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

FORM 10-Q

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

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 8,519,482 shares of common stock, $.01 per share par value, outstanding as of June 30, 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
(in thousands, except share and per share data)

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

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MARKWEST HYDROCARBON, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(UNAUDITED)
(in thousands, except per share data)

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

2

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

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

3

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

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

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

1.    General

        The consolidated financial statements include the accounts of MarkWest Hydrocarbon, Inc. ("MarkWest Hydrocarbon") 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.    Initial Public Offering of MarkWest Energy Partners, L.P. and Related Transactions

        On May 24, 2002, MarkWest Hydrocarbon conveyed most of the assets, liabilities and operations of our midstream business to MarkWest Energy Partners, L.P. (the "Partnership") 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);



•

The direct and indirect assumption of certain liabilities by the Partnership, including $1.8 million in working capital liabilities and $19.4 million of indebtedness;



•

The right to be reimbursed by the Partnership for $15.6 million of capital expenditures; and



•

The right to receive $26.7 million in cash upon the closing of the IPO and MarkWest Energy Operating Company, L.L.C.'s (the "Operating Partnership") new $60 million credit facility. The Operating Partnership is a wholly owned subsidiary of the Partnership.

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

        MarkWest Hydrocarbon's cash consideration totaled $63.5 million, which was funded by proceeds from the IPO and by Partnership borrowings under its credit facility. We used the cash to repay bank indebtedness.

        The common units have preference over the subordinated units with respect to cash distributions and, accordingly, we accounted for the sale of the common units as a sale of a minority interest. At the

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time our subordinated units convert to common units, we will recognize any gain or loss computed at that time, as paid-in capital. Our subordinated units automatically convert to common units on June 30, 2009, but a portion of the subordinated units may convert on or after June 30, 2005 if the Partnership meets certain financial tests, namely operating surpluses that exceed the minimum quarterly distributions, as defined in the partnership agreement.

        Immediately after the IPO, MarkWest Hydrocarbon sold an 8.6% interest in MarkWest Energy GP, L.L.C., the general partner of the Partnership, and 24,864 of its Partnership subordinated units, representing a 0.4% limited partner interest in the Partnership, to certain officers and key employees of MarkWest Hydrocarbon for $183,497 and $407,770, respectively. The officers and employees paid approximately 30% of the purchase price in cash and financed the remainder via loans from MarkWest Hydrocarbon. The loans are formalized by non-recourse promissory notes requiring the principal balance to be repaid no later than June 30, 2009 and bearing interest at the rate of 7% per annum on the unpaid balance. For each transaction, we recognized a $64,000 gain on the purchase price in excess of our book value to the extent that the purchase price was paid in cash, approximately $186,000. The remaining balance was recorded as deferred income and is included in accrued liabilities on our balance sheet.

        MarkWest Hydrocarbon owns 91.4% of the general partner, and MarkWest Hydrocarbon thereby controls the Partnership. The subordinated units owned by MarkWest Hydrocarbon comprise 54.9% of the Partnership's limited partner interests. Together, these interests represent an approximate 56% ownership interest. The Partnership's results are included in our consolidated financial statements. The minority interest in consolidated subsidiary on the consolidated balance sheet represents the minority (non-MarkWest Hydrocarbon) shareholders' investment in the Partnership plus the minority shareholders' share of the net income of the Partnership since its initial public offering on May 24, 2002. Minority interest in net income of consolidated subsidiary in the consolidated statement of income represents the minority shareholders' share of the net income of the Partnership.

        On August 6, 2002, the Partnership declared a quarterly cash distribution of $0.21 per unit, payable August 15, 2002, to common and subordinated unitholders of record on August 13, 2002, and the general partner.

3.    Long-term Debt

MarkWest Hydrocarbon, Inc.

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

        Available borrowings under the Credit Facility are determined by (i) a borrowing base, calculated semiannually, which is based principally on the proved reserves of our oil and gas properties (initially determined to be $34 million); and (ii) a working capital borrowing base, calculated monthly, which is based on NGL product accounts receivable and inventory levels, to a maximum of $20 million. At June 30, 2002, the working capital borrowing base was $8.7 million providing total available borrowings of $42.7 million. Actual borrowing limits may be less than $60 million, and MarkWest Hydrocarbon may be required to pay down amounts borrowed in excess of their applicable borrowing base, depending on proved reserves for our properties, our working capital and our financial covenants. At June 30, 2002, MarkWest Hydrocarbon had outstanding borrowings of $38.5 million under the Credit Facility.

        The Credit Facility permits us to borrow money using either a base rate loan, plus an applicable margin of 0.375% and 1.375%, or a London Interbank Offered Rate ("LIBOR") loan option, plus an applicable margin of between 1.75% and 2.75%, based on a certain debt-to-earnings ratio. We pay fees

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of between 0.25% and 0.50% per annum on the unused commitment, based on our debt-to-earnings ratio. The Credit Facility matures in August 2004. For the three months ended June 30, 2002, the weighted average interest rate was 3.6%.

        The Credit Facility contains various covenants limiting our ability to:

•

incur indebtedness;



•

grant certain liens;



•

make certain investments or payments;



•

enter into certain leases;



•

enter into a merger or consolidation;



•

dispose of assets;



•

amend or enter into certain agreements; and



•

conduct preferential transactions with certain affiliates.

        The Credit Facility also contains covenants requiring us to maintain:

•

a minimum tangible net worth;



•

a ratio of not less than 1.00:1.00 of current assets to current liabilities;



•

a ratio of not more than 3.5:1.00 of Total Funded Debt (as defined in the Credit Facility) to EBITDA (as defined in the Credit Facility) for the four most recently completed fiscal quarters, reducing to 3.25 as of September 30, 2002 and to 3.0 as of December 31, 2002 and thereafter; and



•

a ratio of not less than 3.50:1.00 of EBITDA to interest expense, each for the four most recently completed fiscal quarters.

        The Credit Facility is secured by a first lien on substantially all of our assets.

MarkWest Energy Partners, L.P.

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

        Under the revolving credit facility, up to $28.6 million is available to fund capital expenditures and acquisitions and up to $10 million is available for working capital purposes (including letters of credit) and to fund distributions to unitholders. However, not more than $2.25 million may be used in any four-quarter period to fund distributions to unitholders. On May 24, 2002, the date our IPO closed, $21.4 million was drawn under the term loan. At June 30, 2002, $21.4 million was outstanding under the Partnership Credit Facility. Total credit available to be drawn at June 30, 2002 was approximately $46 million.

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

        Indebtedness under the credit facility bears interest, at the Operating Partnership's option, at either (i) the higher of the federal funds rate plus 0.50% or the prime rate as announced by lender plus an applicable margin of 0.375% to 1.375% or (ii) at a rate equal to LIBOR plus an applicable

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margin ranging from 1.75% per annum to 2.75% per annum depending on the Partnership's ratio of Funded Debt (as defined in the Partnership Credit Facility) to EBITDA (as defined in the Partnership Credit Facility) for the four most recently completed fiscal quarters. The Operating Partnership incurs a commitment fee on the unused portion of the credit facility at a rate ranging from 25.0 to 50.0 basis points based upon the ratio of our Funded Debt to EBITDA for the four most recently completed fiscal quarters. The Partnership Credit Facility matures in May 2005. At that time, both the revolving and term loan credit facilities will terminate and all outstanding amounts thereunder will be due and payable.

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

•

incur indebtedness;



•

grant certain liens;



•

make certain loans, acquisitions and investments;



•

amend our material agreements, including agreements with MarkWest Hydrocarbon;



•

acquire another company;



•

enter into a merger, consolidation or sale of assets; or



•

make distributions in excess of Available Cash (as defined in the Partnership Agreement) for the preceding fiscal quarter.

        The Partnership Credit Facility also contains covenants requiring the Operating Partnership to maintain:

•

a ratio of not less than 3.50:1.00 of EBITDA to interest expense for the prior fiscal quarter;



•

a ratio of not more than 3.50:1.00 of total debt to EBITDA for the prior fiscal quarter; and



•

a minimum net worth of $40 million, subject to adjustment for equity issuances.

        The Partnership and the subsidiaries of the Operating Partnership serve as joint and several guarantors of any obligations under the Partnership Credit Facility. The guarantees are full and unconditional. The Partnership Credit Facility is secured by substantially all the assets of the Partnership and its subsidiaries.

4.    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 principally through our consolidated subsidiary, MarkWest Energy Partners, L.P.; 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 second quarter of 2002 and 2001 and for the six months ended June 30, 2002 and 2001. Operating income for each segment includes total revenues less product purchases, plant operating expenses, lease operating expenses, transportation costs, production taxes, and depreciation, depletion and amortization. Segment operating income excludes selling, general and administrative expenses, interest

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income, interest expense, write-down of deferred financing costs, gain on sale to related party, minority interest in net income of consolidated subsidiary 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:

5.    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.

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        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 Hydrocarbon 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 Hydrocarbon. The United States District Court affirmed Level Propane's arbitration obligation. MarkWest Hydrocarbon 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 Hydrocarbon. 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 Hydrocarbon believes that Level's breach of contract claim has no merit. On June 6, 2002, an Involuntary Petition in Bankruptcy was filed against Level Propane in the United States Bankruptcy Court for the Northern District of Ohio, Eastern Division. Level Propane has consented to the Petition and the arbitration proceeding is now subject to the automatic stay against adverse claims provided for by the Bankruptcy Code. MarkWest Hydrocarbon will file an appropriate proof of claim.

        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 Hydrocarbon'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 Hydrocarbon removed that action to the United States District Court for the Eastern District of Kentucky, Ashland Division. MarkWest Hydrocarbon 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 Hydrocarbon in full and final satisfaction of any additional payments claimed to have been due. MarkWest Hydrocarbon filed a motion for summary judgment based on that accord and satisfaction. The motion was denied on the ground that a fact based dispositive motion was premature prior to discovery. MarkWest Hydrocarbon anticipates renewing its motion for summary judgment after discovery has been completed. A pretrial conference has been scheduled for April 12, 2003.

6.    Recent Accounting Pronouncements

        In April 2002, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 145; Rescission of FAS Statements No. 4, 44 and 64; Amendment of FAS Statement No. 13; and Technical Corrections ("FAS 145"), which is generally effective for transactions occurring after May 15, 2002. Through the rescission of FAS Statements 4 and 64, FAS No. 145 eliminates the requirement that gains and losses from extinguishment of debt be aggregated and, if material, be classified as an extraordinary item net of any income tax effect. FAS No. 145 made several other technical corrections to existing pronouncements that may change accounting practice. FAS No. 145 will have no impact on our results of operations or financial position.

        In June 2002, the FASB issued Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or Disposal Activities ("FAS No. 146"). FAS 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 Emerging Issues Task Force ("EITF") Issue No. 94-3, "Liability Recognition for Certain Employee Termination

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Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." We do not believe that FAS 146 will have a material impact on our results of operations or financial position.

7.    Change in Inventory Accounting Method

        For the quarter ended March 31, 2002, the cost of 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 (loss) before income taxes, net income (loss) and basic earnings (loss) per share would have been as follows for the three and six months ended June 30, 2001, on a pro forma basis (in thousands):

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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 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;

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•

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;



•

our ability to manage the risks inherent in drilling wells; and



•

the ability of the Partnership to make distributions to MarkWest Hydrocarbon and the other limited partners.

        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.

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. (the "Partnership" or "MarkWest Energy Partners") 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 $44 million. Concurrent with the 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 Hydrocarbon viewed the creation of MarkWest Energy Partners as important to its ability to continue the growth of its gathering and processing business by accessing a lower cost form of equity capital. The reduction in bank debt was important as well in reducing MarkWest Hydrocarbon's ratio of debt to total capitalization.

        MarkWest Hydrocarbon now owns a 91.4% interest in MarkWest Energy GP, L.L.C., the Partnership's general partner. Officers of the general partner and officers and key employees of MarkWest Hydrocarbon purchased the remaining 8.6% interest in MarkWest Energy GP, L.L.C. MarkWest Energy GP, L.L.C., owns the 2% general partner interest in the Partnership, as well as the incentive distribution rights. Through the general partner, we are entitled to distributions on our general partner interest and, if any, on its incentive distribution rights.

        MarkWest Hydrocarbon, Inc., now owns 2,975,136 subordinated units and officers of the general partner and officers and key employees of MarkWest Hydrocarbon purchased an aggregate of 24,864 subordinated units, representing 54.9% and 0.5% limited partner interests in the Partnership, respectively. Combined with the general partner interest, MarkWest Hydrocarbon owns an aggregate 55.7% interest in the Partnership and officers and key employees own an aggregate 0.6% interest. Common units have preference over the subordinated units with respect to cash distributions.

        MarkWest Hydrocarbon's consolidated financials statements, beginning May 24, 2002, will include 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.

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Results of Operations

Operating Data

Three Months Ended June 30, 2002 Compared to the Three Months Ended June 30, 2001

        Overview.    Net loss was $2.1 million for the three months ended June 30, 2002, compared to net income of $8,000 for the three months ended June 30, 2001. Income from operations in our Appalachia, Michigan and Rocky Mountain core areas approximated 2001 amounts as volume increases were offset by lower average sales prices. Increased depreciation, depletion and amortization and selling, general and administrative expenses offset income from our Canadian operations. Additionally, we wrote down $2.3 million in deferred financing costs as a result of our May 24, 2002 credit facility amendment.

        Gas gathering, processing and marketing revenues.    Gas gathering, processing and marketing revenues were $39.0 million for the three months ended June 30, 2002, compared to $28.5 million for the three months ended June 30, 2001, an increase of $10.5 million, or 37%. Higher sales volumes out of our Siloam fractionator in 2002 were largely offset by decreased average sales prices. Increased gas marketing transaction volume primarily accounted for the overall increase. Our gas marketing activities are a high volume, low margin business executed in support of our midstream operations.

        Exploration and production revenues.    Exploration and production revenues were $7.4 million for the three months ended June 30, 2002, compared to $2.5 million for the three months ended June 30, 2001, an increase of $4.9 million, or 200%. E&P revenues increased primarily due to our August 2001 E&P Canadian acquisition and subsequent drilling success, which have added approximately 19,900 Mcfe/d of production. Our capital program in the U.S. has yielded an additional 2,100 Mcfe/d of production since the second quarter of 2001. Our volume increases have been partially offset by price decreases.

        Purchased gas costs.    Purchased gas costs were $32.3 million for the three months ended June 30, 2002, compared to $22.5 million for the three months ended June 30, 2001, an increase of $9.8 million, or 43%. The gas costs associated with higher sales volumes out of our Siloam fractionator in 2002 were

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partly offset by lower average product costs. Increased gas marketing transaction volume primarily accounted for the overall increase. Our gas marketing activities are a high volume, low margin business executed in support of our midstream operations.

        Plant operating expenses.    Plant operating expenses were $3.9 million for the three months ended June 30, 2002, compared to $3.5 million for the three months ended June 30, 2001, an increase of $0.4 million, or 11%. The increase was principally caused by increased production volumes.

        Lease operating expenses.    Lease operating expenses were $1.7 million for the three months ended June 30, 2002, compared to $0.6 million for the three months ended June 30, 2001, an increase of $1.1 million, or 203%. Lease operating expense increased in 2002 primarily due to the addition of our Canadian operations in August 2001.

        Transportation costs.    Transportation costs were $0.4 million for the three months ended June 30, 2002, compared to $0.2 million for the three months ended June 30, 2001, an increase of $0.2 million, or 112%. The increase was principally caused by the addition of our Canadian operations in August 2001.

        Production taxes.    Production taxes were $0.5 million for the three months ended June 30, 2002, compared to $0.2 million for the three months ended June 30, 2001, a increase of $0.3 million, or 198%. Production taxes increased in 2002 primarily due to the addition of our Canadian operations in August 2001.

        Selling, general and administrative expenses.    Selling, general and administrative expenses were $2.7 million for the three months ended June 30, 2002, compared to $1.9 million for the three months ended June 30, 2001, an increase of $0.9 million, or 47%. Expenses related to operating the business of our August 2001 Canadian E&P acquisition principally caused the increase.

        Depreciation, depletion and amortization.    Depreciation, depletion and amortization were $4.9 million for the three months ended June 30, 2002, compared to $1.6 million for the three months ended June 30, 2001, an increase of $3.4 million, or 213%. The increase was principally the result of the addition of our Canadian E&P operations in August 2001 and our increased production. As we continue to drill and develop our acreage in Canada, we expect our depletion rate per unit of production to decrease.

        Interest expense.    Interest expense was $1.2 million for the three months ended June 30, 2002, compared to $0.6 million for the three months ended June 30, 2001, an increase of $0.5 million, or 84%. Additional debt incurred in connection with the financing of our August 2001 Canadian acquisition was the primary reason for the increase.

        Write-off of deferred financing costs.    We wrote off $2.3 million in deferred financing costs as a result of our May 24, 2002 credit facility amendment, which was completed concurrently with the initial public offering of our consolidated subsidiary, MarkWest Energy Partners, L.P.

        Minority interest.    Minority interest in consolidated subsidiary represents the public unitholders' interest in MarkWest Energy Partners, L.P., which completed its initial public offering on May 24, 2002.

Six Months Ended June 30, 2002 Compared to the Six Months Ended June 30, 2001

        Overview.    Net loss was $1.9 million for the six months ended June 30, 2002, compared to net income of $1.5 million for the six months ended June 30, 2001. Income from operations in our Appalachia, Michigan and Rocky Mountain core areas decreased compared to 2001 amounts, as volume increases were more than offset by lower average sales prices. Increased depreciation, depletion and amortization and selling, general and administrative expenses offset income from our Canadian

15

operations. Additionally, we wrote down $3.0 million in deferred financing costs as a result of our May 24, 2002 credit facility amendment.

        Gas gathering, processing and marketing revenues.    Gas gathering, processing and marketing revenues were $76.7 million for the six months ended June 30, 2002, compared to $114.1 million for the six months ended June 30, 2001, a decrease of $37.3 million, or 33%. GPM revenues decreased primarily due to:

•

In Appalachia, significantly lower average sales prices in 2002 partially offset by higher sales volumes, resulted in a net decrease of $13.3 million.



•

Reduced sales prices and volumes in our 2002 gas marketing operations resulted in a $24.7 million decrease in revenues. Gas marketing is a high volume, low margin operation conducted in support of our midstream business.

        Exploration and production revenues.    Exploration and production revenues were $14.4 million for the six months ended June 30, 2002, compared to $5.4 million for the six months ended June 30, 2001, an increase of $9.0 million, or 166%. E&P revenues increased primarily due to our August 2001 E&P Canadian acquisition and subsequent drilling success, which together have added 20,300 Mcfe/d of production. Our capital program in the U.S. has also yielded an additional 2,000 Mcfe/d of production since the second quarter of 2001. Our volume increases have been partially offset by price decreases.

        Purchased gas costs.    Purchased gas costs were $60.3 million for the six months ended June 30, 2002, compared to $98.1 million for the six months ended June 30, 2001, a decrease of $37.7 million, or 38%. Purchased gas costs decreased in 2002 primarily due to the following:

•

In Appalachia, significantly lower average purchase costs in 2002 partially offset by higher sales volumes, resulted in a net decrease of $12.0 million.



•

Reduced purchase prices and volumes in our 2002 gas marketing operations resulted in a $25.0 million decrease in purchased gas costs. Gas marketing is a high-volume, low-margin operation completed in support of our midstream business.

        Plant operating expenses.    Plant operating expenses were $8.3 million for the six months ended June 30, 2002, compared to $8.1 million for the six months ended June 30, 2001, an increase of $0.2 million, or 3%.

        Lease operating expenses.    Lease operating expenses were $3.3 million for the six months ended June 30, 2002, compared to $1.1 million for the six months ended June 30, 2001, an increase of $2.2 million, or 202%. Lease operating expense increased in 2002 primarily due to the addition of our Canadian operations in August 2001.

        Transportation costs.    Transportation costs were $0.7 million for the six months ended June 30, 2002, compared to $0.3 million for the six months ended June 30, 2001, an increase of $0.4 million, or 124%. The increase was principally caused by the addition of our Canadian operations in August 2001.

        Production taxes.    Production taxes were $0.8 million for the six months ended June 30, 2002, compared to $0.5 million for the six months ended June 30, 2001, an increase of $0.3 million, or 65%. Production taxes increased in 2002 primarily due to the addition of our Canadian operations in August 2001.

        Selling, general and administrative expenses.    Selling, general and administrative expenses were $5.6 million for the six months ended June 30, 2002, compared to $4.3 million for the six months ended June 30, 2001, an increase of $1.3 million, or 30%. Expenses related to operating the business of our August 2001 Canadian E&P acquisition principally caused the increase.

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        Depreciation, depletion and amortization.    Depreciation, depletion and amortization were $10.1 million for the six months ended June 30, 2002, compared to $3.2 million for the six months ended June 30, 2001, an increase of $6.9 million, or 218%. The increase was principally the result of our August 2001 Canadian E&P acquisition and our increased production. As we continue to drill and develop our acreage in Canada, we expect our depletion rate per unit of production to decrease.

        Interest expense.    Interest expense was $2.2 million for the six months ended June 30, 2002, compared to $1.5 million for the six months ended June 30, 2001, a increase of $0.8 million, or 52%. Additional debt incurred in connection with the financing of our August 2001 Canadian acquisition was the primary reason for the increase.

        Write-off of deferred financing costs.    We wrote off $2.9 million in deferred financing costs as a result of two amendments to our credit facility through June 30, 2002, which was completed concurrently with the initial public offering of our consolidated subsidiary, MarkWest Energy Partners, L.P.

        Minority interest.    Minority interest in consolidated subsidiary represents the public unitholders' interest in MarkWest Energy Partners, L.P., which completed its initial public offering on May 24, 2002.

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.. We may also use operating leases to finance support equipment.

        Two material changes regarding our financial condition occurred during the second quarter of 2002. First, on May 24, 2002, MarkWest Energy Partners, L.P. completed its initial public offering of 2,415,000 units. In return for conveying most of the assets, liabilities and operations of our midstream business to the Partnership, we received $63.5 million in cash, among other considerations. We used $63.0 million of the proceeds received to reduce our bank indebtedness. The partnership borrowed $21.4 million on May 24, 2002, and these borrowings are included in long-term debt on our consolidated balance sheet. You should read Note 2 in Notes to Consolidated Financial Statements in Item 1 included in this Form 10-Q for further information.

        Second, contemporaneous with the Partnership's IPO, we amended our credit facility, and the Partnership entered into its own separate credit facility. You should read Note 3 in Notes to Consolidated Financial Statements in Item 1 included in this Form 10-Q for further information.

        We believe that cash generated from our operations, and our borrowing capacity will be sufficient to meet our working capital requirements and fund our required capital expenditures.

        Future capital expenditures are mostly discretionary and, in our exploration and production segment, will be increased or decreased with cash flow from operations and with MarkWest Hydrocarbon's borrowing base. 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. MarkWest Hydrocarbon's borrowing base is a function of our proved reserves (which are impacted by commodity prices and our drilling results), as well as its NGL marketing business's receivables and inventory levels. We are currently undergoing our semi-annual borrowing base redetermination, and the size of our capital program for the second half of 2002 is dependent on the redetermination, which is expected to be completed by the end of August 2002.

        As part of the formation of MarkWest Energy Partners, MarkWest Hydrocarbon retained its commodity price exposure to a variable processing margin (NGL revenues less natural gas costs, for about three-quarters of the Appalachian volumes). This variability has been reduced due to our

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increased natural gas production, as is further discussed in Item 3, Quantitative and Qualitative Disclosures about Market Risk.

        For the Partnership, future acquisitions or projects are expected to financed through a combination of debt and issuance of additional units, as is common practice with master limited partnerships.

Cash Flows

        Net cash provided by operating activities was $27.9 million and $14.0 million for the six months ended June 30, 2002 and 2001, respectively. Net cash provided by operating activities increased during the first six months 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 $13.1 million and $15.7 million for the six months ended June 30, 2002 and 2001, respectively. Capital expenditures were comparable for the periods presented.

        Net cash used in financing activities was $12.4 million in the first six months of 2002 compared to $3.2 million net cash provided by financing activities for the first six months of June 2001. During 2002, we were able to pay down our debt a net of $54.5 million, whereas in 2001, we borrowed an additional $3.0 million. We were able to pay down our debt in 2002 with the $43.7 million proceeds from the initial public offering of MarkWest Energy Partners, L.P., and from cash from operating activities in excess of capital spending.

Capital Requirements

        MarkWest Hydrocarbon projects capital expenditures of $28 million for 2002, of which we had spent $16.3 million as of June 30, 2002, principally in our E&P segment, of which $14 million is for our Canadian capital program, $7.5 million is for our Rocky Mountain capital program and $3 million is for our Michigan capital program. Another $2 million is for our gathering and processing segment's Canadian program. The balance is for company-wide maintenance capital and other capital programs. Our capital spending is principally discretionary and may change contingent upon a number of factors, including our results of operations and the semiannual borrowing base redetermination currently in progress as described above.

Financing Facilities

        On May 24, 2002, we amended our credit facility and the Partnership entered into a new credit facility. You should read Note 3 in Notes to Consolidated Financial Statements in Item 1 included in this Form 10-Q for further information. Credit availability is determined separately under each of the MarkWest Hydrocarbon and MarkWest Energy Partners credit facilities.

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Outlook

        Following are our best current estimates of third and fourth quarter 2002 results for MarkWest Hydrocarbon and MarkWest Energy Partners. Please be aware of the risk factors outlined above that could cause actual results to differ materially from these forward-looking numbers.

*

Does not include $50,000,000 for Canadian acquisition in August 2001.

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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 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 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. 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 GPM purchase location (Appalachia) and NYMEX. 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. As of June 30, 2002, our natural gas basis hedges were as follows:

Table I
Hedged Natural Gas Basis

        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

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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 II below). In our E&P segment, we historically hedged our natural gas sales (Table IV 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 III below).

        As of June 30, 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 II
Hedged Processing Margin

        Under our new hedging strategy, we hedge our NGL product sales by selling forward propane or crude oil. As of June 30, 2002, we hedged Appalachian and Michigan NGL product sales as follows:

Table III
Hedged Sales Price for NGL Products

        Under Tables II and III, 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 June 30, 2002, we hedged 324,000 MMBtu and 54,000 MMBtu at $4.09 per MMBtu for the balance of 2002 and 2003, respectively.

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        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 June 30, 2002, we hedged natural gas volumes and prices as follows:

Table IV
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 June 30, 2002 and 2001.

Interest Rate Risk

        We are exposed to changes in interest rates, primarily as a result of our long-term debt with floating interest rates. As of June 30, 2002, we are a party to contracts expiring June 7, 2004 to fix interest rates on $10.0 million of our debt at 5.28% compared to floating LIBOR, plus an applicable margin. As of June 30, 2002, the Partnership is a party to contracts expiring May 19, 2005 to fix interest rates on $8.0 million of our debt at 3.84% compared to floating LIBOR, plus an applicable margin.

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PART II OTHER INFORMATION

Item 1.    Legal Proceedings

        Reference is made to Note 5 to the Consolidated Financial Statements included earlier in this Form 10-Q.

Item 4.    Submission of Matters to a Vote of Security Holders

        At the Annual Meeting of Stockholders held on June 6, 2002, the following proposals were adopted by the margins indicated:

1.

To elect three Class III directors to hold office for a three-year term expiring at the Annual Meeting of Stockholders occurring in the year 2005 or until the election and qualification of their respective successors.

2.

To approve the amendment of the 1996 Stock Incentive Plan increasing the number of shares of common stock authorized for issuance from 850,000 to 925,000 shares.

3.

To approve the amendment of the 1996 Non-Employee Director Stock Option Plan increasing the number of shares of common stock authorized for issuance from 20,000 to 30,000.

4.

To ratify the selection of PricewaterhouseCoopers LLP as our independent accountants for the fiscal year ending December 31, 2002.

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Item 6.    Exhibits and Reports on Form 8-K

(a)

Exhibits

10.11*    Fifth Amended and Restated Credit Agreement among MarkWest Hydrocarbon, Inc., and various lenders dated May 24, 2002.

10.12*    Amended and Restated Credit Agreement among MarkWest Resources Canada Corp., and various lenders dated May 24, 2002.

11.*    Statement regarding computation of earnings per share.

99.1*    Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.2*    Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b)

Reports on Form 8-K

A report on Form 8-K was filed on May 21, 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/A was filed on May 28, 2002; Pro forma financial statements related to the Canadian acquisition of two companies in August 2001.

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SIGNATURE

        Pursuant to the requirements of the Securities Exchange Act of 1934, MarkWest Hydrocarbon, as registrant, has duly caused this report to be signed on its behalf by the undersigned, thereunto authorized.

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QuickLinks

Item 1. Consolidated Financial Statements

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk
PART II OTHER INFORMATION
Item 1. Legal Proceedings
Item 4. Submission of Matters to a Vote of Security Holders
Item 6. Exhibits and Reports on Form 8-K