful;

•

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

•

competition from other NGL processors, including major energy companies;

•

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

•

winter weather conditions;

•

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

•

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

•

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.

Results of Operations

Three Months Ended March 31, 2002 Compared to the Three Months Ended March 31, 2001

Overview

        Net income was $0.2 million, or $0.02 per share, for the three months ended March 31, 2002, compared to $1.5 million, or $0.17 per share, for the three months ended March 31, 2001, a decrease of $1.3 million, or 88%. Earnings before interest, income taxes, depreciation, depletion and amortization (EBITDA) were $7.3 million for the three months ended March 31, 2002, compared to $4.8 million for the three months ended March 31, 2001, an increase of $2.5 million, or 51%.

        The decrease in net income was principally attributable to:

•

lower processing margins in our GPM segment. Reduced NGL product prices in 2002, partially offset by increased NGL product sales volumes and improved results from our terminals, were the primary causes for reduced margins.

•

an after tax, non-cash write-off of $0.5 million in deferred financing costs related to the March 29, 2002 amendment to our credit facility.

Operating Data

        Gas gathering, processing and marketing revenues.    Gas gathering, processing and marketing revenues were $37.7 million for the three months ended March 31, 2002, compared to $85.5 million for the three months ended March 31, 2001, a decrease of $47.8 million, or 56%. GPM revenues decreased primarily due to the following:

•

gas marketing revenues decreased $32.6 million, principally due to decreases in the volume and price of natural gas sold.

•

a decrease in our average Appalachian NGL product sales price, which accounted for $16.9 million of the overall decrease. Our average Appalachian NGL product sales price was $0.43 per gallon for the three months ended March 31, 2002, compared to $0.72 per gallon for the three months ended March 31, 2001, a decrease of $0.29 per gallon, or 40%. Average sale prices for NGL products decreased due to warmer winter weather during 2002 and lower crude oil prices.

•

the above decreases were partially offset by record NGL product sales volumes (increased GPM revenues $4.1 million) and the addition of our Canadian midstream operations during 2002 (increased GPM revenues $0.4 million).

        Exploration and production revenues.    Exploration and production revenues were $7.1 million for the three months ended March 31, 2002, compared to $3.0 million for the three months ended March 31, 2001, an increase of $4.1 million, or 138%. E&P revenues increased primarily due to our August 2001 E&P Canadian acquisition and subsequent drilling success, which have added 21,000 Mcfe/d of production. Our capital program in the U.S. has also yielded an additional 1,600 Mcfe/d of production since the first quarter of 2001. Our volume increases have been partially offset by price decreases.

        Cost of sales.    Cost of sales were $29.0 million for the three months ended March 31, 2002, compared to $75.8 million for the three months ended March 31, 2001, a decrease of $46.8 million, or 62%. Cost of sales decreased in 2002 primarily due to the following:

•

gas marketing cost of goods sold decreased $32.3 million due to decreases in the volume and price of natural gas sold.

•

a decrease in our average Appalachian natural gas replacement costs, which accounted for $10.3 million of the overall decrease. Our replacement natural gas cost was $0.32 per NGL gallon equivalent for the three months ended March 31, 2002 compared to $0.54 per NGL gallon equivalent for the three months ended March 31, 2001, a decrease of $0.22 per NGL gallon equivalent, or 41%.

•

a decrease in our average Appalachian NGL prices, which accounted for $2.7 million of the overall decrease. Reduced average Appalachian NGL prices reduced the percent of proceeds remitted to an Appalachian producer.

•

record Appalachian NGL product sales offset the above decreases by $3.4 million.

        Operating expenses.    Operating expenses were $5.7 million for the three months ended March 31, 2002, compared to $5.3 million for the three months ended March 31, 2001, an increase of $0.4 million, or 8%. The increase was principally caused by our August 2001 Canadian E&P acquisition.

        Selling, general and administrative expenses.    Selling, general and administrative expenses were $2.8 million for the three months ended March 31, 2002, compared to $2.4 million for the three months ended March 31, 2001, an increase of $0.4 million, or 17%. The increase was principally caused by increased expenses related to operating the business of our August 2001 Canadian E&P acquisition.

        Depreciation, depletion and amortization.    Depreciation, depletion and amortization were $5.2 million for the three months ended March 31, 2002, compared to $1.6 million for the three months ended March 31, 2001, an increase of $3.6 million, or 222%. The increase was principally the result of our August 2001 Canadian E&P acquisition.

        Interest expense.    Interest expense was $1.1 million for the three months ended March 31, 2002, compared to $0.8 million for the three months ended March 31, 2001, an increase of $0.2 million, or 27%. Our increased debt level, a result of our August 2001 Canadian E&P acquisition, principally caused the increase.

        Write-off of deferred financing costs.    We wrote off $0.7 million in deferred financing costs as a result of our March 29, 2002 credit facility amendment.

Liquidity and Capital Resources

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

        On January 31, 2002, MarkWest Energy Partners, L.P., a newly formed limited partnership (the MLP) created to own and operate most of our gathering, processing, transportation, storage, and fractionation assets in Appalachia and Michigan, filed a registration statement on Form S-1 with the Securities and Exchange Commission for an initial public offering. On March 22, 2002, April 16, 2002, April 25, 2002, May 1, 2002 and May 8, 2002, we filed amendments to this Form S-1. We currently anticipate offering to the public approximately 40% of the limited partner interests in the partnership. We and certain of our affiliates will own the general partner of the partnership, as well as the remaining 60% of the limited partner interests in the form of subordinated units. The rights of the holders of subordinated units to receive distributions of cash from the partnership are subordinated to the rights of the public unitholders to receive such distributions. In connection with the offering, we will enter into a number of contracts with the partnership pursuant to which we will pay it fees for providing us with gathering, processing, transportation, storage, and fractionation services. We will retain the risks and benefits associated with our "keep-whole" contracts in Appalachia. Proceeds we receive from the offering will be used to reduce our outstanding debt. We anticipate that the limited partnership will enter into a separate credit facility, the proceeds of which will be used to support the limited partnership's operations. For financial reporting purposes, the results of operations of MarkWest Energy Partners, L.P. will be consolidated with our operating results. The completion of the offering is subject to numerous conditions, including market conditions, and we can provide no assurance that it will be successfully completed. A registration statement relating to the proposed offering has been filed with the Securities and Exchange Commission but has not yet become effective. The securities may not be sold, nor may offers to buy be accepted prior to the time the registration statement becomes effective. The information contained in this Form 10-Q with respect to this offering shall not constitute an offer to sell or a solicitation of an offer to buy these securities.

        Absent the proceeds from the MLP's initial public offering, our 2002 capital program may need to be reduced, depending on commodity price levels and our operating performance, and our credit facility may need to be amended. Our 2002 capital expenditures are largely discretionary and concentrated in our E&P business segment.

Cash Flows

        Net cash provided by operating activities was $19.1 million and $10.0 million for the three months ended March 31, 2002 and 2001, respectively. Net cash provided by operating activities increased during the first quarter of 2002 due to (a) greater cash flows from operating activities and (b) timing of cash receipts and disbursements.

        Net cash used in investing activities was $9.1 million and $9.5 million for the three months ended March 31, 2002 and 2001, respectively. Capital expenditures for each period presented were comparable.

        Net cash used in financing activities was $12.0 million for the three months ended March 31, 2002. Net cash provided by financing activities was $1.1 million for the three months ended March 31, 2001. We paid down our debt a net $11.8 million during the first quarter of 2002 whereas we borrowed a net $1.0 million during the first quarter of 2001.

Capital Requirements

        MarkWest forecasts a baseline capital budget of $26 million for 2002. In our GPM segment, $3 million is for the next phase of our Canadian midstream infrastructure. In our E&P segment, $10 million is for our Canadian capital program, $7 million is for our Rocky Mountain capital program and $4 million for our Michigan capital program. Another $2 million is for company-wide maintenance capital and other capital programs. Our baseline capital budget is principally discretionary and may change contingent upon a number of factors, including our results of operations and opportunities.

Financing Facilities

        On March 29, 2002, we amended our credit agreement with various financial institutions. The $120 million credit facility is comprised of $80 million in revolving lines of credit ($45 million under a U.S. facility and $35 million under a Canadian facility) and a $40 million term loan under the U.S. facility. The U.S. facility matures August 2004 and the Canadian facility matures October 2007. The amended credit facility includes a borrowing base, calculated semiannually, which is based principally on oil and gas properties and midstream assets (initially determined to be $100 million), plus a working capital borrowing base, calculated monthly, which is based on NGL product accounts receivable and inventory levels, to a maximum of $20 million. In the future, actual borrowing limits may be less than $120 million, depending on proved reserves for our properties, our working capital and our financial covenants.

        The credit facility permits us to borrow money using either a base rate loan or a London Interbank Offered Rate (LIBOR) loan option, plus an applicable margin of between 0.375% and 2.75%, based on a certain debt to earnings ratio. We pay fees of between 0.25% and 0.50% per annum on the unused commitment, based on our debt to earnings ratio. The credit facility is secured by a first lien on substantially all of our assets. The loan agreement restricts certain activities, including incurrence of additional indebtedness, and requires the maintenance of certain financial ratios and other conditions. During May 2002, we signed an amendment to the credit facility for the period from March 31, 2002 through June 15, 2002, pending completion of our subsidiary MarkWest Energy Partners, L.P.'s initial public offering. Our maximum leverage ratio was maintained at 4.00 (rather than being reduced to 3.75) and our minimum fixed charge coverage ratio (fixed charges defined to include not only interest costs, but also maintenance capital expenditures and 12.5 percent of outstanding debt) was decreased to a minimum of 1.30 (down from 1.50 previously and 1.40 at December 31, 2001). At March 31, 2002, we had $100.9 million outstanding under the credit facility bearing interest at a weighted average rate of 4.275%.

        During the second quarter of 2002, an additional write-down of deferred financing costs will be required upon consummation of the MLP initial public offering and the associated amendment to our credit facility.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

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

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

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

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

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

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

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

        As of March 31, 2002, under our historical hedging practice, the hedged Appalachian NGL product sales volumes and associated projected margin per NGL product gallon, were as follows:

Table I
Hedged Processing Margin

        Under our new hedging strategy, we hedge our NGL product sales by selling forward propane or crude oil. As of March 31, 2002, we hedged Appalachian and Michigan NGL product sales as follows:

Table II
Hedged Sales Price for NGL Products

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

        Also within our GPM segment, for certain Appalachian natural gas sales, as of March 31, 2002, we hedged 487,000 MMBtu and 54,000 MMBtu at $4.09 per MMBtu for 2002 and 2003, respectively.

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

        In our E&P segment, under our historical hedging strategy we hedged our exposure to changes in market prices for our natural gas production by selling fixed-for-float swaps and utilizing costless collars. Historically, we hedged a significant portion of our natural gas production. In light of our natural hedge, we are transitioning our hedging strategy to limit our hedges to E&P natural gas production in excess of natural gas purchase requirements in our GPM segment. As of March 31, 2002, we hedged natural gas volumes and prices as follows:

Table III
Hedged Natural Gas Sales

(1)

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

        We enter into speculative transactions on an infrequent basis. Specific approval by the Board of Directors is necessary prior to executing such transactions. Speculative transactions are marked to market at the end of each accounting period, and any gain or loss is recognized in income for that period. There were no such speculative activities for the three months ended March 31, 2002 and 2001.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

        Reference is made to Note 4 to the Consolidated Financial Statements included earlier in this Form 10-Q.

Item 6. Exhibits and Reports on Form 8-K

(a)

Exhibits

11—Statement regarding computation of earnings per share.

18—Letter regarding change in accounting principle.

(b)

Reports on Form 8-K

A report on Form 8-K was filed on January 4, 2002; MarkWest Hydrocarbon, Inc. announces promotions and retirement.

A report on Form 8-K was filed on January 31, 2002; MarkWest Hydrocarbon, Inc. announces the filing of a registration statement for sale of common units in MarkWest Energy Partners, L.P.

A report on Form 8-K was filed on March 13, 2002; MarkWest Hydrocarbon, Inc. announces settlement agreements related to lawsuits filed in February 2001.

SIGNATURE

        Pursuant to the requirements of the Securities Exchange Act of 1934, MarkWest, as registrant, had this report signed on our behalf by the undersigned, who has been duly authorized.