UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

ý		QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2003

OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-11566

MARKWEST HYDROCARBON, INC.

(Exact name of registrant as specified in its charter)

Delaware		84-1352233
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).

Yes o No ý

The registrant had 8,496,813 shares of common stock, $.01 per share par value, outstanding as of March 31, 2003.

PART I—FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

Consolidated Balance Sheet at March 31, 2003 and December 31, 2002

Consolidated Statement of Operations for the Three Months Ended March 31, 2003 and 2002

Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2003 and 2002

Consolidated Statement of Changes in Stockholders’ Equity for the Three Months Ended March 31, 2003

Notes to the 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

Item 4. Controls and Procedures

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

Item 6. Exhibits and Reports on Form 8-K

SIGNATURE

CERTIFICATIONS

Glossary of Terms

Bcf		billion cubic feet of natural gas
Btu		British thermal units, an energy measurement
Gal/d		gallons per day
Mcf		thousand cubic feet of natural gas
Mcf/d		thousand cubic feet of natural gas per day
Mcfe		thousand cubic feet of natural gas equivalent
Mcfe/d		thousand cubic feet of natural gas equivalent per day
MMBtu		million British thermal units, an energy measurement
MMcf		million cubic feet of natural gas
MMcf/d		million cubic feet of natural gas per day
NGL		natural gas liquids, such as propane, butanes and natural gasoline

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 SHEETS

(UNAUDITED)

(in thousands except share and per share data)

	March 31, 2003			December 31, 2002
ASSETS
Current assets:
Cash and cash equivalents	$	7,908		$	6,410
Receivables, net (including related party receivables of $1,143 and $748, respectively)	38,446			25,444
Inventories	3,223			4,347
Prepaid replacement natural gas	2,104			1,197
Other assets	1,310			1,240
Total current assets	52,991			38,638

Property, plant and equipment:
Gas processing, gathering, storage and marketing equipment	159,614			121,851
Oil and gas properties and equipment, full cost method	154,164			139,234
Land, buildings and other equipment	7,627			7,540
Construction in progress	1,640			1,610
	323,045			270,235
Less: accumulated depreciation, depletion and amortization	(65,469		)	(58,717		)
Total property and equipment, net	257,576			211,518

Risk management asset	638			749
Intangible assets, net of accumulated amortization of $2,150 and $2,018, respectively	2,605			2,138
Note receivables from employees	271			271

Total assets	$	314,081		$	253,314

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable (including related party payables of $1,893 and $1,264, respectively)	$	44,596		$	26,063
Accrued liabilities	8,178			8,145
Risk management liability	13,960			13,719
Total current liabilities	66,734			47,927

Deferred income taxes	33,666			35,685
Long-term debt	105,824			64,223
Risk management liability	1,761			2,115
Other long-term liabilities	6,646			4,011
Minority interest in consolidated subsidiary	45,345			46,001
Commitments and contingencies

Stockholders’ equity:
Preferred stock, par value $0.01, 5,000,000 shares authorized, 0 shares outstanding	—			—
Common stock, par value $0.01, 20,000,000 shares authorized, 8,561,374 and 8,561,374 shares issued, respectively	87			87
Additional paid-in capital	42,747			42,758
Retained earnings	18,651			19,693
Accumulated other comprehensive income (loss), net of tax	(6,987		)	(8,858		)
Treasury stock, 64,561 and 50,461 shares, respectively	(393		)	(328		)
Total stockholders’ equity	54,105			53,352

Total liabilities and stockholders’ equity	$	314,081		$	253,314

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended March 31,
	2003			2002
	(in thousands, except per share data)
Revenue:
Gathering, processing and marketing	$	50,651		$	37,330
Exploration and production	10,659			7,057
Total revenue	61,310			44,387

Operating expenses:
Purchased gas costs	46,003			28,088
Plant operating expenses	4,506			4,350
Lease operating expenses	1,608			1,252
Transportation costs	513			338
Production taxes	728			283
Selling, general and administrative expenses	3,137			2,827
Depreciation, depletion and amortization	5,098			5,214
Total operating expenses	61,593			42,352

Income (loss) from operations	(283		)	2,035

Other income and (expenses):
Interest income	24			7
Interest expense	(1,087		)	(1,052		)
Write-down of deferred financing costs	—			(718		)
Minority interest in net income of consolidated subsidiary	(874		)	—
Other income (expense)	(15		)	2

Income (loss) before income taxes	(2,235		)	274

Provision (benefit) for income taxes:
Current	(23		)	83
Deferred	(1,199		)	16
Provision (benefit) for income taxes	(1,222		)	99

Income (loss) before change in accounting principle	(1,013		)	175

Cumulative effect of change in accounting for asset retirement obligations, net of tax	(29		)	—

Net income (loss)	$	(1,042	)	$	175

Basic earnings (loss) per share of common stock	$	(0.12	)	$	0.02
Earnings (loss) per share assuming dilution	$	(0.12	)	$	0.02

Weighted average number of outstanding shares of common stock:
Basic	8,511			8,515
Assuming dilution	8,514			8,528

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three Months Ended March 31,
	2003			2002
	(in thousands)
Cash flows from operating activities:
Net income (loss)	$	(1,042	)	$	175
Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect of change in accounting	29			—
Depreciation, depletion and amortization	5,098			5,214
Amortization of deferred financing costs included in interest expense	309			306
Write-off of deferred financing costs	—			718
Minority interest in net income of consolidated subsidiary	874			—
Derivative ineffectiveness and non-cash mark-to-market adjustment	(922		)	(75		)
Reclassification of Enron hedges to purchased gas costs	(18		)	(420		)
Deferred income taxes	(1,199		)	16
Other	240			24
Changes in operating assets and liabilities:
(Increase) decrease in receivables	(3,844		)	(1,557		)
(Increase) decrease in inventories	1,124			2,433
(Increase) decrease in prepaid expenses and other assets	(873		)	7,503
Increase (decrease) in accounts payable and accrued liabilities	9,773			1,703
Increase (decrease) in other long-term liabilities	—			3,090

Net cash flow provided by operating activities	9,549			19,130

Cash flows from investing activities:
Pinnacle acquisition, net of cash acquired	(38,238		)	—
Capital expenditures	(6,735		)	(9,113		)
Proceeds from sale of assets	24			42

Net cash used in investing activities	(44,949		)	(9,071		)

Cash flows from financing activities:
Proceeds from long-term debt	45,700			4,500
Repayment of long-term debt	(6,500		)	(16,300		)
Debt issuance costs	(810		)	(236		)
Distribution to MarkWest Energy Partners’ unitholders	(1,530		)	—
Net issuance of treasury shares	(76		)	76

Net cash provided by (used in) financing activities	36,784			(11,960		)

Effect of exchange rate on changes in cash	114			3

Net increase (decrease) in cash and cash equivalents	1,498			(1,898		)
Cash and cash equivalents at beginning of period	6,410			2,340

Cash and cash equivalents at end of period	$	7,908		$	442

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENT OF CHANGES IN

STOCKHOLDERS’ EQUITY

(UNAUDITED)

	Shares of Common Stock	Shares of Treasury Stock		Common Stock		Additional Paid-In Capital			Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
	(in thousands)

Balance, December 31, 2002	8,561	(50	)	$	87	$	42,758		$	19,693		$	(328	)	$	(8,858	)	$	53,352

Comprehensive income:
Net income (loss)	—	—		—		—			(1,042		)	—			—			(1,042		)
Other comprehensive income:
Foreign currency translation, net of tax	—	—		—		—			—			—			2,264			2,264
Risk management activities, net of tax	—	—		—		—			—			—			(393		)	(393		)
Comprehensive income, net of tax																		$	829

Net treasury stock (acquisitions) reissuances	—	(15	)	—		(11		)	—			(65		)	—			(76		)

Balance, March 31, 2003	8,561	(65	)	$	87	$	42,747		$	18,651		$	(393	)	$	(6,987	)	$	54,105

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

MARKWEST HYDROCARBON, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. General

The consolidated financial statements include the accounts of MarkWest Hydrocarbon, Inc. (“MarkWest Hydrocarbon”), and its wholly owned subsidiaries. Through consolidation, we have eliminated all significant intercompany accounts and transactions. We have reclassified certain prior year amounts to conform to the current year’s presentation.

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, 2002, 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. The variance between the effective tax rate for the three months ended March 31, 2003 and statutory rates was impacted by an operating loss in the U.S. combined with operating income in Canada.

2. Pinnacle Acquisition

On March 28, 2003, our consolidated subsidiary, MarkWest Energy Partners, L.P. (“MarkWest Energy Partners”), completed the acquisition of Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG Transmission Company, Inc., PNG Utility Company and Bright Star Gathering, Inc. (collectively, the “Sellers”). The purchase price was comprised of $23.4 million paid in cash to the Sellers, plus the assumption of specified liabilities, including $16.6 million of bank indebtedness.

The acquisition was accomplished through a merger under Texas law of the Sellers and four newly formed wholly owned subsidiaries of MarkWest Energy Partners as buyers. In the merger, most of the assets and liabilities of the Sellers were allocated to the MarkWest Energy Partners entities, and all entities survived the merger. The assets acquired from the Sellers, primarily located in the state of Texas, with the balance located in New Mexico, Louisiana, Mississippi and Kansas, are comprised of three lateral natural gas pipelines and twenty gathering systems. The three lateral natural gas pipelines consist of approximately 67 miles of pipe and transport up to 1.1 Bcf/day under firm contracts to power plants. The twenty gathering systems gather more than 44 MMcf/d.

The purchase price was allocated as follows (in thousands):

Acquisition costs:
Long-term debt incurred	$	39,471
Direct acquisition costs	450
Current liabilities assumed	8,150
Total	$	48,071

Allocation of acquisition costs:
Current assets	$	10,643
Oil and gas properties-proved	37,428
Total	$	48,071

Pro Forma Results of Operations (Unaudited)

The following table reflects the unaudited pro forma consolidated results of operations for the three months ended March 31, 2003 and 2002, as though our Pinnacle acquisition had occurred on January 1, 2002. These unaudited pro forma results have been prepared for comparative purposes only and are not indicative of future results.

	Three Months Ended March 31,
	2003			2002
	(in thousands, except per share data)
Revenue	$	79,097		$	52,429
Net income (loss)	$	(327	)	$	(41	)
Basic net income (loss) per limited partner unit	$	(0.04	)	$	0.00
Diluted net income (loss) per limited partner unit	$	(0.04	)	$	0.00

3. Liquidity

MarkWest Hydrocarbon’s cash flow generated from operations is subject to volatility in energy prices, especially prices for NGLs and natural gas. Our cash flow is enhanced in periods when the prices received for NGLs are high relative to the price of natural gas we purchase to satisfy our “keep-whole” contractual arrangements in Appalachia, and is reduced in periods when the prices received for NGLs are low relative to the price of natural gas we purchase to satisfy such contractual arrangements. Under “keep-whole” contracts, we retain and sell the NGLs produced in our processing operations for third-party producers, and then reimburse or “keep whole” the producers for the Btu content of the NGLs removed through the re-delivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas. Generally, the value of the NGLs extracted is greater than the cost of replacing those Btus with dry gas, resulting in positive operating margins under these contracts. Periodically, when natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, the cost of keeping the producer “whole” can result in operating losses.

Toward the end of the first quarter of 2003, natural gas prices began to be unusually high compared to NGL prices. This trend is forecast to continue through at least the second quarter of 2003. This unusual disparity in prices has reduced our internally generated cash flows, will likely cause limitations on the availability of borrowings under our credit facility, and may cause us to be in noncompliance with certain financial covenants under the credit facility.

We have commenced discussions with the lenders under our credit facility and believe that we will be able to obtain covenant waivers should noncompliance occur. However, we believe that during any period of noncompliance, borrowings under the credit facility would be limited to amounts currently available, exclusive of MarkWest Energy Partners’ credit facility. As of March 31, 2003, MarkWest Hydrocarbon has borrowed $44.7 million of the $52.9 million available credit under our $60 million credit facility.

In light of the forecasted reduction in cash flows and possible limits on available borrowings under our credit facility, MarkWest Hydrocarbon has undertaken a series of initiatives to enhance our liquidity position and to take advantage of favorable market valuations of domestic exploration and production assets. Accordingly, we have engaged a third party to act as financial advisor to MarkWest Hydrocarbon to assist in soliciting acquisition proposals for certain of our developed oil and gas properties. The expected sale proceeds from these properties would substantially improve our liquidity and allow us to maintain full compliance with our credit facility covenants.

Almost all of our capital expenditures are discretionary. We will therefore manage our future capital expenditures to match available cash flows from operations.

4. Debt

MarkWest Hydrocarbon, Inc.

In conjunction with the Pinnacle acquisition (see Note 2), MarkWest Hydrocarbon amended its credit agreement (the “Credit Facility”) with various lenders effective March 28, 2003. The amended agreement provides for a ratio of not more than 3.75:1.00 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 3.50 as of September 30, 2003, and to 3.0 as of March 31, 2004 and thereafter. All other aspects of the amended agreement, including rates, collateralization and covenants are similar to the original agreement.

MarkWest Energy Partners

In conjunction with the Pinnacle acquisition (see Note 2), MarkWest Energy Partners amended its credit agreement with various lenders effective March 28, 2003. The amended agreement provides for a $15 million increase to our maximum borrowing amount, now $75 million. All other aspects of the amended agreement, including rates, collateralization and covenants are similar to the original agreement.

5. Adoption of SFAS No. 143

On January 1, 2003, we adopted SFAS No. 143, Asset Retirement Obligations. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. During the first quarter of 2003, we recorded a net-of-tax cumulative effect of change in accounting principle charge of $29,000 ($63,000 before tax), an asset retirement obligation of $3.2 million (a net increase to long-term liabilities of $2.5 million). We also increased net properties $2.4 million in accordance with the provisions of SFAS No. 143. There was no impact on our cash flows as a result of adopting SFAS No. 143. The pro forma asset retirement obligation would have been $2.5 million at January 1, 2002 had we adopted SFAS No. 143 on January 1, 2002. The asset retirement obligation, which is included on the Consolidated Balance Sheet in Other Long-Term Liabilities, was $2.4 million at March 31, 2003.

For the period ended March 31, 2002, the pro forma effect on net income and earnings per share, had SFAS No. 143 been adopted by us on January 1, 2002, would have been as follows:

	As Reported		Pro Forma
	(in thousands, except per share data)
Net income	$	175	$	(173	)
Earnings per share:
Basic	$	0.02	$	(0.02	)
Diluted	$	0.02	$	(0.02	)

6. Assets Held for Sale

Our board of directors has approved a plan to sell our three NGL product terminals, which are considered to be non-strategic assets. The terminals’ combined net book value as of March 31, 2003 was approximately $2.7 million. We believe the results from these terminals are immaterial for separate presentation as a discontinued operation.

7. Segment Reporting

Our operations are classified into three reportable segments:

(1) Exploration and Production—explore for and produce natural gas;

(2) Gathering and Processing—gathering and processing of natural gas and the transportation, fractionation and storage of natural gas liquids. Our gathering and processing operations are conducted by MarkWest Energy Partners; and

(3) Marketing—sell our equity and third party NGLs and purchase and market third-party natural gas.

On May 24, 2002, we spun off our gathering and processing assets into MarkWest Energy Partners, L.P., our fully consolidated subsidiary. The formation and initial public offering (the “IPO”) of MarkWest Energy Partners (the IPO closed on May 24, 2002) and the subsequent change to the structure of our internal organization caused the composition of our reportable segments to change in the fourth quarter of 2002. Prior to the fourth quarter of 2002, we classified our operations into two reportable segments:

(1) Exploration and Production—explore for and produce natural gas; and

(2) Gathering, Processing and Marketing—gathering and processing of natural gas and the transportation, fractionation and storage of natural gas liquids; also purchase and market third-party natural gas and NGLs.

Although first quarter of 2003 reflects our new segments, information prior to May 24, 2002 has not been restated to reflect the change in segmentation because no transfer pricing existed between Gathering and Processing and Marketing up until that point in time. In connection with the formation of MarkWest Energy Partners, certain contracts were executed which established the basis of fees for services rendered by processing MarkWest Hydrocarbon’s natural gas. No such arrangement existed prior to the formation of MarkWest Energy Partners. As a result, it is not practicable to restate certain prior period segment information to conform to our current presentation.

We evaluate the performance of our segments and allocate resources to them based on operating income. There were no intersegment revenues prior to May 24, 2002. We conduct our business in the United States and Canada.

The table below presents information about operating income for the reported segments for the three months ended March 31, 2003 and 2002. Operating income for each segment includes total revenues less purchased products costs, operating expenses, depreciation and depletion and excludes selling, general and administrative expenses, interest expense, interest income, one-time charges and income taxes. We have not reported asset information by reportable segment because we do not produce such information internally.

	MarkWest Hydrocarbon
										MarkWest Energy Partners
	Exploration and Production						Marketing			Gathering Processing &
	U.S.		Canada		Total		U.S.			U.S.		Total
Three Months Ended March 31, 2003
Revenues	$	4,242	$	6,417	$	10,659	$	32,958		$	17,693	$	61,310
Segment operating income	$	1,960	$	2,278	$	4,238	$	(5,003	)	$	3,619	$	2,854

	Exploration and Production						Gathering Processing & Marketing
	U.S.		Canada		Total		U.S		Total
Three Months Ended March 31, 2002
Revenues	$	2,357	$	4,700	$	7,057	$	37,330	$	44,387
Segment operating income	$	849	$	212	$	1,061	$	3,801	$	4,862

A reconciliation of total segment operating income to total consolidated income before taxes is as follows:

	Three Months Ended March 31,
	2003			2002
Total segment operating income	$	2,854		$	4,862
Selling, general and administrative expenses administrative expenses	(3,137		)	(2,827		)
Interest income	24			7
Interest expense	(1,087		)	(1,052		)
Write-down of deferred financing costs	—			(718		)
Minority interest in net income of consolidated subsidiary	(874		)	—
Other income (expense)	(15		)	2
Income (loss) before taxes	$	(2,235	)	$	274

8. 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.

9. Stock and Unit Compensation

As permitted under SFAS No. 123, Accounting for Stock-Based Compensation, we have elected to continue to measure compensation costs for stock-based and unit-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. We have two fixed compensation plans and, through our consolidated subsidiary, MarkWest Energy Partners, we have a variable plan. We account for these plans using fixed and variable accounting as appropriate.

Had compensation cost for our two stock-based compensation plans been determined based on the fair value at the grant dates under those plans consistent with the method prescribed by SFAS No. 123. our net income and earnings (loss) per share would have been reduced to the pro forma amounts listed below:

	Three Months Ended March 31,
	2003			2002
	(in thousands, except share data)
Net income (loss), as reported	$	(1,042	)	$	175
Deduct: total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effect	(73		)	(136		)
Pro forma net income (loss)	$	(1,115	)	$	39

Earnings (loss) per share:
Basic, as reported	$	(0.12	)	$	0.02
Basic, pro forma	$	(0.13	)	$	0.00
Diluted, as reported	$	(0.12	)	$	0.02
Diluted, pro forma	$	(0.13	)	$	0.00

Compensation expense for the variable plan, including restricted unit grants, is measured using the market price of MarkWest Energy Partners’ common units on the date the number of units in the grant becomes determinable and is amortized into earnings over the period of service. Our stock options are issued under a fixed plan. Accordingly, compensation expense is not recognized for stock options unless the options were granted at an exercise price lower than market on the grant date.

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 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

• our expectations regarding MarkWest Energy Partners, L.P.

• our ability to obtain waivers of non-compliance under our credit facility

• the success of our efforts to improve our liquidity position

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

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

• 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

• 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.

Pinnacle Acquisition

Results of Operations

Operating Data

	Three Months Ended March 31,
	2003	2002	% Change

Exploration and production
Natural gas produced (Mcfe/d)	27,500	29,200	(6	%)

MarkWest Energy Partners
Appalachia:
Natural gas processed (Mcf/d)	264,000	269,000	(2	%)
NGLs fractionated for a fee (gal/d)	446,000	479,000	(7	%)

Michigan:
Natural gas processed for a fee	15,400	11,000	40	%

Three Months Ended March 31, 2003 Compared to the Three Months Ended March 31, 2002

Net loss. Net loss was $1.0 million for the three months ended March 31, 2003, compared to net income of $0.2 million for the three months ended March 31, 2002. The continuing unfavorable results from our hedges primarily caused our first quarter 2003 net loss. Hedging losses more than offset the benefits from the high natural gas prices that prevailed throughout the first quarter of 2003.

Gathering, processing and marketing revenue. Gathering, processing and marketing revenue was $50.7 million for the three months ended March 31, 2003 compared to $37.3 million for the three months ended March 31, 2002, an increase of $13.3 million, or 36%. Revenue was higher in 2003 than in 2002 primarily due to:

• Increased NGL product sales prices in Appalachia, which increased revenues $10.4 million, net of $7.3 million of hedging losses in 2003. Price increases offset modest Appalachian volume declines, which pushed revenues down $1.4 million.

• Increased volumes, up 40%, and prices, up 109%, in Michigan contributed an additional $1.3 million in 2003.

• Our March 2003 Pinnacle acquisition increased revenues $0.8 million.

• Gas marketing revenues increased $0.6 million.

Exploration and production revenue. Exploration and production revenue was $10.7 million for the three months ended March 31, 2003 compared to $7.1 million for the three months ended March 31, 2002, an increase of

$3.6 million, or 60%. Revenue was higher in 2003 than in 2002 primarily due to higher natural gas prices, partially offset by volume decreases. Revenue increased despite $1.5 million in hedging losses in 2003.

Purchased gas costs. Purchased gas costs were $46.0 million for the three months ended March 31, 2003, compared to $28.1 million for the three months ended March 31, 2002, an increase of $17.9 million, or 64%. Purchased gas costs were higher in 2003 primarily due to:

• Increased natural gas and NGL product prices in Appalachia, which increased purchased product costs $15.2 million. Price increases offset modest Appalachian volume declines, which pushed purchased product costs down $1.1 million. Purchased gas costs increased more than gathering, processing and marketing revenues.

• Increased volumes, up 40%, and prices, up 109%, in Michigan contributed an additional $0.4 million in 2003.

• Our March 2003 Pinnacle acquisition increased purchased product costs $0.7 million.

• Gas marketing product purchase costs increased $0.8 million.

Plant operating expenses. Plant operating expenses were $4.5 million for the three months ended March 31, 2003, compared to $4.4 million for the three months ended March 31, 2002, an increase of $0.2 million, or 4%.

Lease operating expenses. Lease operating expenses were $1.6 million for the three months ended March 31, 2003, compared to $1.3 million for the three months ended March 31, 2002, an increase of $0.4 million, or 29%. Lease operating expenses increased principally due to additional workovers and recompletions of wells in Canada in 2003.

Transportation costs. Transportation costs were $0.5 million for the three months ended March 31, 2003, compared to $0.3 million for the three months ended March 31, 2002, an increase of $0.2 million, or 35%. Transportation costs increased principally due to a 36% increase in our throughput from our U.S. properties. We provide the majority of our Canadian transportation.

Production taxes. Production taxes were $0.7 million for the three months ended March 31, 2003, compared to $0.3 million for the three months ended March 31, 2002, an increase of $0.4 million, or 158%. Production taxes increased principally due to increased natural gas prices in 2003.

Selling, general and administrative expenses. Selling, general and administrative expenses were $3.1 million for the three months ended March 31, 2003, compared to $2.8 million for the three months ended March 31, 2002, an increase of $0.3 million, or 11%. The increase is principally attributable to increased insurance costs and incremental costs associated with our consolidated subsidiary, MarkWest Energy Partners, which went public in May 2002.

Depreciation and depletion. Depreciation and depletion were $5.1 million for the three months ended March 31, 2003, compared to $5.2 million, for the three months ended March 31, 2002, a decrease of $0.1 million, or 2%.

Interest expense. Interest expense was $1.1 million for both the three months ended March 31, 2003, and March 31, 2002. The expensing of third party costs associated with MarkWest Energy Partners’ March 28, 2003 credit facility amendment offset a decrease in the average amount of debt outstanding in 2003.

Write-down of deferred financing costs. We wrote off $0.7 million in deferred financing costs in the first quarter of 2002 as a result of amending our credit facility in March 2002.

Minority interest in net income of consolidated subsidiary. This represents the minority interest (i.e., non-MarkWest Hydrocarbon) ownership in the net income of MarkWest Energy Partners, which completed its initial public offering in May 2002.

Cumulative effect of change in accounting for asset retirement obligations. We adopted SFAS No. 143, Asset Retirement Obligations, in the first quarter of 2003.

Liquidity and Capital Resources

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

We have commenced discussions with the lenders under our credit facility and believe that we will be able to obtain covenant waivers should noncompliance occur. However, we believe that during any period of noncompliance, borrowings under the credit facility would be limited to amounts currently available, exclusive of MarkWest Energy Partners’ credit facility (discussed below). As of March 31, 2003, MarkWest Hydrocarbon has borrowed $44.7 million of the $52.9 million available credit under our $60 million credit facility.

Almost all of our capital expenditures are discretionary. We will therefore manage our future capital expenditures to match available cash flows from operations.

For MarkWest Energy Partners, future acquisitions or projects are expected to be financed through a combination of debt and issuance of additional units, as is common practice with master limited partnerships. The March 2003 Pinnacle acquisition was financed under MarkWest Energy Partners’ credit facility, which was expanded by $15 million on March 28, 2003. As of March 31, 2003, MarkWest Energy Partners has borrowed $61.1 million of the $75 million available credit under its $75 million credit facility.

MarkWest Hydrocarbon (exclusive of MarkWest Energy Partners) forecasts a baseline capital budget of $17 million for 2003, almost all of which is for discretionary exploration and production projects. The capital budget may change contingent upon a number of factors, including results of operations and cash flow.

Cash Flows

Net cash provided by operating activities was $9.5 million and $19.1 million for the three months ended March 31, 2003 and 2002, respectively. Net cash provided by operating activities decreased during the first three months of 2003 due to lower volumes and higher natural gas prices.

Net cash used in investing activities was $44.9 million and $9.1 million for the three months ended March 31, 2003 and 2002, respectively. Net cash used in investing activities was larger in 2003 due to our Pinnacle acquisition.

Net cash provided by financing activities was $36.8 million during the first three months of 2003. Net cash used in financing activities was $12.0 million during the first three months of 2002. In 2003, we had net borrowings as we financed our Pinnacle acquisition. During 2002, we completed our seasonal conversion of inventories to cash, which we used to pay down long-term debt.

Outlook

We expect natural gas prices to remain high for several months, which may continue to adversely affect our overall cash flow from operations if there continues to be a significant negative disparity between natural gas prices and NGL product prices.

MarkWest Energy Partners’ Appalachian plants were shut down during April and early May for annual maintenance. The shut down period varied by plant and lasted between a few days to two to three weeks. Consequently, second quarter 2003 Appalachian throughput volumes will decrease relative to the first quarter of 2003. However, the resulting volumetric decrease in cash flow from Appalachian operations should be more than offset by cash flow from MarkWest Energy Partners’ Texas (Pinnacle) operations, which began contributing to our consolidated results March 28, 2003.

We expect our second quarter 2003 natural gas production to decline compared to our first quarter 2003 production levels. In the San Juan Basin, a third-party pipeline shut down for maintenance will shut down our production for approximately a week.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

Overview

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

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

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

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

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

Types of Price Risk

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

• Under “keep-whole” contracts, we take title to and sell the NGLs produced in our processing operations. We also reimburse or “keep whole” the producers for the Btu content of the NGLs removed through the re-delivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas. Keep-whole contracts therefore expose us to NGL product price risk (on the sales side) and natural gas price risk (on the purchase or reimbursement side). Generally, the value of the NGLs extracted is greater than the cost of replacing those Btus with dry gas, resulting in positive operating margins under these contracts. In the event natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, the cost of keeping the producer “whole” results in operating losses. The spread between the NGL product sales price and the purchase price of natural gas with an equivalent Btu content is called the “frac spread”.

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

Our fully consolidated subsidiary, MarkWest Energy Partners, is also subject to NGL price risk stemming from its percent-of-proceeds contracts (representing approximately 15% of its gross margin prior to the Pinnacle acquisition) and natural gas price risk from its recent Pinnacle acquisition. MarkWest Energy Partners gathers and transports natural gas for producers behind our gathering systems in Texas, many under percent-of-proceeds or percent-of-index contracts. Under these contracts MarkWest Energy Partners is entitled to approximately 10% of the natural gas produced.

Basis Risk

To the extent our natural gas production equals our keep-whole requirements for purchasing natural gas in Appalachia and there are no material differences in net prices, our commodity price risk is mitigated.

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

As of March 31, 2003, our natural gas basis hedges were as follows:

	Table I Hedged Natural Gas Basis
	Year Ending December 31, 2003
MMBtu	2,996,000
$ /MMBtu	$	(0.42	)

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

Natural Gas Price Risk

Generally, we are an overall net consumer of natural gas as our keep-whole contractual requirements for purchasing natural gas in Appalachia currently exceed our natural gas production. Until such time this relationship reverses and we become a net producer of natural gas, our E&P hedges are generally limited to either (i) obtaining futures prices that our models suggest are optimal, (ii) realizing the economics of a transaction, like our 2001 Canadian E&P acquisition, or (iii) mitigating our basis risk as described above. Generally, we execute our strategy by either entering into fixed-for-float swaps or utilizing costless collars. As of March 31, 2003, we have hedged our combined Canadian and Rocky Mountain natural gas volumes and prices as follows:

	Table II Hedged Natural Gas Sales
	Year Ending December 31,
	2003		2004		2005

MMBtu	3,527,000		2,877,000		44,100
$ /MMBtu	$	3.40	$	3.30	$	3.34
Henry Hub Equivalent $/MMBtu (1)	$	4.02	$	3.88	$	3.81

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

Regarding our natural gas price risk in Texas (part of our Pinnacle acquisition), we enter into fixed-for-float swaps or buy puts. As of March 31, 2003, no such hedges were in place. As of May 6, 2003, we had hedged our Texas natural gas price risk via swaps as follows:

	Table III Hedged Natural Gas Sales
	Year Ending December 31,
	2003		2004		2005

MMBtu	122,500		183,000		182,500
$ /MMBtu	$	5.09	$	4.57	$	4.26

As of May 6, 2003, we had hedged our Texas natural gas price risk via puts as follows:

	Table IV Hedged Natural Gas Sales
	Year Ending December 31,
	2003		2004		2005

MMBtu	245,000		366,000		—
Strike price ($/MMBtu)	$	4.50	$	4.00	$	0.00

NGL Product Price Risk

We hedge our NGL product sales by selling forward propane or crude oil. As of March 31, 2003, we have hedged Appalachian and NGL product sales as follows:

	Table V Hedged Sales Price for NGL Products
	Year Ending December 31,
	2003		2004
MarkWest Hydrocarbon, Inc.
NGL Volumes Hedges Using Crude Oil
NGL gallons	61,746,000		13,113,000
NGL sales prices per gallon	$	0.38	$	0.51

MarkWest Energy Partners, L.P.
NGL Volumes Hedged Using Crude Oil
NGL gallons	2,862,000		—
NGL sales price per gallon	$	0.46	—
NGL Volumes Hedged Using Propane
NGL gallons	1,008,000		—
NGL sales price per gallon	$	0.41	—
Total NGL Volumes Hedged
NGL gallons	3,870,000		—
NGL sales price per gallon	$	0.44	—

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

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

To the extent our Appalachian natural gas purchase requirements exceed our E&P natural gas production, we are simultaneously subject to NGL price risk on the sales side and natural gas price risk on the purchase side within our GPM business. Consequently, we may hedge our Appalachian processing margin (defined as revenues less purchased product costs) by simultaneously selling propane or crude oil while purchasing natural gas. However, as of March 31, 2003, we had no such hedges in place.

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.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

Reference is made to Note 8 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.

*Filed herewith.

(b) Reports on Form 8-K

A report on Form 8-K was filed on March 26, 2003, announcing that MarkWest Hydrocarbon’s 46.7 percent-owned affiliate, MarkWest Energy Partners, L.P., has entered into a Purchase and Sale Agreement with Energy Spectrum Partners, L.P., for the acquisition of Pinnacle Natural Gas Company and certain affiliates for approximately $38 million.

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.

MarkWest Hydrocarbon, Inc.

(Registrant)

Date:	May 14, 2003	/s/ Donald C. Heppermann

		Donald C. Heppermann
		Senior Vice President Finance, Chief Financial Officer and Secretary

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 officer 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”).

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.

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls.

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.

Date:	May 14, 2003
		/s/ John M. Fox
		John M. Fox
		President and Chief Executive Officer

CERTIFICATION

I, Donald C. Heppermann, certify that:

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

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”).

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.

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls.

Date:	May 14, 2003
		/s/ Donald C. Heppermann

		Donald C. Heppermann
		Senior Vice President Finance, Chief Financial Officer and Secretary