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 September 30, 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 9,384,013 shares of common stock, $.01 per share par value, outstanding as of

September 30, 2003.

PART I—FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements
	Condensed Consolidated Balance Sheets (Unaudited) at September 30, 2003 and December 31, 2002
	Condensed Consolidated Statements of Operations (Unaudited) for the Three and Nine Months Ended September 30, 2003 and 2002
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2003 and 2002
	Condensed Consolidated Statement of Changes in Stockholders’ Equity (Unaudited) for the Nine Months Ended September 30, 2003
	Notes to the Unaudited Condensed 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

Glossary of Terms

Bcf		billion cubic feet of natural gas
Btu		British thermal units, an energy measurement
LIBOR		London Inter-Bank Offered Rate
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
NGLs		natural gas liquids, such as propane, butanes and natural gasoline

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

PART I—FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

MARKWEST HYDROCARBON, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

(in thousands, except share and per share data)

	September 30, 2003			December 31, 2002
ASSETS
Current assets:
Cash and cash equivalents	$	7,580		$	6,410
Receivables, net	13,695			25,444
Inventories	6,553			4,347
Prepaid replacement natural gas	3,566			1,197
Other assets	2,314			1,240
Assets held for sale	5,046			—
Total current assets	38,754			38,638

Property, plant and equipment:
Gas processing, gathering, storage and marketing equipment	163,705			121,851
Oil and gas properties and equipment, full cost method	—			139,234
Land, buildings and other equipment	5,939			7,540
Construction in progress	893			1,610
	170,537			270,235
Less: accumulated depreciation, depletion and amortization	(39,496		)	(58,717		)
Total property and equipment, net	131,041			211,518

Risk management asset	99			749
Intangible assets, net of accumulated amortization of $2,649 and $2,018, respectively	1,502			2,138
Note receivables from employees	217			271
Assets held for sale	116,131			—

Total assets	$	287,744		$	253,314

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	19,746		$	26,063
Accrued liabilities	15,438			8,145
Risk management liability	4,396			13,719
Liabilities held for sale	14,334			—
Total current liabilities	53,914			47,927

Deferred income taxes	4,015			35,685
Long-term debt	63,300			64,223
Risk management liability	375			2,115
Other long-term liabilities	46			4,011
Minority interest in consolidated subsidiary	53,987			46,001
Liabilities held for sale	49,678			—
Commitments and contingencies (Note 11)

Stockholders’ equity:
Preferred stock, par value $0.01, 5,000,000 shares authorized, 0 shares outstanding	—			—
Common stock, par value $0.01, 22,000,000 shares authorized, 9,466,805 and 9,417,511 shares issued and outstanding, respectively	95			95
Additional paid-in capital	49,214			42,750
Retained earnings	15,582			19,693
Accumulated other comprehensive loss, net of tax	(1,920		)	(8,858		)
Treasury stock, 82,792 and 55,507 shares, respectively	(542		)	(328		)
Total stockholders’ equity	62,429			53,352

Total liabilities and stockholders’ equity	$	287,744		$	253,314

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

MARKWEST HYDROCARBON, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
	(in thousands, except per share data )

Revenue	$	48,228		$	29,540		$	146,767		$	105,430

Operating expenses:
Purchased product costs	44,521			26,313			134,881			86,658
Facility expenses	5,327			3,770			14,381			11,941
Selling, general and administrative expenses	3,426			2,313			9,064			6,526
Depreciation and amortization	2,220			1,341			5,791			4,243
Loss on sale of terminals	55			—			55			—
Total operating expenses	55,549			33,737			164,172			109,368

Loss from operations	(7,321		)	(4,197		)	(17,405		)	(3,938		)

Other income and (expenses):
Interest income	24			19			68			41
Interest expense	(1,139		)	(753		)	(4,244		)	(2,995		)
Write-down of deferred financing costs	—			—			—			(2,977		)
Gain on sale to related party	—			77			188			141
Minority interest in net income of consolidated subsidiary	(1,607		)	(1,122		)	(3,342		)	(1,480		)
Other income (expense)	31			(36		)	15			(62		)

Loss from continuing operations before income taxes	(10,012		)	(6,012		)	(24,720		)	(11,270		)

Benefit for income taxes	(3,701		)	(2,345		)	(9,058		)	(4,395		)

Loss from continuing operations	(6,311		)	(3,667		)	(15,662		)	(6,875		)

Discontinued operations (Note 3):
Income (loss) from discontinued exploration and production operations, net of tax	(1,260		)	505			2,788			1,815
Gain on sale of properties, net of tax	593			—			14,862			—
Income (loss) from discontinued operations	(667		)	505			17,650			1,815

Income (loss) before cumulative effect of accounting change	(6,978		)	(3,162		)	1,988			(5,060		)

Cumulative effect of change in accounting for asset retirement obligations, net of tax	—			—			(29		)	—
Net income (loss)	$	(6,978	)	$	(3,162	)	$	1,959		$	(5,060	)

Basic earnings (loss) per share of common stock	$	(0.74	)	$	(0.34	)	$	0.21		$	(0.54	)
Earnings (loss) per share assuming dilution	$	(0.74	)	$	(0.34	)	$	0.21		$	(0.54	)

Weighted average number of outstanding shares of common stock:
Basic	9,378			9,374			9,364			9,369
Assuming dilution	9,400			9,385			9,380			9,385

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

MARKWEST HYDROCARBON, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine Months Ended September 30,
	2003			2002
	(in thousands)
Cash flows from operating activities:
Net income (loss)	$	1,959		$	(5,060	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Cumulative effect of change in accounting principle	29			—
Depreciation, depletion and amortization	18,814			15,788
Amortization of deferred financing costs included in interest expense	1,270			975
Write-off of deferred financing costs	—			2,977
Minority interest in net income of consolidated subsidiary	3,342			1,480
Derivative ineffectiveness and non-cash mark-to-market adjustments	(2,207		)	1,710
Reclassification of Enron hedges to purchased product costs	(153		)	(648		)
Deferred income taxes	(4,846		)	(4,062		)
Gain on sale of San Juan Basin properties	(23,035		)	—
Cost of exiting hedges	(3,440		)	—
Other	427			(95		)
Changes in operating assets and liabilities:
(Increase) decrease in receivables	15,046			3,075
(Increase) decrease in inventories	(2,540		)	(320		)
(Increase) decrease in prepaid expenses and other assets	(3,941		)	8,322
Increase (decrease) in accounts payable and accrued liabilities	863			6,628
Increase (decrease) in other long-term liabilities	1,565			3,089

Net cash flow provided by operating activities	3,153			33,859

Cash flows from investing activities:
Pinnacle acquisition, net of cash acquired	(38,238		)	—
Lubbock pipeline acquisition	(12,222		)	—
Proceeds from sale of San Juan Basin properties, net of costs to dispose	55,007			—
Capital expenditures	(24,968		)	(25,433		)
Proceeds from sales of terminals	2,438			87
Proceeds from sale of assets to related parties	212			263

Net cash used in investing activities	(17,771		)	(25,083		)

Cash flows from financing activities:
Proceeds from long-term debt	86,835			48,910
Repayment of long-term debt	(75,130		)	(98,945		)
Proceeds from initial public offering, net of transaction costs	—			43,012
Proceeds from private placement of MarkWest Energy Partners’ common units, net of transaction costs	9,764			—
Capital contribution from MarkWest Energy GP, L.L.C. interest holders	17			—
Debt issuance costs	(811		)	(1,804		)
Distributions to MarkWest Energy Partners’ unitholders	(5,173		)	(514		)
Exercise of stock options	333			—
Net issuance (buyback) of treasury shares	(158		)	141
Payment on share purchase notes	—			13

Net cash provided by (used in) financing activities	15,677			(9,187		)

Effect of exchange rate on changes in cash	111			17
Net increase (decrease) in cash and cash equivalents	1,170			(394		)
Cash and cash equivalents at beginning of period	6,410			2,340
Cash and cash equivalents at end of period	$	7,580		$	1,946

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

MARKWEST HYDROCARBON, INC.

CONDENSED 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	)	$	86	$	42,759	$	19,693		$	(328	)	$	(8,858	)	$	53,352

Stock dividend, retroactively applied to January 1, 2003	859	(5	)	9		6,117		(6,070		)	(56		)	—			—

Comprehensive income:
Net income	—	—		—		—		1,959			—			—			1,959
Other comprehensive income:
Foreign currency translation, net of tax	—	—		—		—		—			—			3,796			3,796
Risk management activities, net of tax	—	—		—		—		—			—			3,142			3,142
Comprehensive income, net of tax																	8,897

Acquisition of treasury stock, net	—	(28	)	—		5		—			(158		)	—			(153		)
Exercise of options	47	—		—		333		—			—			—			333

Balance, September 30, 2003	9,467	(83	)	$	95	$	49,214	$	15,582		$	(542	)	$	(1,920	)	$	62,429

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

MARKWEST HYDROCARBON, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. General

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

We have prepared the unaudited financial statements presented herein in accordance with the instructions to Form 10-Q. The year-end balance sheet data was derived from audited financial statements but does not include all disclosures required by accounting principles generally accepted in the United States. Please read the interim unaudited 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 normal recurring adjustments for a fair presentation of the results for the unaudited interim periods.

We base the effective corporate tax rate for interim periods on the estimated annual effective corporate tax rate. The effective tax rate for continuing operations varies from statutory rates primarily due to state income taxes.

2. Sale of San Juan Basin Properties

During the third quarter of 2003, MarkWest Hydrocarbon completed the sales of the remainder of its San Juan Basin oil and gas properties to certain third parties for approximately $6.1 million, net of transaction costs and closing adjustments. Previously, MarkWest Hydrocarbon closed on the sale of the majority of its San Juan Basin properties in the second quarter of 2003. We recognized net pretax gains of $3.3 million and $23.0 million on the sales for the three and nine months ended September 30, 2003, which are included in Discontinued Operations: Gain on Sale of Properties. The proceeds from the sales were used for working capital and general corporate purposes.

3. Discontinued Operations and Assets and Liabilities Held For Sale

During the third quarter of 2003, our Board of Directors approved a plan to sell our Canadian oil and gas properties. On November 12, 2003, we announced we had entered into an agreement to sell one of our Canadian subsidiaries, which owns most of our Canadian properties, to a third party (see Note 15). Management also intends to dispose of our remaining U.S. and Canadian oil and gas properties within the next year as we discontinue our exploration and production business.

Revenues from the discontinued operations were $7.6 million and $7.7 million for the three months ended September 30, 2003 and 2002, respectively, and $27.5 million and $22.2 million for the nine months ended September 30, 2003 and 2002, respectively. Pretax income (loss) from discontinued operations was ($1.6) million and $0.3 million for the three months ended September 30, 2003 and 2002, respectively, and $3.5 million and $2.1 million for the nine months ended September 30, 2003 and 2002, respectively.

The earnings (loss) per share impact from discontinued operations was $(0.07) and $0.05 per basic and diluted share for the three months ended September 30, 2003 and 2002, respectively, and $1.88 and $0.19 per basic and diluted share for the nine months ended September 30, 2003 and 2002, respectively. The earnings per share impact from the cumulative effect of the change in accounting for asset retirement obligations was not significant for 2003.

4. Pinnacle Acquisition

On March 28, 2003, our consolidated subsidiary, MarkWest Energy Partners, L.P. (“MarkWest Energy Partners”), completed the acquisition (the “Pinnacle 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 Pinnacle 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 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
Fixed assets (including long-term contracts)	37,428
Total	$	48,071

Pro Forma Results of Operations

The following table reflects the unaudited pro forma consolidated results of operations for the three months ended September 30, 2002, and the nine months ended September 30, 2003 and 2002, as though the Pinnacle Acquisition had occurred on January 1, 2002. These unaudited pro forma results have been prepared for comparative purposes only and are not necessarily indicative of future results.

	Three Months Ended			Nine Months Ended September 30,
	September 30, 2002			2003			2002
	(in thousands, except per share data )
Revenue	$	40,422		$	164,554		$	135,520
Loss from continuing operations	$	(3,962	)	$	(14,436	)	$	(7,680	)
Net income (loss)	$	(3,457	)	$	2,703		$	(5,865	)
Basic net income (loss) per share	$	(0.37	)	$	0.29		$	(0.63	)
Diluted net income (loss) per share	$	(0.37	)	$	0.29		$	(0.63	)

5. Lubbock Pipeline Acquisition

On September 2, 2003, our consolidated subsidiary, MarkWest Energy Partners, through its wholly owned subsidiary MarkWest Pinnacle L.P., completed the acquisition (the “Lubbock Pipeline Acquisition”) of a 68-mile intrastate gas transmission pipeline near Lubbock, Texas from a subsidiary of ConocoPhillips for approximately $12.2 million. The transaction was financed through borrowings under MarkWest Energy Partners’ existing credit facility. The acquisition was accounted for as a purchase business combination. The pro forma results of operations of the Lubbock Pipeline Acquisition have not been presented, as they are not significant.

6. Terminal Dispositions

Our Board of Directors has approved a plan to sell any of our three NGL product terminals, which are considered to be non-strategic assets. On July 15, 2003, we sold our Lordstown, Ohio terminal to a third party for approximately $0.7 million, including $0.2 million for on-hand inventory. On September 2, 2003, we sold our Lynchburg, Virginia terminal to a third party for approximately $1.6 million plus on-hand inventory. As a result of the two sales, we incurred a loss of less than $0.1 million.

7. Stock Dividend

On July 10, 2003, our board of directors declared a stock dividend of one share of MarkWest Hydrocarbon’s common stock for each ten shares of common stock held by our stockholders. The stock dividend was paid on August 11, 2003, to the stockholders of record as of the close of business on July 31, 2003. All periods presented have been adjusted to give effect to the stock dividend.

8. Private Placement

Our consolidated subsidiary, MarkWest Energy Partners, sold 375,000 common units in two installments at a price of $26.23 per unit in a private placement transaction to certain accredited investors. The first installment of 300,031 units was completed on June 27, 2003, and grossed approximately $7.9 million. The second installment of 74,969 units was completed on July 10, 2003, and grossed approximately $1.9 million. Transaction costs for both installments were less than $0.1 million. MarkWest Energy Partners’ general partner paid its pro rata contribution in July 2003 after the second installment was completed. MarkWest Energy Partners primarily used the net proceeds from both installments to pay down debt under its credit facility.

9. Related Party Transactions

MarkWest Hydrocarbon, Inc.

Through our wholly owned subsidiary, MarkWest Resources, Inc., we held varied undivided interests in several exploration and production assets in which MAK-J Energy Partners Ltd. (“MAK-J”) also owns an undivided interest, varying from 25% to 51%. The general partner of MAK-J is a corporation owned and controlled by our current Chief Executive Officer, John M. Fox. One other current officer is a limited partner in MAK-J. As of September 30, 2003, we have receivables due from MAK-J, representing its share of operating and capital costs generated in the normal course of business, of approximately $0.7 million.

MarkWest Energy Partners

During the third quarter of 2003, MarkWest Hydrocarbon purchased a 0.3% interest in MarkWest Energy GP, L.L.C., the general partner of MarkWest Energy Partners, and 867 subordinated units of MarkWest Energy Partners from a former officer. We had originally sold the general partner interest and subordinated units to this individual in May 2002. In return for the general partner interest and the subordinated units, we exchanged the former officer’s $10,000 note receivable and related accrued interest and paid approximately $27,000 in cash, for total consideration of approximately $37,000. The purchase price for MarkWest Energy Partners subordinated units was based on market value of MarkWest Energy Partners common units, discounted for the subordination. The purchase price for the general partner interest was based on a formula included in the parties’ original purchase and sale agreement.

10. Segment Reporting

Our operations are classified into two reportable segments:

(1) Gathering and Processing—gathering and processing of natural gas and the transportation, fractionation and storage of natural gas liquid (our gathering and processing operations are conducted by MarkWest Energy Partners); and

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

A previous third segment, Exploration and Production, was discontinued in the third quarter of 2003. As a

result, this segment is no longer included in this disclosure.

On May 24, 2002, we spun off our gathering and processing assets into MarkWest Energy Partners. 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; (which has since been discontinued); and

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

Although the three and nine months ended September 30, 2003 reflects our revised segments, information prior to May 24, 2002, was not revised 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 was not practicable to revise certain prior period segment information to conform to our current presentation. In light of the discontinuance of our Exploration and Production segment during the third quarter of 2003, revenue and pretax income for this segment for all periods presented is included in Note 3. Prior period information for the Gathering, Processing and Marketing segment is shown on the face of the Statement of Operations, as this is the only segment included in continuing operations for 2002.

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.

The tables below presents information about operating income for the reported segments for the three and nine months ended September 30, 2003. 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.

	MarkWest Hydrocarbon
				MarkWest Energy Partners
	Marketing			Gathering & Processing		Eliminating Entries			Total
	(in thousands)
Three Months Ended September 30, 2003
Revenues from external customers	$	29,340		$	18,888	$	—		$	48,228
Intersegment revenues	$	—		$	12,524	$	(12,524	)	$	—
Segment operating income (loss)	$	(9,320	)	$	5,480	$	—		$	(3,840	)

	MarkWest Hydrocarbon
				MarkWest Energy Partners
	Marketing			Gathering & Processing		Eliminating Entries			Total
	(in thousands)
Three Months Ended September 30, 2003
Revenues from external customers	$	104,206		$	42,741	$	—		$	146,767
Intersegment revenues	$	—		$	36,000	$	(36,000	)	$	—
Segment operating income (loss)	$	(21,571	)	$	13,285	$	—		$	(8,286	)

	Three Months Ended September 30, 2003			Nine Months Ended September 30, 2003
	(in thousands)
Total segment operating loss	$	(3,840	)	$	(8,286	)
Loss on sale of terminals	(55		)	(55		)
Selling, general and administrative expenses	(3,426		)	(9,064		)
Interest income	24			68
Interest expense	(1,139		)	(4,244		)
Write-off of deferred financing costs	—			—
Gain on sale to related party	—			188
Minority interest in net income of consolidated subsidiary	(1,607		)	(3,342		)
Other income	31			15
Loss from continuing operations before income taxes	$	(10,012	)	$	(24,720	)

11. 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, results of operations or cash flows.

12. 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 (loss) and earnings (loss) per share would have been changed to the pro forma amounts listed below:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
	(in thousands, except per share data)
Net income (loss), as reported	$	(6,978	)	$	(3,162	)	$	1,959		$	(5,060	)
Add: Compensation expense included in reported net income	72			—			343			—
Deduct: total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effect	(180		)	(105		)	(636		)	(314		)
Pro forma net income (loss)	$	(7,086	)	$	(3,267	)	$	1,666		$	(5,374	)

Earnings (loss) per share:
Basic, as reported	$	(0.74	)	$	(0.34	)	$	0.21		$	(0.54	)
Basic, pro forma	$	(0.76	)	$	(0.35	)	$	0.18		$	(0.57	)
Diluted, as reported	$	(0.74	)	$	(0.34	)	$	0.21		$	(0.54	)
Diluted, pro forma	$	(0.75	)	$	(0.35	)	$	0.18		$	(0.57	)

Compensation expense for the variable plan, including restricted unit grants, is measured using the market price of MarkWest Energy Partners’ common units on the last trading day of the corresponding quarter 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.

13. Asset Retirement Obligations

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 will 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 $3.4 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 Unaudited Condensed Consolidated Balance Sheet in Other Long-Term Liabilities, was $3.8 million at September 30, 2003.

For the periods ended September 30, 2002, the pro forma effect on net income and earnings per share, had we adopted SFAS No. 143 on January 1, 2002, would have been as follows:

	Three Months Ended September 30, 2002						Nine Months Ended September 30, 2002
	As Reported			Pro Forma			As Reported			Pro Forma
	(in thousands, except per share data)
Net loss	$	(3,162	)	$	(3,512	)	$	(5,060	)	$	(6,110	)
Loss per share:
Basic	$	(0.34	)	$	(0.37	)	$	(0.54	)	$	(0.65	)
Diluted	$	(0.34	)	$	(0.37	)	$	(0.54	)	$	(0.65	)

The following is a reconciliation of the asset retirement obligation for the three months ended September 30, 2003 (in thousands):

Asset retirement obligation as of July 1, 2003	$	3,277
Liability accrued upon capital expenditures	479
Liability settled	(20		)
Accretion of discount expense	43
Asset retirement obligation as of September 30, 2003	$	3,779

14. Recent Accounting Pronouncements

In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150 (“SFAS No. 150”), “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” This statement establishes standards for the measurement and classification of certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise effective the first interim period beginning after June 15, 2003. The adoption of this standard did not have any impact on our financial position or results of operations.

In April 2003, the FASB issued Statement of Financial Accounting Standards No. 149 (“SFAS No. 149”), “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under Statement of Financial Accounting Standards No. 133 (“SFAS No. 133”), “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003 and should be applied prospectively. However, provisions related to SFAS No. 133 Implementation Issues effective for fiscal quarters beginning prior to June 15, 2003 should continue to be applied in accordance with their respective dates. The adoption of this standard did not have any impact on our financial position or results of operations.

15. Subsequent Events

MarkWest Hydrocarbon, Inc. Credit Facility Amendment

On October 6, 2003, we amended our credit facility (the “Credit Facility”) with various financial institutions. Prior to amendment the $60 million revolving credit facility was comprised of two components: (a) a $25 million U.S. facility and, (b) through our wholly owned Canadian subsidiary, a $35 million Canadian facility. The amendment terminated the Canadian portion of the facility and modified certain provisions of the U.S. facility to accommodate the new Canadian credit facility (“Canadian Credit Facility”) discussed below.

Available borrowings under the Credit Facility are determined by (a) a borrowing base, calculated semiannually, which is based principally on the proved reserves of our oil and gas properties (amended to be $0); and (b) a working capital borrowing base, calculated monthly, which is based on NGL product accounts receivable and inventory levels, to a maximum of $20 million ($13.7 million was available as of September 30, 2003). Actual borrowing limits may be less than $60 million, and MarkWest Hydrocarbon may be required to pay down amounts borrowed in excess of their applicable borrowing base, depending on proved reserves for our properties, our working capital and our financial covenants. At September 30, 2003, MarkWest Hydrocarbon had outstanding borrowings of $2.0 million under the Credit Facility.

The Credit Facility permits us to borrow money using a base rate loan, plus an applicable margin of 0.375% and 1.375%, or a London Interbank Offered Rate (“LIBOR”) loan option, plus an applicable margin of between 1.75% and 2.75%, based on a certain debt-to-earnings ratio. We pay fees of between 0.25% and 0.50% per annum on the unused commitment, based on our debt-to-earnings ratio. The Credit Facility matures in August 2004. For the year ended December 31, 2002, the weighted average interest rate was 4.88%.

The Credit Facility contains various covenants limiting our ability to:

• Incur indebtedness;

• Grant certain liens;

• Make certain investments or payments;

• Enter into certain leases;

• Enter into a merger or consolidation;

• Dispose of assets;

• Amend or enter into certain agreements;

• Conduct preferential transactions with certain affiliates; and

• Pay dividends.

The Credit Facility also contains covenants requiring us to maintain a minimum tangible net worth and meet certain financial ratios, as defined in the Credit Facility. The Credit Facility is secured by a first lien on substantially all of our assets, excluding our Partnership subordinated units and our interest in the Partnership’s general partner.

A new Canadian Credit Facility was entered into by our wholly owned Canadian subsidiary and was initially funded on October 6, 2003. Available borrowings under the Canadian Credit Facility are limited to the lesser of CDN$30 million and the “Borrowing Base” which is determined by the lender from time to time, and is based principally on the proved reserves of our oil and gas properties.

The Canadian Credit Facility permits us to borrow money using a prime rate loan, plus an applicable margin of 0.25% and 1.50%, or a base rate option, plus an applicable margin of between 1.50% and 2.75%, based on a certain debt-to-cash flow ratio. We pay a fee of 0.25% per annum on the unused commitment. The Canadian Credit Facility is subject to annual review, with the first review scheduled for May 31, 2004.

The Canadian Credit Facility contains various covenants limiting our ability to:

• Incur indebtedness;

• Grant certain liens;

• Enter into a merger or consolidation;

• Dispose of assets or move assets outside Alberta, Saskatchewan, British Columbia or Manitoba; and

• Pay dividends or repay shareholder loans.

The Canadian Credit Facility also contains covenants requiring us to meet certain financial ratios, as defined in the Canadian Credit Facility. The Canadian Credit Facility is secured by a first lien on substantially all of the assets of MarkWest Resources Canada Corp.

MarkWest Energy Partners Signs Agreement to Acquire Shell Crude Pipeline

On November 7, 2003, MarkWest Energy Partners entered into a Purchase and Sale Agreement with Shell Pipeline Company LP and other Shell subsidiaries, for the acquisition of Shell’s Michigan Crude Gathering Pipeline assets for approximately $21 million. The acquisition will be financed utilizing MarkWest Energy Partners’ existing credit facility, which it anticipates expanding in conjunction with the acquisition.

The crude gathering assets, located in northern Michigan, are comprised of approximately 250 miles of pipelines, 4 truck unloading stations, associated terminals and tank facilities. The system is a common carrier Michigan intrastate pipeline and gathers approximately 16,000 barrels per day of light crude oil from wells throughout Michigan. The oil is transported for a fee to the Lewiston station where it is batch injected into the Enbridge Lakehead Pipeline, which then transports the oil to refineries in Sarnia Ontario, Canada. The pipeline provides the producers in Michigan an alternative to trucking the crude to the Sarnia refinery complex.

MarkWest Hydrocarbon Signs Agreement to Sell Canadian Subsidiary

On November 12, 2003, MarkWest Hydrocarbon announced we had entered into a Purchase and Sale Agreement with Advantage Energy Income Fund to sell our wholly owned subsidiary, MarkWest Resources Canada Corp., for cash consideration of CDN$102.5 million, less debt and other liabilities assumed by Advantage Energy Income Fund. The sale price may be increased by up to an additional CDN$2.5 million if certain lands are retained through additional drilling prior to December 31, 2003.

We continue to evaluate options for our wholly owned subsidiary, MarkWest Canadian Midstream Services Inc., which holds natural gas exploration assets located in the Bigstone-Berland River area of west-central Alberta.

We plan to use the net proceeds from the sale to retire debt outstanding under our existing bank revolving credit facility and for general corporate purposes.

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 of Financial Condition and Results of Operations 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.

Sale of San Juan Basin Properties

During the third quarter of 2003, we completed the sales of the remainder of our San Juan Basin oil and gas properties to certain third parties for approximately $6.1 million, net of anticipated transaction costs and closing adjustments. Previously, we closed on the sale of the majority of our San Juan Basin properties in the second quarter of 2003. We recognized a net pretax gain of $3.3 million on the sales completed during the third quarter. The net proceeds from the sales are being used for working capital and general corporate purposes.

Terminal Dispositions

Pinnacle Acquisition

On March 28, 2003, our consolidated subsidiary, MarkWest Energy Partners, completed the Pinnacle Acquisition. 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 fixed-fee contracts to power plants. The twenty gathering systems gather more than 44 MMcf/d.

Lubbock Pipeline Acquisition

On September 2, 2003, through its wholly owned subsidiary, MarkWest Pinnacle L.P., MarkWest Energy Partners completed the acquisition of a 68-mile intrastate gas transmission pipeline near Lubbock, Texas from a subsidiary of ConocoPhillips for approximately $12.2 million. The transaction was financed through borrowings under MarkWest Energy Partners’ existing credit facility. The acquisition was accounted for as a purchase business combination.

Retirement of President and Chief Executive Officer and Appointment of Successor

The Boards of Directors of MarkWest Hydrocarbon and of the general partner of MarkWest Energy Partners announced on October 23, 2003, that John M. Fox, the current Chairman, President and Chief Executive Officer of MarkWest Hydrocarbon and the general partner of MarkWest Energy Partners, has advised them he will retire as Chief Executive Officer effective December 31, 2003. (The general partner of MarkWest Energy Partners is a consolidated subsidiary of MarkWest Hydrocarbon.) As part of the management transition, the Boards also announced the resignation of Mr. Fox as President effective November 1, 2003, and the appointment of Frank M. Semple as President as of such date. To facilitate an orderly transition, Mr. Fox will continue in his role as Chief Executive Officer during the remainder of the calendar year, after which time Mr. Semple will also assume the position of Chief Executive Officer.

Mr. Fox will remain a Director and Chairman of the Board of both MarkWest Hydrocarbon and the general partner of MarkWest Energy Partners. Mr. Fox founded MarkWest Hydrocarbon and has served as its President,

Chief Executive Officer and Chairman of the Board since its inception in April 1988. Mr. Fox has served in the same capacities for the general partner of MarkWest Energy Partners since May 2002.

Prior to accepting his appointment to MarkWest Hydrocarbon and the general partner of MarkWest Energy Partners, Mr. Semple served as Chief Operating Officer of WilTel Communications, formerly Williams Communications, a $1.5 billion revenue, 2,500-employee telecommunications company based in Tulsa, Oklahoma. Preceding that, he held the position of Senior Vice President/General Manager of Williams Natural Gas from 1995 to 1997 as well as Vice President of Marketing and Vice President of Operations and Engineering for Northwest Pipeline and Director of Product Movements and Division Manager for Williams Pipeline during his 22-year career with the Williams Companies. During his tenure at Williams Communications, he served on the board of directors for PowerTel Communications and the Competitive Telecommunications Association. He currently serves on the board of directors for the Tulsa Zoo and Children’s Medical Center. Mr. Semple holds a bachelor’s degree in mechanical engineering from the United States Naval Academy. He also completed the Program for Management Development at Harvard University.

MarkWest Energy Partners Signs Agreement to Acquire Shell Crude Pipeline

MarkWest Hydrocarbon Signs Agreement to Sell Canadian Subsidiary

During the third quarter of 2003, our Board of Directors approved a plan to sell our Canadian oil and gas properties. Management also intends to dispose of our remaining U.S. and Canadian oil and gas properties within the next year as we discontinue our exploration and production business.

We plan to use the net proceeds from the sale to retire debt outstanding under our existing bank revolving credit facility and for general corporate purposes.

Results of Operations

Operating Data

	Three Months Ended September 30,				Nine Months Ended September 30,
	2003	2002	% Change		2003	2002	% Change

Gathering, processing and marketing
Appalachia:
NGL product production—Siloam plant (gallons)	47,000,000	44,600,000	5	%	122,700,000	129,200,000	(5	)%
NGL product sales—Siloam plant (gallons)	40,800,000	37,200,000	10	%	125,700,000	128,600,000	(2	)%

Southwest(1)
Pipeline throughput (Mcf/d)	59,000	—	NM		51,000	—	NM

Michigan:
Pipeline throughput (Mcf/d)	17,300	16,900	2	%	15,700	13,400	17	%
NGL product sales (gallons)	3,982,000	3,212,000	24	%	9,112,000	8,081,000	13	%

Exploration and production
Natural gas produced (Mcfe/d)	20,900	31,100	(33	)%	24,400	29,800	(18	)%

NM – Not meaningful

(1)Acquired March 28, 2003, and September 2, 2003, MarkWest Energy Partners’ Southwest assets are located primarily in Texas and four surrounding states.

Three Months Ended September 30, 2003 Compared to the Three Months Ended September 30, 2002

Revenue. Revenue was $48.2 million for the three months ended September 30, 2003, compared to $29.5 million for the three months ended September 30, 2002, an increase of $18.9 million, or 63%. The Pinnacle Acquisition increased revenue $15.3 million. Higher NGL product sales prices and volumes from our Appalachian operations were partially offset by a reduction in gas marketing revenues, a result of reduced volumes sold. Third quarter 2002 results include a $1.8 million non-cash hedging ineffectiveness charge.

Purchased product costs. Purchased product costs were $44.5 million for the three months ended September 30, 2003, compared to $26.3 million for the three months ended September 30, 2002, an increase of $18.2 million, or 69%. The Pinnacle Acquisition increased purchased product costs $12.1 million, partially offset by a reduction in gas marketing purchased products costs of $4.1 million, a result of reduced volumes sold. Increased product costs and sales volumes from our Appalachian operations increased purchased product costs $8.8 million.

Facility expenses. Facility expenses were $5.3 million for the three months ended September 30, 2003, compared to $3.8 million for the three months ended September 30, 2002, an increase of $1.6 million, or 41%. The Pinnacle Acquisition and higher fuel costs in our Appalachian operations primarily caused the increase.

Selling, general and administrative expenses. Selling, general and administrative expenses were $3.4 million for the three months ended September 30, 2003, compared to $2.3 million for the three months ended September 30, 2002, an increase of $1.1 million, or 48%. The increase is principally attributable to the Pinnacle Acquisition, increased insurance costs and incremental costs associated with operating MarkWest Energy Partners as a public company.

Depreciation. Depreciation was $2.2 million for the three months ended September 30, 2003, compared to $1.3 million, for the three months ended September 30, 2002, an increase of $0.9 million, or 65%. Depreciation increased primarily due to the Pinnacle Acquisition.

Interest expense. Interest expense was $1.1 million for the three months ended September 30, 2003, compared to $0.8 million for the three months ended September 30, 2002, an increase of $0.4 million, or 51%. Interest expense increased due to a larger average outstanding debt balance, primarily a function of the financing of MarkWest Energy Partners’ 2003 acquisitions.

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.

Discontinued operations. We decided to exit the exploration and production business during the third quarter of 2003. Consequently, we have aggregated the results of operations, net of tax, from that business for separate disclosure in accordance with SFAS No. 144. We also sold the remaining portion of our San Juan Basin properties during the third quarter of 2003.

Nine Months Ended September 30, 2003 Compared to the Nine Months Ended September 30, 2002

Revenue. Revenue was $146.8 million for the nine months ended September 30, 2003, compared to $105.4 million for the nine months ended September 30, 2002, an increase of $41.3 million, or 39%. Revenue was higher in 2003 than in 2002 primarily due to:

• The Pinnacle Acquisition added $32.8 million.

• Increased NGL product sales prices offset modest volume decreases in Appalachia adding $28.5 million in revenue partially offset by $11.2 million of increased hedging losses in 2003.

• Gas marketing volumes declined primarily due to reduced volumes sold decreasing revenue $12.6 million.

• $1.7 million in non-cash hedging ineffectiveness charges in 2002 have substantially reversed during 2003.

Purchased product costs. Purchased product costs were $134.9 million for the nine months ended September 30, 2003, compared to $86.7 million for the nine months ended September 30, 2002, an increase of $48.2 million, or 54%. Purchased product costs were higher in 2003 primarily due to:

• The Pinnacle Acquisition added $26.6 million.

• Increased natural gas costs offset modest volume decreases in Appalachia adding $27.3 million in purchased product costs.

• Gas marketing volumes declined primarily due to reduced volumes sold decreasing purchased product costs $10.5 million.

Facility expenses. Facility expenses were $14.4 million for the nine months ended September 30, 2003, compared to $11.9 million for the nine months ended September 30, 2002, an increase of $2.4 million, or 20%. Facility operating expenses increased primarily due to the Pinnacle Acquisition and higher fuel costs in Appalachia.

Selling, general and administrative expenses. Selling, general and administrative expenses were $9.1 million for the nine months ended September 30, 2003, compared to $6.5 million for the nine months ended September 30, 2002, an increase of $2.5 million, or 39%. The increase is principally attributable to the Pinnacle Acquisition, increased insurance costs and incremental costs associated with operating MarkWest Energy Partners as a public company.

Depreciation. Depreciation was $5.8 million for the nine months ended September 30, 2003, compared to $4.2 million, for the nine months ended September 30, 2002, an increase of $1.5 million, or 36%. Depreciation increased primarily due to the Pinnacle Acquisition.

Interest expense. Interest expense was $4.2 million for both the nine months ended September 30, 2003, compared to $3.0 million for the nine months ended September 30, 2002, an increase of $1.2 million, or 42%. The settlement of interest rate swaps during the second quarter of 2003 increased interest expense $0.6 million. The remainder of the increase is principally attributable to an increase in the average outstanding debt balance during the third quarter of 2003, a result of financing MarkWest Energy Partners’ 2003 acquisitions.

Write-down of deferred financing costs. We wrote off $3.0 million in deferred financing costs in 2002 as a result of amending our credit facility twice.

Discontinued operations. We decided to exit the exploration and production business during the third quarter of 2003. Consequently, we have aggregated the results of operations, net of tax, from that business for separate disclosure in accordance with SFAS No. 144. We also sold our San Juan Basin properties during the second and third quarters of 2003.

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.

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 unusual disparity in prices reduced our internally generated cash flows through the second quarter and into the third quarter of 2003. However, this disparity in prices has substantially reversed beginning in the third quarter and is expected to remain near historical levels through the remainder of 2003.

To combat the reduction in cash flows and otherwise bolster our liquidity, we sold our San Juan Basin oil and gas properties during the second and third quarters of 2003 for approximately $55.9 million, net of anticipated transaction costs and closing adjustments. We recognized a net pretax gain of approximately $23.0 million on the sales. The proceeds from the sale were used to repay debt outstanding under our existing credit facility in the amount of approximately $42.6 million. The remaining proceeds are being used for general corporate purposes. Additionally, on November 12, 2003, we announced that we have entered into an agreement with a third party to sell one of our Canadian subsidiaries, which owns most of our Canadian oil and gas properties.

Almost all of our capital expenditures are discretionary. We continue to manage our future capital expenditures to match available cash flows from operations. As of September 30, 2003, MarkWest Hydrocarbon has borrowed $19.1 million of the approximate $31.7 million available credit under our credit facility.

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 Pinnacle Acquisition and the Lubbock Pipeline Acquisition were financed under MarkWest Energy Partners’ credit facility, which was expanded by $15 million on March 28, 2003. Additionally, MarkWest Energy Partners sold 375,000 common units in two installments at a price of $26.23 per unit in a private placement to certain accredited investors. These sales grossed $9.8 million and were completed July 10, 2003. As of September 30, 2003, MarkWest Energy Partners has borrowed $61.3 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 $3.6 million for the remainder of 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 and availability under our credit facility.

MarkWest Energy Partners’ budget for pipeline connections and other system improvements related to the Pinnacle Acquisition for the remainder of 2003 is $0.5 million. Under certain circumstances, the party from which MarkWest Energy Partners acquired the Pinnacle Acquisition has the right to require MarkWest Energy Partners to purchase an additional lateral pipeline for up to $2.5 million.

Cash Flows

Net cash provided by operating activities was $3.2 million and $33.9 million for the nine months ended September 30, 2003 and 2002, respectively. Net cash provided by operating activities decreased during the first nine months of 2003 primarily due to losses from our keep-whole contract based business.

Net cash used in investing activities was $17.8 million and $25.1 million for the nine months ended September 30, 2003 and 2002, respectively. Net cash used in investing activities was lower in 2003 due to the proceeds from the sale of our San Juan Basin properties, net of the Pinnacle Acquisition and the Lubbock Pipeline Acquisition.

Net cash provided by financing activities was $15.7 million during the first nine months of 2003. Net cash used in financing activities was $9.2 million during the first nine months of 2002. In 2003, we had net borrowings, primarily due to the financing of the Pinnacle Acquisition and the Lubbock Pipeline Acquisition. Additionally, MarkWest Energy Partners, raised capital via a private placement of 375,000 of its common units.

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. (We sold substantially all of our U. S. reserves during the second and third quarters. Additionally, our Board of Directors has approved a plan to sell all or part of our Canadian oil and gas properties.)

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.

Our fully consolidated subsidiary, MarkWest Energy Partners, is also subject to NGL price risk stemming from its percent-of-proceeds contracts in Appalachia and Michigan and natural gas price risk from the Pinnacle Acquisition. MarkWest Energy Partners gathers and transports natural gas for producers behind its gathering systems in Texas and four surrounding states, many under percent-of-proceeds or percent-of-index contracts.

Basis Risk

To the extent our natural gas production offsets 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 sales location (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 September 30, 2003, our natural gas basis hedges were as follows:

	Table I Hedged Natural Gas Basis
	Year Ending December 31, 2003
MMBtu	370,000
$/MMBtu	$	(0.71	)

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

We are an overall net consumer of natural gas as our keep-whole contractual requirements for purchasing natural gas in Appalachia exceed our natural gas production. Consequently, our exploration and production 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 exploration and production 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 September 30, 2003, we have hedged our Canadian natural gas volumes and prices as follows:

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

MMBtu	561,000		610,000		—
$/MMBtu	$	3.56	$	3.19	$	—
Henry Hub Equivalent	$	4.25	$	4.08	$	—

Regarding our natural gas price risk from the Pinnacle Acquisition, MarkWest Energy Partners enters into fixed-for-float swaps or buys puts thereby establishing a floor sales price. As of September 30, 2003, MarkWest Energy Partners hedged its Pinnacle natural gas price risk via swaps as follows:

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

MMBtu	46,000		183,000		183,000
$/MMBtu	$	5.09	$	4.57	$	4.26

As of September 30, 2003, MarkWest Energy Partners hedged its Pinnacle natural gas price risk via puts as follows:

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

MMBtu	92,000		366,000		—
Floor strike price ($/MMBtu)	$	4.50	$	4.00	$	—

NGL Product Price Risk

We hedge our NGL product sales by selling forward propane or crude oil. As of September 30, 2003, we have hedged NGL product sales, primarily in Appalachia, as follows:

	Table V Hedged Sales Price for NGL Products
	Year Ending December 31,
	2003		2004
MarkWest Hydrocarbon, Inc.
NGL Volumes Hedged Using Crude Oil
NGL gallons	13,455,000		10,135,000
NGL sales prices per gallon	$	0.46	$	0.53

MarkWest Energy Partners, L.P.
Butanes and Natural Gasoline Volumes Hedged Using Crude Oil
NGL gallons	869,000		—
NGL sales price per gallon	$	0.50	—
Propane Volumes Hedged Using Propane
NGL gallons	315,000		—
NGL sales price per gallon	$	0.41	—
Total NGL Volumes Hedged
NGL gallons	1,184,000		—
NGL sales price per gallon	$	0.48	—

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 September 30, 2003, we had no such hedges in place.

Interest Rate Risk

MarkWest Hydrocarbon, Inc.

We are exposed to changes in interest rates, primarily as a result of our long-term debt with floating interest rates. As of September 30, 2003, we were not a party to any financial instruments to manage this risk.

MarkWest Energy Partners, L.P.

MarkWest Energy Partners, our consolidated subsidiary, is exposed to changes in interest rates, primarily as a result of its long-term debt under its credit facility with floating interest rates. MarkWest Energy Partners may make use of interest rate swap agreements expiring May 19, 2005 to adjust the ratio of fixed and floating rates in the debt portfolio. As of September 30, 2002, MarkWest Energy Partners was a party to contracts to fix interest rates on $8.0 million of its debt at 3.84% compared to floating LIBOR, plus an applicable margin.

Item 4. Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms, and that information is accumulated and communicated to our management, including our principal executive and principal financial officers (who we refer to in this periodic report as our Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. Our management evaluated, with the participation of our Certifying Officers, the effectiveness of our disclosure controls and procedures as of September 30, 2003, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, our Certifying Officers concluded that as of September 30, 2003, our disclosure controls and procedures were effective.

There were no changes in our internal control over financial reporting that occurred during our most recently completed fiscal quarter that have materially affected, or are reasonably like to materially affect, our internal control over financial reporting.

PART II OTHER INFORMATION

Item 1. Legal Proceedings

Pursuant to the introductory instruction Part II (Other Information) of Form 10-Q, the information required to be furnished by us under this part II, Item 1 (Legal Proceedings) is incorporated by reference to Note 11 (Commitments and Contingencies) of our Notes to Unaudited Consolidated Financial Statements included in Part 1, Item 1 (Financial Statements) of this report on Form 10-Q.

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

10.1 Purchase and Sale Agreement, dated as of June 5, 2003, by and among MarkWest Hydrocarbon, Inc., MarkWest Resources, Inc. and XTO Energy Inc. (incorporated by reference to Exhibit 10 to the MarkWest Hydrocarbon’s current report on Form 8-K filed with the SEC on July 15, 2003)

10.2 Purchase and Sale Agreement dated as of July 31, 2003, among Raptor Natural Plains Marketing LLC, Raptor Gas Transmission LLC, Power-Tex Joint Venture and MarkWest Pinnacle L.P. (incorporated by reference to Exhibit 2.1 to MarkWest Energy Partners’ current report on Form 8-K filed with the SEC on September 17, 2003)

11 Statement regarding computation of earnings per share.

31.1 Chief Executive Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act.

31.2 Chief Financial Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act.

32.1 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.

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

(b) Reports on Form 8-K

A current report on Form 8-K was filed with the SEC under items 5 and 7 of Form 8-K on July 15, 2003, announcing the declaration by our Board of Directors of a stock dividend of one share of MarkWest Hydrocarbon’s common stock for each ten shares of common stock held by MarkWest Hydrocarbon’s common stockholders of record as of the close of business on July 31, 2003.

A current report on Form 8-K was filed with the SEC under items 2 and 7 of Form 8-K July 15, 2003, announcing the completion of our sale of the majority of our San Juan Basin oil and gas properties to XTO Energy Inc. for approximately $50.8 million in cash.

A current report on Form 8-K was filed with the SEC under items 5 and 7 of Form 8-K on August 4, 2003, announcing our consolidated subsidiary, MarkWest Energy Partners, through its subsidiary, MarkWest Pinnacle L.P., had entered into a Purchase and Sale Agreement with Power-Tex Joint Venture, a subsidiary of ConocoPhillips, to acquire an intrastate gas transmission pipeline near Lubbock, Texas for approximately $12 million.

A current report on Form 8-K was furnished with the SEC under items 7 and 12 of Form 8-K on August 13, 2003, concerning our second quarter 2003 earnings release dated August 13, 2003.

An amended current report on Form 8-K/A was filed with the SEC under items 2 and 7 of Form 8-K on August 26, 2003, announcing that our consolidated subsidiary, MarkWest Energy Partners, L.P., completed its acquisition of Pinnacle Natural Gas Company and certain affiliates on March 28, 2003. The amended report included the audited

financial statements of PNG Corporation and Subsidiaries.

A current report on Form 8-K was filed with the SEC under items 2 and 7 of Form 8-K on September 17, 2003, announcing our consolidated subsidiary, MarkWest Energy Partners, through its subsidiary, MarkWest Pinnacle L.P., completed its acquisition of an intrastate gas transmission pipeline near Lubbock, Texas, from Power-Tex Joint Venture, a subsidiary of ConocoPhillips, and certain of its affiliates, for approximately $12 million in cash.

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: November 13, 2003	By:	/s/ Donald C. Heppermann

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

EXHIBIT INDEX

10.1		Purchase and Sale Agreement, dated as of June 5, 2003, by and among MarkWest Hydrocarbon, Inc., MarkWest Resources, Inc. and XTO Energy Inc. (incorporated by reference to Exhibit 10 to the MarkWest Hydrocarbon’s current report on Form 8-K filed with the SEC on July 15, 2003)
10.2		Purchase and Sale Agreement dated as of July 31, 2003, among Raptor Natural Plains Marketing LLC, Raptor Gas Transmission LLC, Power-Tex Joint Venture and MarkWest Pinnacle L.P. (incorporated by reference to Exhibit 2.1 to MarkWest Energy Partners’ current report on Form 8-K filed with the SEC on September 17, 2003)
11		Statement regarding computation of earnings per share.
31.1		Chief Executive Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act.
31.2		Chief Financial Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act.
32.1		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.
32.2		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.