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

FORM 10-Q

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 8,525,369 shares of common stock, $.01 per share par value, outstanding as of September 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

(UNAUDITED)

(in thousands, except share and per share data)

2

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

3

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.

4

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(UNAUDITED)

(in thousands)

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

5

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 permanent differences in Canada.

        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.

7

        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 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 gain on the purchase price in excess of our book value to the extent that the purchase price was paid in cash. 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 15, 2002, the Partnership paid a quarterly cash distribution of $0.21 per unit to common and subordinated unitholders of record on August 13, 2002, and the general partner. On October 22, 2002, the board of directors of the general partner of the Partnership declared the Partnership's quarterly cash distribution of $0.50 per unit for the third quarter of 2002. The distribution is payable November 14, 2002, to unitholders of record on October 31, 2002.

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 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.

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        The table below presents information about operating income for the reported segments for the three and nine months ended September 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 ("DD&A"). Segment operating income excludes selling, general and administrative expenses, interest 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.

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

4.    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 nine months ended September 30, 2001, on a pro forma basis (in thousands):

5.    Recent Accounting Pronouncements

        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

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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 should not have an impact on our financial position or results of operations.

        In July 2001, the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143"). SFAS No. 143 is effective for fiscal years beginning after June 15, 2002 (January 1, 2003 for MarkWest), and establishes an accounting standard requiring the recording of the fair value of liabilities associated with the retirement of long-lived assets in the period in which they are incurred. We are in the process of determining the future impact that the adoption of SFAS No. 143 may have on our earnings and financial position.

6.    Commitments and Contingencies

        We are involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims will not, individually or in the aggregate, have a material adverse effect on our financial position or results of operations.

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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 effectiveness of our NGL hedging activities;



•

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;

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•

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;



•

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

        Overview.    Our net loss was $3.2 million for the three months ended September 30, 2002, compared to a net loss of $0.2 million for the three months ended September 30, 2001. Cash flow from operating activities prior to changes in operating assets and liabilities was $3.0 million for the three months ended September 30, 2002, compared to $2.7 million for the three months ended September 30, 2001.

        In our GPM segment, we had record production at our Siloam fractionator. However, this was more than offset by the fact that NGLs traded at a historically low relationship to crude oil during the third quarter 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 after-tax less in revenue than had the historical relationship been realized.

        Second, in accordance with generally accepted accounting principles, we recorded a $1.0 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 highly 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. Excluding the non-cash hedging item, our net loss was $2.1 million for the three months ended September 30, 2002, compared to a net loss of $0.2 million for the three months ended September 30, 2001. Beginning September 2002, the relationship of NGL product prices to crude oil prices has improved substantially.

        In the third quarter of 2002, processing margins (excluding both items above) were less than the prior period. Finally, it is also important to note the seasonal aspect of our NGL marketing business—

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in the third quarter, NGL product sales are historically lower than in the fourth and first quarters (i.e., the winter months) as some NGL production is stored for winter sale.

        In the E&P segment in our U.S. operations, increased production was offset by lower average sales prices. Increased depreciation, depletion and amortization offset income from our Canadian operations.

        Gas gathering, processing and marketing revenues.    Gas gathering, processing and marketing revenues were $30.0 million for the three months ended September 30, 2002, compared to $28.3 million for the three months ended September 30, 2001, an increase of $1.7 million, or 6%. Revenues increased $0.9 million, due to increased sales volumes out of our Siloam fractionator in 2002, and $5.5 million, due to increased gas marketing transaction volume. Our gas marketing activities are a high-volume, low-margin business executed in support of our midstream operations. These increases were partially offset by decreased average NGL product sales prices out of Siloam, causing an overall decrease of $2.8 million, and a non-cash, hedging ineffectiveness charge of $1.9 million, as discussed above.

        Exploration and production revenues.    Exploration and production revenues were $7.7 million for the three months ended September 30, 2002, compared to $4.2 million for the three months ended September 30, 2001, an increase of $3.6 million, or 86%. E&P revenues increased primarily due to our August 2001 Canadian acquisition and subsequent drilling success in Canada, which have added approximately 11,800 Mcfe/d of average production. Our capital program in the U.S. has yielded an additional 4,000 Mcfe/d of average production during 2002. In the second quarter of 2002, we reported that our volumes had been constrained in Alberta, Canada due to higher than specification "dew point" (a small amount of NGLs in the natural gas caused this condition). We successfully resolved this issue at the north Bantry property by installing a small gas plant for $0.6 million in June 2002. In the third quarter of 2002, this condition surfaced at the south Bantry property due to our continued drilling success, and volumes again were constrained. We expect to resolve this issue through the installation of a $0.6 million plant at the south Bantry property.

        Purchased gas costs.    Purchased gas costs were $26.3 million for the three months ended September 30, 2002, compared to $21.6 million for the three months ended September 30, 2001, an increase of $4.8 million, or 22%. 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 September 30, 2002, compared to $3.8 million for the three months ended September 30, 2001, an increase of $0.1 million, or 3%.

        Lease operating expenses.    Lease operating expenses were $1.9 million for the three months ended September 30, 2002, compared to $1.3 million for the three months ended September 30, 2001, an increase of $0.6 million, or 50%. Lease operating expenses increased in 2002 primarily due to the addition of our Canadian operations in August 2001 and our increased Rocky Mountain production.

        Transportation costs.    Transportation costs were $0.5 million for the three months ended September 30, 2002, compared to $0.2 million for the three months ended September 30, 2001, an increase of $0.3 million, or 129%. The increase was caused by the addition of our Canadian operations in August 2001 and our increased Rocky Mountain production.

        Production taxes.    Production taxes were $0.7 million for the three months ended September 30, 2002, compared to $0.1 million for the three months ended September 30, 2001, an increase of $0.6 million. Production taxes increased in 2002 primarily due to the addition of our Canadian operations in August 2001 and our increased Rocky Mountain production.

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        Selling, general and administrative expenses.    Selling, general and administrative expenses ("SG&A") were $2.7 million for the three months ended September 30, 2002, compared to $1.9 million for the three months ended September 30, 2001, an increase of $0.8 million, or 40%. SG&A increased $0.2 million due to the incremental public company costs associated with our fully consolidated subsidiary, MarkWest Energy Partners, L.P. SG&A also increased $0.2 million due to our August 2001 Canadian E&P acquisition.

        Depreciation, depletion and amortization.    Depreciation, depletion and amortization were $5.6 million for the three months ended September 30, 2002, compared to $3.1 million for the three months ended September 30, 2001, an increase of $2.5 million, or 80%. 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 $0.8 million for the three months ended September 30, 2002, compared to $1.1 million for the three months ended September 30, 2001, a decrease of $0.4 million, or 33%. A reduction in debt, coupled with lower average interest rates, caused the decrease

        Gain on sale to related party.    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 recognize a gain on the purchase price in excess of our book value to the extent that the purchase price was paid in cash, approximately $77,000 during the third quarter. The remaining balance of $328,000 was recorded as deferred income and is included in accrued liabilities on our balance sheet.

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

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Nine Months Ended September 30, 2002 Compared to the Nine Months Ended September 30, 2001

        Overview.    Net loss was $5.1 million for the nine months ended September 30, 2002, compared to net income of $1.3 million for the nine months ended September 30, 2001. Cash flows from operating activities prior to changes in operating assets and liabilities was $13.1 million for the nine months ended September 30, 2002, compared to $8.0 million for the nine months ended September 30, 2001.

        In our GPM segment, we had record production at our Siloam fractionator. However, this was partially offset by the fact NGLs traded at a historically low relationship to crude oil during the third quarter 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 after-tax less in revenue than had the historical relationship been realized.

        Second, in accordance with generally accepted accounting principles, we recorded a $0.9 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 highly 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. Excluding the non-cash hedging item and the write-down of deferred financing costs, our net loss was $2.5 million for the nine months ended September 30, 2002, compared to net income of $1.3 million for the nine months ended September 30, 2001. Beginning September 2002, the relationship of NGL product prices to crude oil prices has improved substantially.

        Processing margins (excluding both hedging items noted above) were less in 2002 than in 2001. Finally, it is also important to note the seasonal aspect of our NGL marketing business—in the third quarter, NGL product sales are historically lower than in the fourth and first quarters (i.e., the winter months) as some NGL production is stored for winter sale.

        In the E&P segment in our U.S. operations, record production was offset by lower average sales prices. Increased depreciation offset income from our Canadian operations.

        Additionally, we wrote down $1.7 million after-tax in deferred financing costs as a result of our May 24, 2002, credit facility amendment, a result of the Partnership's IPO, and an earlier amendment.

        Gas gathering, processing and marketing revenues.    Gas gathering, processing and marketing revenues were $106.7 million for the nine months ended September 30, 2002, compared to $142.4 million for the nine months ended September 30, 2001, a decrease of $35.6 million, or 25%. GPM revenues decreased primarily due to:

•

In Appalachia, we experienced significantly lower average NGL product sales prices in 2002 partially offset by higher sales volumes, resulted in a net decrease of $15.2 million.



•

In Appalachia, we recorded net $1.7 million non-cash, ineffectiveness charge related to our hedging activities.



•

Reduced sales prices and volumes in our 2002 gas marketing operations resulted in a $14.3 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 $22.2 million for the nine months ended September 30, 2002, compared to $9.6 million for the nine months ended September 30, 2001, an increase of $12.6 million, or 131%. E&P revenues increased primarily due to our August 2001 E&P Canadian acquisition and subsequent drilling success, which together have added

17

17,500 Mcfe/d of average production. Our capital program in the U.S. has also yielded an additional 2,100 Mcfe/d of average production during 2002. Our volume increases have been partially offset by price decreases. In the second quarter of 2002, we reported that our volumes had been constrained in Alberta, Canada due to higher than specification "dew point" (a small amount of NGLs in the natural gas caused this condition). We successfully resolved this issue at the north Bantry property by installing a small gas plant for $0.6 million in June 2002. In the third quarter of 2002, this condition surfaced at the south Bantry property due to our continued drilling success, and volumes again were constrained. We expect to resolve this issue through the installation of a $0.6 million plant at the south Bantry property.

        Purchased gas costs.    Purchased gas costs were $86.7 million for the nine months ended September 30, 2002, compared to $119.6 million for the nine months ended September 30, 2001, a decrease of $33.0 million, or 28%. Purchased gas costs decreased in 2002 primarily due to the following:

•

In Appalachia, we experienced lower average purchase costs in 2002 partially offset by higher sales volumes, resulted in a net decrease of $10.7 million.



•

Reduced average purchase prices more than offset increased volumes in our 2002 gas marketing operations netting to a $15.9 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 $12.2 million for the nine months ended September 30, 2002, compared to $11.9 million for the nine months ended September 30, 2001, an increase of $0.3 million, or 3%.

        Lease operating expenses.    Lease operating expenses were $5.2 million for the nine months ended September 30, 2002, compared to $2.4 million for the nine months ended September 30, 2001, an increase of $2.8 million, or 120%. Lease operating expense increased in 2002 primarily due to the addition of our Canadian operations in August 2001.

        Transportation costs.    Transportation costs were $1.2 million for the nine months ended September 30, 2002, compared to $0.5 million for the nine months ended September 30, 2001, an increase of $0.7 million, or 126%. The increase was caused by the addition of our Canadian operations in August 2001 as well as increased throughput from our Rocky Mountain properties.

        Production taxes.    Production taxes were $1.4 million for the nine months ended September 30, 2002, compared to $0.6 million for the nine months ended September 30, 2001, an increase of $0.8 million, or 155%. 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 $8.2 million for the nine months ended September 30, 2002, compared to $6.2 million for the nine months ended September 30, 2001, an increase of $2.0 million, or 33%. Expenses related to operating the businesses of our August 2001 Canadian E&P acquisition and our fully consolidated subsidiary—MarkWest Energy Partners, L.P., which had its initial public offering in May 2002—principally caused the increase.

        Depreciation, depletion and amortization.    Depreciation, depletion and amortization were $15.8 million for the nine months ended September 30, 2002, compared to $6.3 million for the nine months ended September 30, 2001, an increase of $9.5 million, or 149%. 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.

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        Interest expense.    Interest expense was $3.0 million for the nine months ended September 30, 2002, compared to $2.6 million for the nine months ended September 30, 2001, an increase of $0.4 million, or 15%. Additional debt incurred in connection with the financing of our August 2001 Canadian acquisition, partially offset by decreased interest rates, 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 the May 24, 2002 amendment to our credit facility—which was completed concurrently with the IPO of our consolidated subsidiary, MarkWest Energy Partners, L.P.—and an earlier amendment.

        Gain on sale to related party.    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 recognize a gain on the purchase price in excess of our book value to the extent that the purchase price was paid in cash, approximately $141,000 during 2002. The remaining balance of $328,000 was recorded as deferred income and is included in accrued liabilities on our balance sheet.

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

Critical Accounting Policies

        In addition to the Critical Accounting Policies described in our most recent Form 10-K, please see below for a description of our Critical Accounting Policies.

        Price Risk Management Activities.    We account for price risk management activities based upon the fair value accounting methods prescribed by SFAS No. 133. Risk management activities include utilizing various hedging contracts and other derivatives to reduce volatility in our cash flow. SFAS No. 133 require 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.

        One of the primary factors that can have an impact on our results each period is the price assumptions used to value our hedges. Many of these instruments have quoted market prices. However, we are required to use internal valuation techniques or models to estimate the fair value of instruments that are not traded on an active exchange or that have terms that extend beyond the time period for which exchange-based quotes are available. These modeling techniques require us to estimate the level of correlation between future changes in the fair value of the hedge instrument and the transaction being hedged, both at the inception and on an ongoing basis. This is complicated since energy commodity prices, the primary risk we hedge, have basis (location) differences that can be difficult to hedge effectively. The factors underlying our estimates of fair value and our assessment of correlation of our hedging derivatives are impacted by actual results and changes in conditions that affect these factors, many of which are beyond our control. You should read "Item 3 Quantitative and Qualitative Disclosures about Market Risk" for further discussion regarding our risk management activities.

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

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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, like compressors.

        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 availability under our credit facility, which relates to 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 production, our drilling results, and commodity prices), as well as our NGL marketing business's receivables and inventory levels.

        As part of the formation of MarkWest Energy Partners, MarkWest Hydrocarbon retained our 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 increased E&P segment's natural gas production, as is further discussed in Item 3, Quantitative and Qualitative Disclosures about Market Risk.

        As described above under Results of Operations, within our GPM business segment, during the third quarter we experienced (a) some ineffectiveness in our hedging program, reducing our cash flow from operations by $1.8 million, and (b) significantly below average processing margins. Both conditions only affected MarkWest Hydrocarbon on a standalone basis and did not impact the Partnership. Both conditions have also improved recently as NGL product sales prices have risen (including relative to crude oil for hedges). Within our E&P business segment, we suffered constrained throughput in Alberta, Canada because of higher than specification "dew point." As a result of these events and the related impact on our financial flexibility, we have reduced our capital expenditure program for the remainder of 2002 by $2.5 million.

        We have also elected to sell 500,000 subordinated units we own in the Partnership, which would reduce our ownership to 2,500,000 subordinated units, or a 47% interest from the current 56% interest. The funds received will allow us to drill our large inventory of Canadian prospects at a faster rate in 2003 than we otherwise would have. In October 2002, we signed a letter of intent to sell these 500,000 subordinated units for estimated net proceeds of $8 million. We expect to complete the sale of these subordinated units during the fourth quarter of 2002, although there is no assurance that such sale will be completed. In the event the planned sale does not occur, we expect to reduce our planned 2003 capital expenditure program or consider the sale of a mature E&P property.

        As of September 30, 2002, on a standalone basis (i.e., prior to consolidating the Partnership) MarkWest Hydrocarbon had borrowed $41.6 million of its $45.7 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 redetermination based on our proved reserves. As of September 30, 2002, the Partnership had borrowed $21.4 million of its $48 million available credit under its $60 million credit facility.

        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.

Cash Flows

        Net cash provided by operating activities was $33.9 million and $12.4 million for the nine months ended September 30, 2002 and 2001, respectively. Net cash provided by operating activities increased

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during the first nine months of 2002 due to (a) greater cash flows from operating activities, primarily from our growing E&P business, and (b) timing of cash receipts and disbursements.

        Net cash used in investing activities was $25.1 million and $66.4 million for the nine months ended September 30, 2002 and 2001, respectively. Net cash used in investing activities was larger in 2001 principally due to the purchase of our Canadian E&P operations during August 2001.

        Net cash used in financing activities was $9.1 million during the first nine months of 2002. Net cash provided by financing activities was $55.5 million during the first nine months of 2001. During 2001, we borrowed money to fund our Canadian E&P acquisition. During 2002, we paid down debt with the proceeds received from the Partnership on its IPO.

Capital Requirements

        MarkWest Hydrocarbon projects capital expenditures of $29 million for 2002, of which we had spent $25 million as of September 30, 2002, principally in our E&P segment. Our capital spending is principally discretionary and may change contingent upon a number of factors, including our results of operations.

Outlook

        Looking forward, a new gas stream is expected to begin flowing late fourth quarter 2002, when a new gatherer completes its connection into the existing transmission system upstream of the Partnership's Kenova NGL extraction plant. The Partnership has sufficient unused capacity to process for a fee the expected additional 10,000 Mcf/d of natural gas and the resulting 20,000 gallons per day of NGL products.

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

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(a)

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

(b)

Earnings before non-cash hedging ineffectiveness, interest income, interest expense, write-down of deferred financing costs, gain on sales, income taxes, depreciation, depletion and amortization and minority interest in net income of consolidated subsidiary.

(c)

Cash flows provided by operating activities prior to changes in operating assets and liabilities.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

        Overview.    Our primary risk management objective is to reduce volatility in our cash flow. On a long-term basis, our natural gas sales volumes in our E&P segment largely offset our keep-whole contractual requirements for purchasing natural gas in our GPM segment in Appalachia, thereby reducing our risk caused by fluctuations in natural gas prices. In the short term, we may choose to let this natural hedge be operative, or we may elect to hedge our E&P segment and our processing margin in Appalachia separately. We are currently evaluating the latter alternative of hedging each business separately.

        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 into OTC swaps with counterparties that are members of our bank group or other energy and marketing companies. We conduct credit reviews and our agreements 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, except for agreements with a member of our bank group, 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. We are also exposed to financial loss for basis risk as described further below.

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        Natural Gas Price Risk.    As of September 30, 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 GPM segment, for certain Appalachian natural gas sales, as of September 30, 2002, we hedged 162,000 MMBtu and 54,000 MMBtu at $4.09 per MMBtu for the fourth quarter of 2002 and the year 2003, respectively.

        NGL Product Price Risk.    We hedge our NGL product sales by selling forward propane or crude oil. As of September 30, 2002, we have hedged Appalachian and Michigan NGL product sales as follows.

        Under Table II, 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.

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        Basis Risk.    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 discussed under Results of Operations above, during the third quarter of 2002, we experienced some ineffectiveness in our GPM hedging activities, which reduced our cash flows from operations and also required us to record a non-cash charge for potential ineffectiveness of hedges for future quarters.

        As of September 30, 2002, our natural gas basis hedges were as follows:

Item 4. Controls and Procedures

        Based on their evaluation of the internal controls, disclosure controls and procedures within 90 days of the filing date of this report, the Chief Executive Officer and the Chief Financial Officer have concluded that the effectiveness of such controls and procedures is satisfactory. Further there were not any significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

        Reference is made to Note 6 of our Consolidated Financial Statements in Item 1 of this Form 10-Q.

Item 6. Exhibits and Reports on Form 8-K

(a)

Exhibits

        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

        None.

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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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CERTIFICATION

        I, John M. Fox, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of MarkWest Hydrocarbon, Inc.;

2.

Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4.

The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b)

evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c)

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a)

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.

The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

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CERTIFICATION

        I, Gerald A. Tywoniuk, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of MarkWest Hydrocarbon, Inc.;

2.

Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4.

The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b)

evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c)

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a)

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.

The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

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