Explanatory Note

We have determined that, in certain cases, we did not comply with generally accepted accounting principles in the preparation of our 2003 and 2004 first quarter consolidated financial statements and, accordingly, this Amendment No. 1 on Form 10-Q/A amends the Quarterly Report on Form 10-Q originally filed by MarkWest Hydrocarbon, Inc. (the “Company”) on May 13, 2004 for the first quarter ended March 31, 2004.

The Company has determined that previously issued financial statements for the years 2002 and 2003 and the first three quarters of 2003 and 2004 should be restated to reflect compensation expense for the sale of subordinated units of MarkWest Energy Partners, L.P. (“MarkWest Energy Partners” or the “Partnership”) and interests in MarkWest Energy GP, LLC (the “general partner” of MarkWest Energy Partners, L.P., a consolidated subsidiary) to certain employees and directors of the Company from 2002 through 2004 and for an error in accounting for natural gas inventory in the fourth quarter of 2003. The Company is filing contemporaneously with this Form 10-Q/A for the quarterly period ended March 31, 2004, its Annual Report on Form 10-K for the year ended December 31, 2004, which includes restated financial statements for the years ended December 31, 2002 and 2003.

As discussed more fully in Note 10, Restatement and Reclassifications of Consolidated Financial Statements, to the consolidated financial statements, we have restated our previously reported results to account for the sale by the Company of a portion of its interests in the general partner to certain employees and directors of the Company, and the sale by the Company of its subordinated units of the Partnership to certain employees and directors of the Company as compensatory arrangements consistent with the guidance in Accounting Principles Board Opinion (“APB”) No. 25, Accounting for Stock Issued to Employees and Emerging Issues Task Force (“EITF”) No. 95-16, Accounting for Stock Compensation Arrangements with Employer Loan Features under APB Opinion No. 25. This guidance requires MarkWest Hydrocarbon to record compensation expense based on the market value of the subordinated Partnership units and the formula value of the general partner interests held by these employees and directors at the end of each reporting period. These transactions were previously reflected as sales of assets. In addition, certain other restatement adjustments have also been recorded to correct other errors in the financial statements for the first three quarters of 2004, including adjustments to accruals for revenue and purchased product costs, adjustments for costs improperly capitalized as property, plant and equipment, adjustments to properly record capitalized interest on major construction projects in process, adjustments to record as a financing lease, a lease agreement previously entered into by an acquired business, an adjustment to reflect separately restricted marketable securities and adjustments to accrued property taxes. Adjustments were also made to record compensation expense as a result of the modification of the provisions of certain stock options for two officers who terminated their employment with the Company but who continued to serve on its Board of Directors. Additionally, the Company made an adjustment to reclassify a portion of dividends paid during the three months ended March 31, 2004 from retained earnings to additional paid in capital for the amount of dividends distributed in excess of accumulated earnings. Other less significant adjustments and reclassifications were identified and recorded in conjunction with the restatement process as discussed in Note 10.

This Form 10-Q/A amends and restates only Items 1, 2 and 4 of Part I and Item 6 of Part II of the original report. The remaining items are not amended hereby. Except for the foregoing amended information, this Form 10-Q/A continues to describe conditions as of the date of the original report, and the Company has not updated the disclosures contained herein to reflect events that occurred subsequently. Accordingly, this Form 10-Q/A should be read in conjunction with Company filings made with the Securities and Exchange Commission subsequent to the filing of the original report, including any amendments of those filings.

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, 2004			December 31, 2003
	(as restated, see note 10)
ASSETS
Current assets:
Cash and cash equivalents	$	49,115		$	42,144
Marketable securities	4,430			—
Restricted marketable securities	2,500			2,500
Receivables, net (including related party receivables of $56 and $40, respectively, and net of allowance for doubtful accounts of $84 and $120, respectively)	24,814			29,910
Inventories	1,448			5,548
Prepaid replacement natural gas	15			5,940
Deferred income taxes	161			534
Other current assets	1,047			503
Total current assets	83,530			87,079

Property, plant and equipment	234,050			232,257
Less: accumulated depreciation, depletion and amortization	(46,981		)	(44,134		)
Total property, plant and equipment, net	187,069			188,123

Other assets:
Intangible assets, net	170			84
Deferred financing costs, net	3,507			3,747
Deferred offering costs, net	—			995
Investment in and advances to equity investee	245			250
Note receivables from officers	207			217
Other assets	23			—
Total assets	$	274,751		$	280,495

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable (including related party payables of $48 and $51, respectively)	$	23,296		$	24,052
Accrued liabilities	13,829			16,511
Fair value of derivative instruments	747			1,769
Total current liabilities	37,872			42,332

Deferred income taxes	5,801			5,594
Long-term debt	84,200			126,200
Fair value of derivative instruments	154			125
Other long-term liabilities	3,283			2,901
Non-controlling interest in consolidated subsidiary	94,173			52,429
Commitments and contingencies (Note 8)

Stockholders’ equity:
Preferred stock, par value $0.01, 5,000,000 shares authorized, no shares outstanding	—			—
Common stock, par value $0.01, 20,000,000 shares authorized, 10,732,017 and 10,601,775 shares issued, respectively	108			106
Additional paid-in capital	50,402			50,705
Retained earnings	—			2,406
Accumulated other Comprehensive loss, net of tax	(768		)	(1,793		)
Treasury stock at cost, 71,328 and 75,930 shares, respectively	(474		)	(510		)
Total stockholders’ equity	49,268			50,914
Total liabilities and stockholders’ equity	$	274,751		$	280,495

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except per share data)

	Three Months Ended March 31,
	2004			2003
	(as restated, see note 10)

Revenues	$	93,700		$	51,231

Operating expenses:
Purchased product costs	75,488			46,003
Facility expenses	6,086			4,632
Selling, general and administrative expenses	5,314			2,624
Depreciation	3,528			1,602
Amortization of intangible assets	34			—
Total operating expenses	90,450			54,861

Income (loss) from operations	3,250			(3,630		)

Other income (expense):
Interest expense, net	(995		)	(754		)
Amortization of deferred financing costs (a component of interest expense)	(307		)	(309		)
Other income (expense)	25			(15		)
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	1,973			(4,708		)

Provision (benefit) for income taxes:
Current	(14		)	(2,144		)
Deferred	(42		)	93
Provision (benefit) for income taxes	(56		)	(2,051		)

Non-controlling interest in net income of consolidated subsidiary	(1,309		)	(857		)

Income (loss) from continuing operations	720			(3,514		)

Income from discontinued exploration and production operations (net of income tax of $1,143)	—			2,130

Income (loss) before cumulative effect of accounting change	720			(1,384		)

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

Net income (loss)	$	720		$	(1,413	)
Income (loss) from continuing operations per share:
Basic	$	0.07		$	(0.34	)
Diluted	$	0.07		$	(0.34	)
Net income (loss) per share:
Basic	$	0.07		$	(0.14	)
Diluted	$	0.07		$	(0.14	)
Weighted average number of outstanding shares of common stock:
Basic	10,577			10,298
Diluted	10,595			10,302
Cash dividend per common share	$	0.455		$	—

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME

(UNAUDITED)

(in thousands)

	Three Months Ended March 31,
	2004		2003
	(as restated, see note 10)

Net income (loss)	$	720	$	(1,413	)

Other Comprehensive income, net of tax:
Foreign currency translation	—		2,264
Unrealized gains (losses) on commodity derivatives accounted for as hedges	872		(393		)
Unrealized gain on marketable securities	153		—
Total other Comprehensive income	1,025		1,871

Other Comprehensive income	$	1,745	$	458

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)

	Three Months Ended March 31,
	2004			2003
	(as restated, see note 10)
Cash flows from operating activities:
Net income (loss)	$	720		$	(1,413	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Cumulative effect of change in accounting principle	—			29
Depreciation and depletion	3,528			5,098
Amortization of deferred financing costs	307			309
Amortization of intangible assets	34			—
Stock option compensation expense	358			—
Restricted unit compensation expense	374			212
Participation Plan compensation expense	402			53
Contribution of treasury shares to 401(k) benefit plan	72			91
Equity in loss of investee	5			—
Gain from sale of property, plant and equipment	(63		)	—
Non-controlling interest in net income of consolidated subsidiary	1,309			857
Unrealized losses (gains) on derivative instruments	476			(922		)
Reclassification of Enron hedges to purchased product costs	—			(18		)
Deferred income taxes	(41		)	1,180
Other	—			28
Changes in operating assets and liabilities:
(Increase) decrease in receivables	5,096			(3,844		)
Decrease in inventories	4,100			1,124
(Increase) decrease in prepaid replacement natural gas	5,925			(907		)
(Increase) decrease in other current assets	(535		)	34
Increase (decrease) in accounts payable and accrued liabilities	(4,694		)	7,708
Net cash flow provided by operating activities	17,373			9,619

Cash flows from investing activities:
Purchase of marketable securities	(4,277		)	—
Pinnacle acquisition, net of cash acquired	—			(38,238		)
Capital expenditures	(1,629		)	(6,735		)
Proceeds from sales of assets	94			24
Proceeds on financing lease receivable	133			—
Other	3			—
Net cash used in investing activities	(5,676		)	(44,949		)

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

	Three Months Ended March 31,
	2004			2003
	(as restated, see Note 10)

Cash flows from financing activities:
Proceeds from long-term debt	—			45,700
Repayment of long-term debt	(42,000		)	(6,500		)
Payments for debt issuance costs	—			(810		)
Proceeds from MarkWest Energy Partners’ secondary public offering	44,102			—
Distribution to MarkWest Energy Partners’ unitholders	(3,007		)	(1,509		)
Exercise of stock options	1,017			—
Repurchase of treasury shares	(36		)	(167		)
Payment of dividends	(4,802		)	—
Net cash provided by (used in) financing activities	(4,726		)	36,714

Effect of exchange rate changes on cash	—			114

Net increase in cash and cash equivalents	6,971			1,498
Cash and cash equivalents at beginning of period	42,144			6,410
Cash and cash equivalents at end of period	$	49,115		$	7,908

Supplemental cash flow information:
Construction projects in progress obligation	$	1,199		$	—
Cash paid for interest, net of amounts capitalized	$	1,459		$	382

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENT OF CHANGES IN

STOCKHOLDERS’ EQUITY

(UNAUDITED)

(in thousands)

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

Balance, December 31, 2003, as restated, see note 10	10,602	(76	)	$	106	$	50,705		$	2,406		$	(1,793	)	$	(510	)	$	50,914

Stock options exercised	130	—		2		1,015			—			—			—			1,017

Modification of stock options, as restated, see note 10	—	—		—		358			—			—			—			358

Treasury stock acquired	—	(3	)	—		—			—			—			(36		)	(36		)

Treasury stock reissued	—	8		—		—			—			—			72			72

Dividends, as restated, see note 10	—	—		—		(1,676		)	(3,126		)	—			—			(4,802		)

Net income, as restated, see note 10	—	—		—		—			720			—			—			720

Other Comprehensive income	—	—		—		—			—			1,025			—			1,025

Balance, March 31, 2004, as restated, see note 10	10,732	(71	)	$	108	$	50,402		$	—		$	(768	)	$	(474	)	$	49,268

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

MARKWEST HYDROCARBON, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. General

MarkWest Hydrocarbon, Inc. (“MarkWest Hydrocarbon” or the “Company”) manages MarkWest Energy Partners, L.P. (“MarkWest Energy Partners” or the “Partnership”), a publicly-traded master limited partnership engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids (NGLs); and the gathering and transportation of crude oil. The Company also markets natural gas and NGLs. MarkWest Hydrocarbon and MarkWest Energy Partners provide services primarily in the Southwest, Appalachia and Michigan.

The Company’s assets consist primarily of partnership interests in MarkWest Energy Partners. As of March 31, 2004, the Company’s partnership interests consisted of 2,470,996 subordinated units, representing a 35% limited partner interest in the Partnership and a 90% membership (ownership) interest in MarkWest Energy GP, L.L.C., the general partner of the Partnership, which owns a 2% general partner interest and all of the incentive distribution rights in the Partnership.

The consolidated financial statements include the accounts of MarkWest Hydrocarbon and its subsidiaries, including MarkWest Energy Partners. Through consolidation, the Company has eliminated all significant intercompany accounts and transactions.

The Company has 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. You should read these consolidated financial statements and notes thereto along with the audited financial statements and notes thereto as of and for the year ended December 31, 2003 (which have been restated) included in the Company’s December 31, 2004 Annual Report on Form 10-K. In the opinion of management, the Company has made all necessary adjustments for a fair statement of the results for the unaudited interim periods. All such adjustments are of a recurring nature. Results for the three months ended March 31, 2004, are not necessarily indicative of results for the full year 2004 or any other future period.

The Company bases the effective corporate tax rate for interim periods on the estimated annual effective corporate tax rate.

2. Marketable Securities

Marketable securities are classified as available-for-sale and stated at market based on the closing price of the securities at the balance sheet date. Accordingly, unrealized gains or losses are reflected in other Comprehensive income, net of applicable income taxes. For losses that are other than temporary, the cost basis of the securities is written down to fair value and the amount of the write down is reflected in the statement of operations. The Company utilizes a weighted-average cost basis to compute realized gains and losses. Realized gains and losses, and dividend and interest income, are reflected in earnings.

Debt and equity securities are classified as available-for-sale. The following are the components of marketable securities (in thousands):

March 31, 2004(as restated, see note 10)	Cost Basis		Unrealized gains		Unrealized losses			Recorded Basis
Equity securities:
Master limited partnership units	$	4,277	$	179	$	(26	)	$	4,430
Equity securities, classified as current	4,277		179		(26		)	4,430
Fixed maturities:
Mortgage backed securities (due after one year through five years)	$	2,500	$	—	$	—		$	2,500
Fixed Maturities, classified as non-current	2,500		—		—			2,500
Total marketable securities	$	6,777	$	179	$	(26	)	$	6,930

December 31, 2003(as restated, see note 10)	Cost Basis		Unrealized gains		Unrealized losses		Recorded Basis
Restricted fixed maturities:
Mortgage backed securities (due December 2007)	$	2,500	$	—	$	—	$	2,500
Total restricted marketable securities	$	2,500	$	—	$	—	$	2,500

At March 31, 2004, unrealized gains of $0.2 million and unrealized losses of less than $0.1 million relate primarily to investments in domestic equity securities in energy partnerships.

3. Acquisitions by MarkWest Energy Partners

Pinnacle Acquisition

On March 28, 2003, the Partnership 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, “Pinnacle” or the “Sellers”). Pinnacle’s results of operations have been included in the Company’s consolidated financial statements since that date.

The Pinnacle Acquisition was accomplished through a merger under Texas law of the Sellers and four newly formed wholly owned subsidiaries of the Partnership as buyers. In the merger, most of the assets and liabilities of the Sellers were allocated to the Partnership 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	8,945
Total	$	48,866

Allocation of acquisition costs:
Current assets	$	10,643
Fixed assets (including long-term contracts)	38,223
Total	$	48,866

Western Oklahoma Acquisition

On December 1, 2003, the Partnership completed the acquisition of certain assets of American Central Western Oklahoma Gas Company, L.L.C. (“AWOC”) for approximately $38.0 million. Results of operations for the acquired assets have been included in the Company’s consolidated financial statements since that date.

The assets include the Foss Lake gathering system located in the western Oklahoma counties of Roger Mills and Custer. The gathering system is comprised of approximately 167 miles of pipeline, connected to approximately 270 wells, and 11,000 horsepower of compression facilities. The assets also include the Arapaho gas processing plant that was installed during 2000.

The purchase price of approximately $38.0 million was financed through borrowings under the Partnership line of credit, which was amended at the closing of the acquisition to increase availability under the credit facility from $75.0 million to $140.0 million. Substantially all of the acquired assets are pledged to the credit facility lenders to secure the repayment of the outstanding borrowings under the credit facility.

The purchase price was comprised of $38.0 million paid in cash to AWOC, and was allocated as follows (in thousands):

Acquisition costs:
Cash consideration	$	37,850
Direct acquisition costs	101
Total	$	37,951

Allocation of acquisition costs:
Property, plant and equipment	$	37,951

Michigan Crude Pipeline

On December 18, 2003, the Partnership completed the acquisition (the “Michigan Crude Pipeline acquisition”) of Shell Pipeline Company, LP’s and Equilon Enterprises, LLC’s, doing business as Shell Oil Products US (“Shell”), Michigan Crude Gathering Pipeline (the “System”), for approximately $21.3 million. The System’s results of operations have been included in the Company’s consolidated financial statements since December 18, 2003. The $21.3 million purchase price was financed through borrowings under the Partnership’s line of credit.

The System extends from production facilities near Manistee, Michigan to a storage facility near Lewiston, Michigan. The trunk line consists of approximately 150 miles of pipe. Crude oil is gathered into the System from 57 injection points, including 52 central production facilities and five truck unloading facilities, and comprises approximately 100 miles of pipe. The System also includes truck-unloading stations at Manistee, Seeley Road and Junction, and the Samaria Truck Unloading Station located in Monroe County, Michigan, near Toledo, Ohio.

The System is a common carrier Michigan intrastate pipeline and gathers light crude oil from wells. The oil is transported for a fee to the Lewiston, Michigan station where it is batch injected into the Enbridge Lakehead Pipeline.

The purchase price was comprised of $21.3 million paid in cash to Shell plus direct acquisition costs and was allocated as follows (in thousands):

Acquisition costs:
Cash consideration	$	21,155
Direct acquisition costs	128
Total	$	21,283

Allocation of acquisition costs:
Property, plant and equipment	$	21,283

Pro Forma Results of Operations (Unaudited)

The following table reflects the unaudited pro forma consolidated results of operations for the comparable period presented, as though the Pinnacle acquisition, the Western Oklahoma acquisition and Michigan Crude Pipeline acquisition each had occurred on January 1, 2003. The unaudited pro forma results have been prepared for comparative purposes only and may not be indicative of future results.

	Three Months Ended March 31, 2003
	MarkWest Hydrocarbon			Pinnacle		Western Oklahoma		Michigan Crude Pipeline		Adjustments			Total
	(in thousands, except per share data)
	(as restated, see note 10)												(as restated, see note 10)
Revenue	$	51,231		$	18,614	$	11,083	$	1,110	$	(827	)	$	81,211
Net income	$	(1,413	)	$	1,114	$	16	$	494	$	(1,297	)	$	(1,086	)
Basic net loss per share	$	(0.14	)										$	(0.11	)
Diluted net loss per share	$	(0.14	)										$	(0.11	)

Subsequent Event

On April 1, 2004, the Partnership acquired the Hobbs Lateral pipeline for approximately $2.3 million. The Hobbs Lateral pipeline consists of a four-mile pipeline, with a capacity of 160 million cubic feet of natural gas per day, connecting the Northern Natural Gas interstate pipeline to Southwestern Public Service’s Cunningham and Maddox power generating stations in Hobbs, New Mexico. The Hobbs Lateral pipeline is a New Mexico intrastate pipeline regulated by the Federal Energy Regulatory Commission.

4. Property, Plant and Equipment

The following provides the composition of the Company’s property, plant and equipment at:

	March 31,			December 31,
	2004			2003
	(in thousands)
	(as restated, see note 10)
Property, plant and equipment:
Gas gathering facilities	$	74,955		$	73,424
Gas processing plants	56,289			55,888
Fractionation and storage facilities	22,387			22,160
Natural gas pipelines	38,817			38,790
Crude oil pipelines	18,329			18,352
NGL transportation facilities	4,415			4,415
Marketing assets	1,606			1,987
Oil and gas properties and equipment, full cost method	2,495			2,380
Land, buildings and other equipment	12,915			12,499
Construction in-progress	1,842			2,362
	234,050			232,257
Less: Accumulated depreciation, depletion, amortization and impairment	(46,981		)	(44,134		)
Total property, plant and equipment, net	$	187,069		$	188,123

5. Adoption of SFAS No. 143

In June 2001, the Financial Accounting Standards Board issued Statement No. 143, Accounting for Asset Retirement Obligations. The Company adopted SFAS No. 143 beginning January 1, 2003. The most significant impact of this standard on the Company was a change in the method of accruing for site restoration costs. Under SFAS No. 143, the fair value of asset retirement obligations is recorded as a liability when incurred, which is typically at the time the assets are placed in service. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities are accreted for the change in their present value and the initial capitalized costs are depreciated over the useful lives of the related assets.

The cumulative effect of this accounting change for years prior to 2003 was less than $0.1 million and is reflected in the Company’s statement of operations for the three months ended March 31, 2003. At the time of adoption, the Company recorded an asset retirement obligation of $3.4 million, decreased a site restoration liability of $0.9 million that was recorded prior to the implementation of SFAS No. 143 and increased net property, plant and equipment $2.4 million in accordance with the provisions of SFAS No. 143. For the three months ended March 31, 2003, the impact on earnings per share from the cumulative effect of the change in accounting for asset retirement obligations was not significant. The asset retirement obligation, which is included on the consolidated balance sheet in other long-term liabilities, was $0.5 million and $2.4 million at March 31, 2004 and December 31, 2003, respectively.

6. MarkWest Energy Partners’ Secondary Public Offering

On January 12, 2004, the Partnership priced its offering of 1,148,000 common units at $39.90 per unit. Of the 1,148,000 common units, 1,100,444 were sold by the Partnership for gross proceeds of $43.9 million. The remaining 47,556 were sold by certain selling unitholders, proceeds of which were retained by them. In connection with the over-allotment provisions of the underwriting agreement, the Partnership issued an additional 72,500 common units for gross proceeds of $2.9 million. Aggregate gross proceeds of $46.8 million were reduced by underwriters’ fees of $2.5 million and professional fees and other offering costs of $1.3 million, resulting in net proceeds of $43.0 million. The net proceeds of $43.0 million and the $0.9 million contributed by the general partner to maintain its 2% interest resulted in total net proceeds to the Partnership associated with the offering of $43.9 million, which were used to pay down the Partnership’s credit facility.

7. Segment Reporting

The Company’s operations are classified into two reportable segments:

(1) Managing MarkWest Energy Partners—the Company operates MarkWest Energy Partners, a publicly-traded master limited partnership engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids; and the gathering and transportation of crude oil.

(2) Marketing—the Company sells its equity and third party NGLs, purchases third party natural gas and sells its equity and third party natural gas. Since February 2004, the Company is also engaged in the wholesale marketing of propane.

During 2003, the Company discontinued its exploration and production business segment. The Company’s continuing operations are conducted solely in the United States.

The table below presents information about operating income (loss) for the reported segments for the three months ended March 31, 2004 and 2003. Segment operating income (loss) includes total revenues less purchased product costs, facility expenses, depreciation and amortization of intangible assets. Items excluded from segment operating income (loss) are reflected in the reconciliation of total segment operating income (loss) to income (loss) from continuing operations before taxes. The Company has not reported asset information by reportable segment because it does not produce such information internally.

	Marketing			MarkWest Energy Partners		Eliminating Entries			Total
	(in thousands)
Three Months Ended March 31, 2004 (1)
Revenues from external customers	$	44,169		$	49,531	$	—		$	93,700
Intersegment revenues	$	224		$	14,294	$	(14,518	)	$	—
Segment operating income	$	2,061		$	6,503	$	—		$	8,564

Three Months Ended March 31, 2003
Revenues from external customers	$	46,932		$	4,299	$	—		$	51,231
Intersegment revenues	$	267		$	13,394	$	(13,661	)	$	—
Segment operating income (loss)	$	(4,625	)	$	3,619	$	—		$	(1,006	)

A reconciliation of total segment operating income (loss) to income (loss) from continuing operations before non-controlling interest in net income of consolidated subsidiary and income taxes is as follows:

	Three Months Ended March 31,
	2004 (1)			2003 (1)
	(in thousands)
Total segment operating income (loss)	$	8,564		$	(1,006	)
Selling, general and administrative expenses	(5,314		)	(2,624		)
Interest expense, net	(995		)	(754		)
Amortization of deferred financing costs	(307		)	(309		)
Other income (expense)	25			(15		)
Income (loss) from continuing operations before non- controlling interest in net income of consolidated subsidiary and income taxes	$	1,973		$	(4,708	)

(1) As restated, see Note 10.

8. Commitments and Contingencies

The Company is 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 its financial position or results of operations.

9. Stock and Unit Compensation

As permitted under SFAS No. 123, Accounting for Stock-Based Compensation, the Company has elected to continue to measure compensation costs for stock-based and unit-based employee compensation plans as prescribed by APB No. 25, Accounting for Stock Issued to Employees, as permitted under SFAS No. 123, Accounting for Stock Based Compensation, and SFAS No. 148, Accounting for Stock Based Compensation — Transition and Disclosure. The Company has two fixed compensation plans and two variable plans, one of which is through its consolidated subsidiary, MarkWest Energy. The Company accounts for these plans using fixed and variable accounting as appropriate.

Stock Option Plans

The Company’s stock options are issued under a fixed plan. Accordingly, compensation expense is not recognized for stock options unless the options are granted at an exercise price lower than market on the grant date. During the three months ended March 31, 2004, two officers resigned from the Company. As the former officers continued to serve on the Company’s Board of Directors, the Company agreed that the individual’s stock options would continue to vest and be exercisable in accordance with the original vesting and exercise provisions. As a result of the modification to the stock options for these officers the outstanding stock options are to be accounted for as variable awards, and as a result the Company recorded compensation expense of $0.4 million for the three months ended March 31, 2004, measured as the difference in the market value of the Company’s common stock on the date the officer’s status changed and the strike price of the outstanding stock options.

Participation Plan

The Company has also entered into arrangements with certain directors and officers of the Company. These arrangements are referred to as the Participation Plan. Under the Participation Plan, MarkWest Hydrocarbon sells subordinated partnership units of the Partnership and interests in the Partnership’s general partner to employees and directors of the Company under a purchase and sale agreement. In accordance with the provisions of APB No. 25, the Participation Plan is accounted for as a variable plan. Since the employee and director are 100% vested on the date they purchase the subordinated units or general partner interests, compensation expense for the subordinated units is measured as the difference in the market value of the subordinated Partnership units and the amount paid by those individuals. Compensation related to the general partner interest is calculated as the difference in the formula value and the amount paid by those individuals. The formula value is the amount MarkWest Hydrocarbon would have to pay the directors and employees to repurchase the general partner interests and is based on the current market value of the Partnership’s common units and the current quarterly distribution paid by the Partnership. Increases or decreases in the market value of the subordinated units and the formula value of the general partner interests between the date they are acquired and the end of each reporting period result in a change in the measure of compensation, which is reflected currently in operations. The Company recorded compensation expense of $0.4 million and $0.1 million for the three months ended March 31, 2004 and 2003, respectively. These charges are included in selling, general and administrative expenses.

MarkWest Energy Partners Long-Term Incentive Plan

The Partnership issues restricted units under the MarkWest Energy Partners, L.P. Long-Term Incentive Plan. A restricted unit is a “phantom” unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit, or at the discretion of the Compensation Committee, cash equivalent to the value of a common unit. In accordance with APB No. 25, the Partnership applies variable accounting for the plan because a phantom unit is an award to an employee entitling them to increases in the market value of the Partnership’s units subsequent to the date of grant without issuing units to the employees, similar to a stock appreciation right. As a result, the Partnership is required to mark to market the awards at the end of each reporting period. Compensation expense is measured for the phantom unit grants using the market price of MarkWest Energy’s common units on the date the units are granted. The fair value of the units awarded is amortized into earnings over the period of service, adjusted quarterly for the change in the fair value of the unvested units granted. The phantom units vest over a stated period. For certain employees vesting is accelerated if certain performance measures are met. The accelerated vesting criteria provisions are based on annualized distribution goals. If the Partnership’s distributions are at or above the goal for a

certain number of consecutive quarters, vesting of the employee’s phantom units is accelerated. However, the vesting of any phantom units may not occur until at least one year following the date of grant. The general partner of the Partnership may also elect to accelerate the vesting of outstanding awards, which results in an immediate charge to operations for the unamortized portion of the award. During the three months ended March 31, 2004 and 2003, 2,500 and 1,000 restricted units, respectively, were granted. The Partnership recorded compensation expense of $0.4 million and $0.2 million for the three months ended March 31, 2004 and 2003, respectively. These charges are included in selling, general and administrative expenses.

Had compensation cost for the Company’s stock-based and unit-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, , the Company’s net income (loss) and net income (loss) per share would have been revised to the pro forma amounts listed below:

	Three Months Ended March 31,
	2004			2003
	(in thousands, except per share data)
	(as restated, see note 10)			(as restated, see note 10)

Net income (loss), as reported	$	720		$	(1,413	)
Add: compensation expense included in reported net income (loss)	1,134			265
Deduct: total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effect	(803		)	(338		)
Pro forma net income (loss)	$	1,051		$	(1,486	)

Net income (loss) per share:
Basic:
As reported	$	0.07		$	(0.14	)
Pro forma	$	0.10		$	(0.14	)
Diluted:
As reported	$	0.07		$	(0.14	)
Pro forma	$	0.10		$	(0.14	)

10. Restatement and Reclassifications of Consolidated Financial Statements

The Company has determined that, in certain cases, it did not comply with generally accepted accounting principles in the preparation of its 2003 and 2004 consolidated financial statements and, accordingly, the Company has restated its consolidated financial statements for the quarterly periods ended March 31, 2004 and 2003.

The restatements primarily result from compensation expense attributed to the sale of a portion of MarkWest Hydrocarbon’s subordinated Partnership units and interests in the Partnership’s general partner to certain of its employees and directors from 2002 through 2004. MarkWest Hydrocarbon had historically recorded the sale of the subordinated Partnership units and interests in the general partner to certain of MarkWest Hydrocarbon’s employees and directors as a sale of an asset. These arrangements are referred to as the Participation Plan. However, MarkWest Hydrocarbon determined that these transactions should be accounted for as compensatory arrangements, pursuant to the guidance in APB No. 25, Accounting for Stock Issued to Employees and EITF No. 95-16, Accounting for Stock Compensation Arrangements with Employer Loan Features under APB Opinion No. 25. This guidance requires MarkWest Hydrocarbon to record compensation expense based on the market value of the subordinated Partnership units and the formula value of the general partner interests held by the employees and directors at the end of each reporting period. In addition, certain other restatement adjustments have also been recorded to correct other errors in the financial statements for the first three quarters of 2004, including adjustments to accruals for revenue and purchased product costs, adjustments for costs improperly capitalized as property, plant and equipment, adjustments to properly record capitalized interest on major construction projects in process,

Balance Sheet Amounts (in thousands):

	March 31, 2004
	As Previously Reported			Adjustments			As Restated
	(in thousands, except share and per share data)
ASSETS
Current assets:
Cash and cash equivalents	$	49,115		$	—		$	49,115
Restricted cash	2,500			(2,500		)(1)	—
Marketable securities	4,430			—			4,430
Restricted marketable securities	—			2,500		(1)	2,500
Receivables, net	24,751			63		(2)	24,814
Inventories	1,448			—			1,448
Prepaid replacement natural gas	15			—			15
Deferred income taxes	230			(69		)(3)	161
Other current assets	1,047			—			1,047
Total current assets	83,536			(6		)	83,530

Property, plant and equipment	234,756			(706		)(4)	234,050
Less: accumulated depreciation, depletion and amortization	(47,432		)	451		(5)	(46,981		)
Total property, plant and equipment, net	187,324			(255		)	187,069

Other assets:
Intangible assets, net	3,507			(3,337		)(6)	170
Deferred financing costs, net	—			3,507		(7)	3,507
Investment in and advances to equity investee	245			—			245
Note receivables from officers and directors	207			—			207
Other assets	65			(42		)(8)	23
Total assets	$	274,884		$	(133	)	$	274,751

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	22,893		$	403	(9)	$	23,296
Accrued liabilities	14,284			(455		)(10)	13,829
Fair value of derivative instruments	747			—			747
Total current liabilities	37,924			(52		)	37,872

Deferred income taxes	7,048			(1,247		)(11)	5,801
Long-term debt	84,200			—			84,200
Fair value of derivative instruments	154			—			154
Other long-term liabilities	504			2,779		(12)	3,283
Non-controlling interest in consolidated subsidiary	94,797			(624		)(13)	94,173

Commitments and contingencies

Stockholders’ equity:
Preferred stock, par value $0.01, 5,000,000 shares authorized, no shares outstanding	—			—			—
Common stock, par value $0.01, 20,000,000 shares authorized, 10,732,017 shares issued	108			—			108
Additional paid-in capital	51,720			(1,318		)(14)	50,402
Accumulated deficit	(329		)	329		(15)	—
Accumulated other Comprehensive loss, net of tax	(768		)	—			(768		)
Treasury stock at cost, 71,328 shares	(474		)	—			(474		)
Total stockholders’ equity	50,257			(989		)	49,268
Total liabilities and stockholders’ equity	$	274,884		$	(133	)	$	274,751

	December 31, 2003
	As Previously Reported			Adjustments			As Restated
	(in thousands, except share and per share data)
ASSETS
Current assets:
Cash and cash equivalents	$	42,144		$	—		$	42,144
Restricted cash	2,500			(2,500		)(16)	—
Restricted marketable securities	—			2,500		(16)	2,500
Receivables, net	30,750			(840		)(17)	29,910
Inventories	4,815			733		(18)	5,548
Prepaid replacement natural gas	5,940			—			5,940
Deferred income taxes	603			(69		)(19)	534
Other current assets	503			—			503
Total current assets	87,255			(176		)	87,079

Property, plant and equipment	232,257			—			232,257
Less: accumulated depreciation, depletion and amortization	(44,134		)	—			(44,134		)
Total property, plant and equipment, net	188,123			—			188,123

Other assets:
Intangible assets, net	3,831			(3,747		)(20)	84
Deferred financing costs, net	—			3,747		(20)	3,747
Deferred offering costs and other, net	1,037			(42		)(21)	995
Investment in and advances to equity investee	250			—			250
Note receivables from officers	217			—			217
Total assets	$	280,713		$	(218	)	$	280,495

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	24,052		$	—		$	24,052
Accrued liabilities	16,751			(240		)(22)	16,511
Fair value of derivative instruments	1,769			—			1,769
Total current liabilities	42,572			(240		)	42,332

Deferred income taxes	6,346			(752		)(23)	5,594
Long-term debt	126,200			—			126,200
Fair value of derivative instruments	125			—			125
Other long-term liabilities	504			2,397		(24)	2,901
Non-controlling interest in consolidated subsidiary	52,782			(353		)(25)	52,429

Commitments and contingencies

Stockholders’ equity:
Preferred stock, par value $0.01, 5,000,000 shares authorized, no shares outstanding	—			—			—
Common stock, par value $0.01, 20,000,000 shares authorized, 10,601,775 shares issued	106			—			106
Additional paid-in capital	50,705			—			50,705
Retained earnings	3,676			(1,270		)	2,406
Accumulated other Comprehensive loss, net of tax	(1,793		)	—			(1,793		)
Treasury stock at cost, 75,930 shares	(510		)	—			(510		)
Total stockholders’ equity	52,184			(1,270		)	50,914
Total liabilities and stockholders’ equity	$	280,713		$	(218	)	$	280,495

Income Statement Amounts:

	Three Months Ended March 31, 2004
	As Previously Reported			Adjustments			As Restated
	(in thousands, except per share data)

Revenues	$	93,426		$	274	(26)	$	93,700

Operating expenses:
Purchased product costs	75,135			353		(27)	75,488
Facility expenses	5,975			111		(28)	6,086
Selling, general and administrative expenses	4,268			1,046		(29)	5,314
Depreciation	3,458			70		(30)	3,528
Amortization of intangible assets	—			34		(31)	34
Total operating expenses	88,836			1,614			90,450

Income from operations	4,590			(1,340		)	3,250

Other income (expense):
Interest expense, net	(1,358		)	363		(32)	(995		)
Amortization of deferred financing costs (a component of interest expense)	—			(307		)(33)	(307		)
Other income	62			(37		)(34)	25
Income before non-controlling interest in net income of consolidated subsidiary and income taxes	3,294			(1,321		)	1,973

Provision for income taxes:
Current	115			(129		)	(14		)
Deferred	512			(554		)	(42		)
Provision for income taxes	627			(683		)(35)	(56		)

Non-controlling interest in net income of consolidated subsidiary	(1,693		)	384		(36)	(1,309		)

Income from continuing operations	974			(254		)	720

Loss from discontinued exploration and production operations (net of income tax benefit of $104)	(177		)	177		(37)	—

Net income	$	797		$	(77	)	$	720

Income from continuing operations per share:
Basic	$	0.09		$	(0.02	)	$	0.07
Diluted	$	0.09		$	(0.02	)	$	0.07
Net income per share:
Basic	$	0.08		$	(0.01	)	$	0.07
Diluted	$	0.08		$	(0.01	)	$	0.07
Weighted average number of outstanding shares of common stock:
Basic	10,577						10,577
Diluted	10,595						10,595
Cash dividend per common share	$	0.455					$	0.455

	Three Months Ended March 31, 2003
	As Previously Reported			Adjustments			As Restated
	(in thousands, except per share data)

Revenues	$	50,651		$	580	(38)	$	51,231

Operating expenses:
Purchased product costs	46,003			—			46,003
Facility expenses	4,362			270		(39)	4,632
Selling, general and administrative expenses	2,550			74		(40)	2,624
Depreciation	1,530			72		(41)	1,602
Total operating expenses	54,445			416			54,861

Loss from operations	(3,794		)	164			(3,630		)

Other income (expense):
Interest expense, net	(1,063		)	309		(42)	(754		)
Amortization of deferred financing costs (a component of interest expense)	—			(309		)(42)	(309		)
Other expense	(15		)	—			(15		)
Loss before non-controlling interest in net income of consolidated subsidiary and income taxes	(4,872		)	164			(4,708		)

Benefit for income taxes:
Current	(170		)	(1,974		)	(2,144		)
Deferred	(2,281		)	2,374			93
Benefit for income taxes	(2,451		)	400		(43)	(2,051		)

Non-controlling interest in net income of consolidated subsidiary	(874		)	17		(44)	(857		)

Loss from continuing operations	(3,295		)	(219		)	(3,514		)

Income from discontinued exploration and production operations (net of income tax provision of $1,143)	2,282			(152		)(45)	2,130

Loss before cumulative effect of accounting change	(1,013		)	(371		)	(1,384		)

Cumulative effect of change in accounting for asset retirement obligations, net of tax	(29		)	—			(29		)
Net loss	$	(1,042	)	$	(371	)	$	(1,413	)

Loss from continuing operations per share:
Basic	$	(0.32	)	$	(0.02	)	$	(0.34	)
Diluted	$	(0.32	)	$	(0.02	)	$	(0.34	)
Net loss per share:
Basic	$	(0.10	)	$	(0.04	)	$	(0.14	)
Diluted	$	(0.10	)	$	(0.04	)	$	(0.14	)
Weighted average number of outstanding shares of common stock:
Basic	10,298						10,298
Diluted	10,302						10,302

Cash Flow Amounts:

	Three Months Ended March 31, 2004
	As Previously Reported			Adjustments			As Restated
	(in thousands)
Cash flows from operating activities:
Net income	$	797		$	(77	)	$	720
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	3,640			(112		)	3,528
Gain from sale of property, plant and equipment	(63		)	—			(63		)
Amortization of deferred financing costs	312			(5		)	307
Amortization of intangible assets	—			34			34
Stock option compensation expense	—			358			358
Restricted unit compensation expense	374			—			374
Participation Plan compensation expense	—			402			402
Contribution of treasury shares to 401(k) benefit plan	—			72			72
Equity in investee losses	5			—			5
Non-controlling interest in net income of consolidated subsidiary	1,693			(384		)	1,309
Unrealized losses on derivative instrument	476			—			476
Deferred income taxes	455			(496		)	(41		)
Changes in operating assets and liabilities:
Decrease in receivables	5,999			(903		)	5,096
Decrease in inventories	3,367			733			4,100
Decrease in prepaid replacement gas and other assets	5,925			—			5,925
Increase in other current assets	(544		)	9			(535		)
Decrease in accounts payable and accrued liabilities	(3,574		)	(1,120		)	(4,694		)
Net cash flow provided by operating activities	18,862			(1,489		)(46)	17,373

Cash flows from investing activities:
Payments for marketable securities	(4,277		)	—			(4,277		)
Capital expenditures	(2,863		)	1,234			(1,629		)
Proceeds from sale of assets	94			—			94
Proceeds on financing lease receivable	—			133			133
Other	3			—			3
Net cash used in investing activities	(7,043		)	1,367		(47)	(5,676		)

Cash flows from financing activities:
Repayment of long-term debt	(42,000		)	—			(42,000		)
Proceeds from MarkWest Energy Partners’ secondary public offering	44,102			—			44,102
Distribution to MarkWest Energy Partners’ unitholders	(3,054		)	47			(3,007		)
Exercise of stock options	1,017			—			1,017
Acquisition of general partner’s membership interests and MarkWest Energy Partners’ subordinated units from related party	(147		)	147			—
Repurchase of treasury shares	36			(72		)	(36		)
Payment of dividend	(4,802		)	—			(4,802		)
Net cash used in financing activities	(4,848		)	122		(48)	(4,726		)

Net increase in cash and cash equivalents	6,971			—			6,971
Cash and cash equivalents at beginning of period	42,144			—			42,144
Cash and cash equivalents at end of period	$	49,115		$	—		$	49,115

Supplemental cash flow information:
Construction projects in progress obligation	$	—		$	1,199		$	1,199
Cash paid for interest, net of amount capitalized	$	—		$	1,459		$	1,459

	Three Months Ended March 31, 2003
	As Previously Reported			Adjustments			As Restated
	(in thousands)
Cash flows from operating activities:
Net loss	$	(1,042	)	$	(371	)	$	(1,413	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Cumulative effect of change in accounting	29			—			29
Depreciation and depletion	5,098			—			5,098
Amortization of deferred financing costs	309			—			309
Restricted unit compensation expense	212			—			212
Participation Plan compensation expense	—			53			53
Contribution of treasury shares to 401(k) benefit plan	—			91			91
Non-controlling interest in net income of consolidated subsidiary	874			(17		)	857
Unrealized gains on derivative instruments	(922		)	—			(922		)
Reclassification of Enron hedges to purchased gas costs	(18		)	—			(18		)
Deferred income taxes	(1,199		)	2,379			1,180
Other	28			—			28
Changes in operating assets and liabilities:
Increase in receivables	(3,844		)	—			(3,844		)
Decrease in inventories	1,124			—			1,124
Increase in prepaid replacement natural gas	(873		)	(34		)	(907		)
Increase in other assets	—			34			34
Increase in accounts payable and accrued liabilities	9,773			(2,065		)	7,708
Net cash flow provided by operating activities	9,549			70		(49)	9,619

Cash flows from investing activities:
Pinnacle acquisition, net of cash acquired	(38,238		)	—			(38,238		)
Capital expenditures	(6,735		)	—			(6,735		)
Proceeds from sale of assets	24			—			24
Net cash used in investing activities	(44,949		)	—			(44,949		)

Cash flows from financing activities:
Proceeds from long-term debt	45,700			—			45,700
Repayment of long-term debt	(6,500		)	—			(6,500		)
Payments for debt issuance costs	(810		)	—			(810		)
Distribution to MarkWest Energy Partners’ unitholders	(1,530		)	21			(1,509		)
Repurchase of treasury shares	(76		)	(91		)	(167		)
Net cash provided by financing activities	36,784			(70		)(49)	36,714

Effect of exchange rate on changes in cash	114			—			114

Net increase in cash and cash equivalents	1,498			—			1,498
Cash and cash equivalents at beginning of period	6,410			—			6,410
Cash and cash equivalents at end of period	$	7,908		$	—		$	7,908

Supplemental cash flow information:
Cash paid for interest	$	—		$	382	(50)	$	382

Changes in Stockholders’ Equity Amounts:

	Shares of Common Stock	Shares of Treasury Stock		Common Stock		Additional Paid-In Capital			Accumulated Deficit			Accumulated Other Comprehensive Loss			Treasury Stock			Total Stockholders’ Equity
	(in thousands)
Balance, as previously reported, March 31, 2004	9,756	(71	)	$	98	$	51,730		$	(329	)	$	(768	)	$	(474	)	$	50,257

Stock dividend	976	—		10		(10		)	—			—			—			—

Reclassifications of dividends paid	—	—		—		(1,676		)	1,676			—			—			—

Modification of stock options	—	—		—		358			—			—			—			358

Restatement adjustment to net income for the year ended December 31, 2002	—	—		—		—			(213		)	—			—			(213		)

Restatement adjustments to net income for the year ended December 31, 2003	—	—		—		—			(1,057		)	—			—			(1,057		)

Restatement adjustment to net income for the three months ended March 31, 2004	—	—		—		—			(77		)	—			—			(77		)
Balance, as restated, March 31, 2004	10,732	(71	)	$	108	$	50,402		$	—		$	(768	)	$	(474	)	$	49,268

March 31, 2004 Balance Sheet

(1). Restricted cash was reduced by $2.5 million and restricted marketable securities increased by a corresponding amount as a result of restating restricted marketable securities from restricted cash to restricted marketable securities.

(2). Receivables net, were increased by $0.06 million to correct the amounts recorded for accrued revenue.

(3). The current deferred income tax asset was increased by $0.1 million to reflect the tax effect of the restatement adjustments.

(4). Property, plant and equipment, net, were reduced by $0.7 million. During 2003, as a part of the Pinnacle acquisition, the Partnership acquired the Blackhawk pipeline. The pipeline was subject to a lease with a third party. The Partnership incorrectly recorded the pipeline as property and equipment and depreciated it over its estimated useful life. The lease has now been accounted for as a sales-type financing lease.

(5). Accumulated depreciation was reduced by $0.5 million to reverse the depreciation previously recorded on the Blackhawk pipeline.

(6). Intangible assets, net were decreased by $3.3 million primarily as a result of the following restatement adjustments:

• a decrease of $3.5 million to reclassify deferred financing costs, net to a separate line item on the consolidated balance sheet.

• an increase of $0.2 million to record the remaining balance of the financing lease receivable relating to the lease agreement for the Blackhawk pipeline. Under the terms of the lease agreement the pipeline reverted to the lessee in April 2004.

(7). Deferred financing costs, net were increased by $3.5 million as a result of the reclassification of the deferred financing costs, net from intangible assets, net to a separate line item on the consolidated balance sheet.

(8). Other assets were decreased by $0.04 million as a result of reversing an asset that was previously recorded with the repurchase of the Partnership’s general partner interest and the Partnership’s subordinated units by the Company under the Participation Plan. The Participation Plan has now been accounted for as a compensatory plan.

(9). Accounts payable were increased by $0.4 million to correct amounts recorded for accrued product costs.

(10). Accrued liabilities were decreased by $0.5 million primarily as a result of the following restatement adjustments:

• a decrease of $0.3 million to reverse deferred income as a result of accounting for the Participation Plan as a compensatory arrangement. Previously the sale of subordinated partnership units and interests in the Partnership’s general partner to certain employees and directors of the Company was incorrectly recorded as a sale of an asset. The Company recorded deferred income to the extent the Company loaned the employees and directors a portion of the purchase price.

• a decrease of $0.1 million to correct amounts recorded for accrued property taxes.

• a decrease of $0.2 million to reflect the current tax effect of the restatement adjustments

• an increase of $0.1 million for other miscellaneous adjustments.

(11). The non-current deferred income tax liability was decreased by $1.2 million to reflect the tax effect of the restatement adjustments.

(12). Other long-term liabilities were increased by $2.8 million to reflect compensation expense accrued under the Participation Plan.

(13). Non-controlling interest in consolidated subsidiary was decreased by $0.6 million to reflect the portion of the restatement adjustments attributable to the non-controlling interest in MarkWest Energy Partners, and to eliminate the effect of the subordinated units and general partner interests owned by employees and directors under the Participation Plan, which were previously accounted for as non-controlling interests. The Participation Plan is now accounted for as a compensatory arrangement and as a result the Company records a separate liability for the fair value of the subordinated units and general partner interests held by participants in the Plan.

(14). Additional paid-in capital decreased by $1.3 million as a result of the following restatement adjustments:

• a decrease of $1.7 million as a result of restating dividends paid during the three months ended March 31, 2004 from retained earnings to additional paid in capital for dividends distributed in excess of accumulated earnings.

• an increase of $0.4 million to reflect compensation as a result of the modification of the provisions of stock options for two officers who terminated their employment with the Company but who continued to serve on the Company’s Board of Directors.

(15). Accumulated earnings increased $0.3 million as a result of the following restatement adjustments:

• an increase of $1.7 million as a result of restating dividends paid from retained earnings to additional paid in capital for dividends distributed in excess of accumulated earnings.

• a decrease of $0.2 million and $1.3 million to reflect the effect of the restatement adjustments on net income for the years ended December 31, 2002 and 2003, respectively.

• a decrease of $0.1 million to reflect the effect of the restatement adjustments on net income for the three months ended March 31, 2004.

December 31, 2003 Balance Sheet

(16). Restricted cash was reduced by $2.5 million and restricted marketable securities increased by a corresponding amount as a result of restating restricted marketable securities from restricted cash to restricted marketable securities.

(17). Receivables, net were reduced by $0.8 million to restate natural gas inventory from receivables to inventory. Previously the inventory was incorrectly identified as a pipeline imbalance and was recorded as a receivable.

(18). Inventories were increased by $0.7 million as a result of the following restatement adjustments:

• an increase of $0.8 million to restate natural gas inventory from receivables to inventory. Previously the inventory was incorrectly identified as a pipeline imbalance and was recorded at market value.

• a decrease of $0.1 million to record natural gas inventory at cost. The inventory was previously incorrectly identified as a pipeline imbalance and was recorded at market value.

(19). The current deferred income tax asset was decreased by $0.1 million to reflect the tax effect of the restatement adjustments.

(20). Deferred financing costs, net increased by $3.7 million and intangibles and other assets decreased by a corresponding amount as a result of reclassifying deferred financing costs, net to a separate line item on the consolidated balance sheet.

(21). Other assets were decreased by $0.04 million to eliminate the excess cost recorded on the repurchase of an interest in the Partnership’s general partner and subordinated Partnership units previously sold to an officer under the Participation Plan. The Participation Plan has now been accounted for as a compensatory arrangement and payments to repurchase the general partnership interests and subordinated units are applied against the liability recorded for the Participation Plan.

(22). Accrued liabilities were decreased by $0.2 million primarily as a result of the following restatement adjustments:

• a decrease of $0.22 million to eliminate deferred income as a result of accounting for the Participation Plan as a compensatory arrangement. Previously the sale of subordinated partnership units and interests in the Partnership’s general partner to certain employees and directors of the Company was incorrectly recorded as a sale of an asset. The Company recorded deferred income to the extent the Company had loaned the employees and directors a portion of the purchase price.

• a decrease of $0.02 million to reflect the current tax effect of the restatement adjustments.

(23). The non-current deferred income tax liability was decreased by $0.8 million to reflect the tax effect of the restatement adjustments.

(24). Other long-term liabilities were increased by $2.4 million to reflect compensation expense accrued under the Participation Plan.

(25). Non-controlling interest in consolidated subsidiary was decreased by $0.4 million to reflect the impact of the portion of the restatement adjustments attributable to the non-controlling interest in MarkWest Energy Partners and to eliminate the effect of the subordinated units and general partner interests owned by employees and directors under the Participation Plan, which were previously accounted for as

non-controlling interests. The Participation Plan is now accounted for as a compensatory arrangement and as a result the Company records a separate liability for the fair value of the subordinated units and general partner interests held by participants in the Plan.

Three Months Ended March 31, 2004 Income Statement

(26). Revenues for the first quarter of 2004 increased by $0.3 million primarily as a result of the following restatement adjustments:

• an increase of $0.3 million to reclassify gas revenues from discontinued operations to continuing operations. The Company retained its interests in three wells in Michigan, which it originally intended to dispose of in connection with the discontinuance of its exploration and production business.

• an increase of $0.08 million to record natural gas inventory at cost. Previously the inventory was incorrectly identified as a pipeline imbalance and was recorded at market value.

• an increase of $0.06 million to correct the amounts recorded for accrued revenue.

• a decrease of $0.03 million to restate the settlement of a commodity hedge from interest expense to revenue.

• a decrease of $0.1 million to reduce revenue for the proceeds on the Blackhawk financing lease receivable.

(27). Purchased product costs for the first quarter of 2004 increased by $0.4 million to correct amounts recorded for accrued product costs.

(28). Facility expenses increased by $0.11 million for the first quarter of 2004 primarily as a result of the following restatement adjustments:

• an increase of $0.14 million to reclassify lease operating expenses from discontinued operations to continuing operations.

• a decrease of $0.08 million to correct amounts recorded for accrued property taxes.

• an increase of $0.03 million to record storage fees related to inventory the Partnership held for sale.

• an increase of $0.02 million to record repair expense improperly capitalized as property, plant and equipment.

(29). Selling, general and administrative expenses increased by $1.1 million for the first quarter of 2004 primarily as a result of the following restatement adjustments:

• an increase of $0.5 million to reflect the compensation expense under the Participation Plan.

• an increase of $0.4 to record compensation for the modification of stock options for two officers who terminated their employment with the Company but who continued to serve on the Company’s Board of Directors.

• an increase of $0.2 million to reclassify expenses related to the retained exploration and production operations from discontinued operations to continuing operations.

(30). Depreciation expense decreased by $0.1 million for the reversal of depreciation expense previously recorded on the Blackhawk pipeline.

(31). Amortization of intangible assets expense increased by $0.03 million to record amortization of a customer contract that was acquired with the Blackhawk pipeline.

(32). Interest expense decreased by $0.4 million for the first quarter of 2004 primarily as a result of the following restatement adjustments:

• a decrease of $0.3 million to reclassify amortization of deferred financing costs to a separate line item on the consolidated income statement.

• a decrease of $0.03 million to capitalize interest expense on major construction projects in progress in 2004 and other miscellaneous adjustments.

• a decrease of $0.03 to restate the settlement of a commodity hedge from interest expense to revenue.

(33). Amortization of deferred financing costs increased $0.3 million as a result of the reclassification of the amortization of deferred financing costs from interest expense to a separate line item on the consolidated income statement.

(34). Other income decreased by $0.04 million to reflect an additional adjustment relating to the financing lease receivable for the Blackhawk pipeline.

(35). The provision for income taxes was decreased by $0.7 million primarily as a result of the following restatement adjustments:

• a decrease of $0.1 million to reclassify current taxes relating to retained oil and gas operations from discontinued operations to continuing operations.

• a decrease of $0.6 million to reflect the tax effect of the restatement adjustments.

(36). Non-controlling interest in consolidated subsidiary was increased by $0.4 million to reflect the portion of the restatement adjustments attributable to non-controlling interest in MarkWest Energy Partners, and to eliminate the effect of the subordinated units and general partner interests held by employees and directors under the Participation Plan, which were previously accounted for as non-controlling interests. The Participation Plan is now accounted for as a compensatory arrangement and as a result the Company records a separate liability for the fair value of the subordinated units and general partner interests held by participants in the Plan.

(37). Loss from discontinued exploration and production operations was decreased by $0.2 million to reclassify the loss from the retained exploration and production operations from discontinued operations to continuing operations.

Three Months Ended March 31, 2003 Income Statement

(38). Revenues for the first quarter of 2003 increased by $0.6 million to reclassify gas revenues from discontinued operations to continuing operations. The Company retained its interests in three wells in Michigan, which it originally intended to dispose of in connection with the discontinuance of its exploration and production business.

(39). Facility expenses increased by $0.3 million to reclassify expenses related to the retained exploration and production operations from discontinued operations to continuing operations.

(40). Selling, general and administrative expense increased by $0.1 million to reflect the compensation expense under the Participation Plan.

(41). Depreciation expense increased by $0.1 million to reclassify expenses related to the retained exploration and production operations from discontinued operations to continuing operations.

(42). Interest expense decreased $0.3 million and amortization of deferred financing costs increased by a corresponding amount as a result of reclassifying the amortization of deferred financing costs from interest expense to a separate line item on the consolidated income statement.

(43). The income tax benefit was decreased by $0.4 million primarily as a result of the following restatement adjustments:

• a decrease of $0.3 million to reflect the tax effect of the restatement adjustments.

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

On April 11, 2005, management, after discussion with the Audit Committee of our Board of Directors, determined that previously issued financial statements for the years ended December 31, 2002 and 2003 and for each of the first three quarters of 2003 and 2004 should be restated to reflect compensation expense for the sale of subordinated Partnership units and interests in the Partnership’s general partner to certain employees and directors of the Company that occurred during 2002, 2003 and 2004. In addition, certain other adjustments have also been recorded to correct other errors in the consolidated financial statements, including adjustments to accruals for revenue and purchased product costs, adjustments for cost improperly capitalized as property, plant and equipment, adjustments to properly record capitalized interest on major construction projects in process, adjustments to record as a financing lease, a lease agreement previously entered into by an acquired business, an adjustment to record natural gas inventory at cost, an adjustment to properly record restricted marketable securities and adjustments to accrued property taxes. Adjustments were also made to record compensation expense as a result of the modification of the provisions of certain stock options for two officers who terminated their employment with the Company but who continued to serve on its Board of Directors. Additionally, the Company made an adjustment to reclassify a portion of dividends paid during the three months ended March 31, 2004 from retained earnings to additional paid in capital for the amount of dividends distributed in excess of accumulated earnings.

Refer to Note 10, Restatement and Reclassifications of Consolidated Financial Statements, to the Consolidated Financial Statements in Part 1, Item 1 of this Form 10-Q/A for further information regarding the restatement of our previously issued financial statements.

Management Overview of the Quarter Ended March 31, 2004

MarkWest Hydrocarbon reported net income of $0.7 million, or $0.07 per diluted share, for the three months ended March 31, 2004, compared to a net loss of $1.4 million, or $0.14 per diluted share, for the first quarter of 2003.

On April 22, 2004, the board of directors of MarkWest Hydrocarbon declared the Company’s first quarterly cash dividend of $0.023 per share of its common stock, which implies an annual dividend of $0.092 per share. The board of directors declared that the dividend is to be paid on May 19, 2004, to the stockholders of record as of the close of business on May 5, 2004. The ex-dividend date is May 3, 2004. The board announced that its objective is to maintain a regular quarterly dividend, but that any future dividends will be dependent upon the financial performance of the Company.

First quarter 2004 results primarily benefited from two events. First, the full-quarter contributions from MarkWest Energy Partners’ 2003 acquisitions increased income from continuing operations by approximately $2.2 million relative to first quarter 2003. MarkWest Energy Partners is our consolidated subsidiary. First quarter 2003 did not include any financial impact from MarkWest Energy Partners’ 2003 acquisitions except for approximately $50,000, which represents four days of results from its March 28, 2003, Pinnacle acquisition. Second, healthier margins from our marketing business, primarily due to a favorable pricing environment and a reduction in hedging losses, accounted for an approximate $7.0 million increase in income from continuing operations. These increases were offset by increases in selling, general and administrative expenses due to the significant growth of MarkWest Energy Partners.

Our Business

We were founded in 1988 as a partnership and later incorporated in Delaware. We completed our initial public offering in 1996.

We are an energy company primarily focused on growing the value of our investment in MarkWest Energy Partners, L.P., a publicly-traded limited partnership engaged in the gathering, processing and transmission of natural gas, the transportation, fractionation and storage of natural gas liquids (“NGLs”) and the gathering and transportation of crude oil. We also market NGLs and natural gas. We discontinued our exploration and production activities during 2003.

Our assets consist almost entirely of our partnership interests in MarkWest Energy Partners. As of March 31, 2004, our partnership interests consisted of the following:

• 2,470,996 subordinated units, representing a 34.6% limited partner interest in the Partnership; and

• A 90.2% ownership interest in MarkWest Energy GP, L.L.C., the general partner of the Partnership, which owns a 2.0% general partner interest and all of the incentive distribution rights in the Partnership.

The Company’s operations are classified into two reportable segments:

(1) Managing MarkWest Energy —The Company operates MarkWest Energy, a publicly traded limited partnership engaged in the gathering, processing and transmission of natural gas, the transportation, fractionation and storage of natural gas liquids, and the gathering and transportation of crude oil.

(2) Marketing—The Company sells its equity and third party NGLs, purchases third party natural gas and sells its equity and third party natural gas. Since February 2004, the Company is also engaged in the wholesale marketing of propane.

During 2003, the Company discontinued its exploration and production business segment.

To better understand our business and the results of operations discussed below, it is important to have an understanding of three factors:

• The nature of our relationship with MarkWest Energy Partners;

• The nature of the contracts from which we derive our revenues and from which MarkWest Energy Partners derives its revenues; and

• The comparability within our results of operations across periods because of MarkWest Energy Partners recent acquisition activity.

Our Relationship with MarkWest Energy Partners

We spun off the majority of our then-existing natural gas gathering and processing and NGL transportation, fractionation and storage assets into MarkWest Energy Partners in May 2002, just before the Partnership completed its initial public offering. At the time of its formation and initial public offering, we entered into four contracts with MarkWest Energy Partners whereby MarkWest Energy Partners provides midstream services in Appalachia in exchange for a fee. Additionally, MarkWest Energy Partners receives 100% of all fee and percent-of-proceeds consideration for the first 10 MMcf/d that it gathers and processes in Michigan. MarkWest Hydrocarbon retains a 70% net profits interest in the gathering and processing income earned on quarterly pipeline throughput in excess of 10 MMcf/d. In accordance with generally accepted accounting principles, MarkWest Energy Partners’ financial results are included in our consolidated financial statements. All intercompany accounts and transactions are eliminated during consolidation.

As a result of our contracts with MarkWest Energy Partners mentioned above, we are the Partnership’s largest customer, accounting for 22% of its revenues and 38% of its gross margin (revenues less purchased product costs) for the three months ended March 31, 2004. We expect we will account for less of MarkWest Energy Partners’ business in the future as it continues to acquire assets and increase its customer and business diversification.

Also at the time of the initial public offering, we entered into an Omnibus Agreement with MarkWest Energy Partners and related parties that governs potential competition and indemnification obligations among the parties.

Through our majority ownership in the Partnership’s general partner, we control and operate MarkWest Energy Partners. Our employees are responsible for conducting the Partnership’s business and operating its assets pursuant to a Services Agreement, which was formalized effective January 1, 2004. We receive $5,000 annually from MarkWest Energy Partners for services provided under the Services Agreement. We also are reimbursed for any reasonable costs incurred in the operation of the Partnership.

Our Contracts

Excluding the revenues and gross margin (defined as revenues less purchased product costs) derived from MarkWest Energy Partners, we generate the majority of our revenues and gross margin from the marketing of NGLs and, to a lesser extent, natural gas. As compensation for providing processing services to our Appalachian producers (we have since outsourced these services to MarkWest Energy Partners as discussed below), we earn a fee and receive title to the NGLs produced. In return, we are required to replace, in dry natural gas, the Btu value of the NGLs extracted. This Btu replacement obligation is referred to in the industry as a “keep-whole” arrangement. In keep-whole arrangements, our principal cost is the replacement of the Btus extracted from the gas stream in the form of NGLs or consumed as fuel during processing with dry gas of an equivalent Btu content. 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.” Generally, the frac spread and, consequently, the operating margins, are favorable 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.

At the closing of MarkWest Energy Partners’ initial public offering on May 24, 2002, we outsourced our midstream services to the Partnership. Pursuant to the terms of the operating agreements, we retained all the benefits and associated risks of our keep-whole contracts with producers. Our NGL and gas marketing operations were retained by us and not contributed to MarkWest Energy Partners.

Our keep-whole contracts expose us to commodity price risk, both on the sales side (of NGLs) and on the purchase side (of natural gas), which may increase the volatility of our marketing results and cash flows. We attempt to mitigate our commodity price risk through our hedging program. Under our hedging program, implemented two years ago based in part on historical pricing data through that point in time, we have incurred significant hedging losses. For the three months ended March 31, 2004 and 2003, we lost $2.2 million and $7.3 million, respectively, as a result of our hedging program. The last transactions associated with this unfavorable hedging program settled in April 2004.

MarkWest Energy Partners’ Contracts

The Partnership generates the majority of its revenues and gross margin (defined as revenues less purchased product costs) from natural gas gathering, processing and transmission, NGL transportation, fractionation and storage, and crude oil gathering and transportation. While all of these services constitute midstream energy operations, the Partnership provides its services pursuant to four different types of contracts.

• Fee-based contracts. Under fee-based contracts, the Partnership receives a fee or fees for one or more of the following services: gathering, processing, and transmission of natural gas, transportation, fractionation and storage of NGLs, and gathering and transportation of crude oil. The revenue MarkWest Energy Partners earns from these contracts is generally directly related to the volume of natural gas, NGLs or crude oil that flows through its systems and facilities and is not directly dependent on commodity prices. In certain cases, the Partnership’s contracts provide for minimum annual payments. To the extent a sustained decline in commodity

prices results in a decline in volumes, however, the Partnership’s revenues from these contracts would be reduced.

• Percent-of-proceeds contracts. Under percent-of-proceeds contracts, MarkWest Energy Partners generally gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGLs at market prices and remits to producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, the Partnership delivers an agreed upon percentage of the residue gas and NGLs to the producer and sells the volumes it keeps to third parties at market prices. Under these types of contracts, MarkWest Energy Partners’ revenues and gross margins increase as natural gas prices and NGL prices increase, and its revenues and gross margins decrease as natural gas prices and NGL prices decrease.

• Percent-of-index contracts. Under percent-of-index contracts, the Partnership generally purchases natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount. MarkWest Energy Partners then gathers and delivers the natural gas to pipelines where it resells the natural gas at the index price, or at a different percentage discount to the index price. With respect to (1) and (3) above, the gross margins the Partnership realizes under the arrangements decrease in periods of low natural gas prices because these gross margins are based on a percentage of the index price. Conversely, MarkWest Energy Partners’ gross margins increase during periods of high natural gas prices.

• Keep-whole contracts. Under keep-whole contracts, the Partnership gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, MarkWest Energy Partners must either purchase natural gas at market prices for return to producers or make a cash payment to the producers equal to the value of this natural gas. Accordingly, under these arrangements, the Partnership’s revenues and gross margins increase as the price of NGLs increase relative to the price of natural gas, and its revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs.

In its current areas of operations, MarkWest Energy Partners has a combination of contract types, including limited keep-whole arrangements. The only Partnership keep-whole contracts are associated with the Arapaho processing plant that were assumed as a part of its December 2003 Oklahoma acquisition. However, since the Btu content of the inlet natural gas meets the downstream pipeline specifications, MarkWest Energy Partners has the option of not extracting NGLs in a low processing margin environment. In addition, approximately 45% of the related gas-gathering contracts include additional fees to cover plant operating costs, fuel costs and shrinkage costs in a low processing margin environment. Because of its ability to operate the plant in several recovery modes, including turning it off, and the additional fees provided for in the gas gathering contracts, the Partnership’s exposure is limited to a portion of the operating costs of the plant.

In many cases, MarkWest Energy Partners provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. The Partnership’s contract mix and, accordingly, its exposure to natural gas and NGL prices, may change as a result of changes in producer preferences, its expansion in regions where some types of contracts are more common and other market factors. Any change in mix may impact MarkWest Energy Partners’ financial results.

Items Impacting Comparability of Financial Results

Recent MarkWest Energy Partners Acquisition Activity

In reading the discussion of our historical results of operations, you should be aware of the impact of MarkWest Energy Partners’ recent significant acquisitions, which impact the comparability of our results of operations for the periods discussed.

Since its initial public offering, the Partnership has completed four acquisitions for an aggregate purchase price of approximately $110.0 million. These four acquisitions include:

• The Pinnacle acquisition, which closed on March 28, 2003, for consideration of $38.5 million;

• The Lubbock pipeline acquisition (also known as the Power-Tex Lateral pipeline), which closed September 2, 2003, for consideration of $12.2 million;

• The western Oklahoma acquisition, which closed December 1, 2003, for consideration of $38.0 million; and

• The Michigan Crude Pipeline acquisition, which closed December 18, 2003, for consideration of $21.3 million.

Except for four days of activity from the Pinnacle acquisition, our consolidated statement of operations for the three months ended March 31, 2003, does not reflect the impact of these acquisitions. However, our consolidated results of operations for the three months ended March 31, 2004, do reflect the impact from these acquisitions.

Cobb Processing Facility Repair

First quarter 2004 results were adversely impacted by unexpected downtime at the Partnership’s Cobb processing plant in Appalachia. The facility was shutdown for approximately 45 days during the first quarter due to equipment failure. The plant has since been repaired and is operating normally. Income from operations was approximately $0.3 million less than it would have been had the Cobb operations not been interrupted during first quarter 2004. Current plans are to replace the existing plant with a new facility during the second half of 2004.

Results of Operations

Operating Data

	Three Months Ended March 31,
	2004	2003	% Change

Marketing
NGL product sales (gallons)	51,525,000	53,986,000	(5	)%

MarkWest Energy Partners
Appalachia:
Natural gas processed (Mcf/d)(1)	207,000	203,000	2	%
NGLs fractionated (Gal/d)	462,000	446,000	4	%
Michigan:
Natural gas volumes transported (Mcf/d)	13,900	15,400	(10	)%
NGL product sales (gallons)	2,700,000	2,900,000	(7	)%
Crude oil transported (Bbl/d)(2)	14,600	NA	NA
Southwest:
Gathering system throughput (Mcf/d)(3)	97,800	NA	NA
Lateral pipeline throughput (Mcf/d)(4)	28,900	NA	NA

NA – Not applicable.

(1) Includes throughput from the Kenova, Cobb, and Boldman processing plants.

(2) The Partnership acquired its Michigan Crude Pipeline in December 2003.

(3) Includes volumes from the Partnership’s Pinnacle gathering systems, which were acquired in late March 2003, and its Oklahoma gathering systems, which were acquired in December 2003.

(4) Includes volumes from the Partnership’s Power-Tex Lateral pipeline, which was acquired in September 2003. The Power-Tex Lateral pipeline (previously referred to as the Lubbock Pipeline) is the only lateral the Partnership owned during the first quarter of 2004 that produces revenue on a per-unit-of-throughput basis. MarkWest Energy Partners receives a flat fee from the other three lateral pipelines it owned during the first quarter of 2004 and, therefore, the throughput data from these lateral pipelines is excluded from this statistic. The Partnership acquired a fifth lateral pipeline, referred to as the Hobbs Lateral, on April 1, 2004. The Hobbs Lateral generates revenue on a per-unit-of-throughput basis similar to the Power-Tex lateral.

Three Months Ended March 31, 2004 Compared to the Three Months Ended March 31, 2003

	Marketing			MarkWest Energy Partners, L.P.		Eliminating Entries			Total
	(in thousands)
Three Months Ended March 31, 2004 (1):
Revenues	$	44,393		$	63,825	$	(14,518	)	$	93,700

Purchased product costs	35,851			47,853		(8,216		)	75,488
Facility expenses	6,098			6,290		(6,302		)	6,086
Depreciation	383			3,145		—			3,528
Amortization of intangible assets	—			34		—			34
Total segment operating expenses	42,332			57,322		(14,518		)	85,136

Segment operating income	$	2,061		$	6,503	$	—		$	8,564

Three Months Ended March 31, 2003(1):
Revenues	$	47,199		$	17,693	$	(13,661	)	$	51,231

Purchased product costs	45,210			8,392		(7,599		)	46,003
Facility expenses	6,357			4,337		(6,062		)	4,632
Depreciation	257			1,345		—			1,602
Total segment operating expenses	51,824			14,074		(13,661		)	52,237

Segment operating income (loss)	$	(4,625	)	$	3,619	$	—		$	(1,006	)

	Three Months Ended March 31,
	2004 (1)			2003 (1)
	(in thousands)
Segment operating income (loss)	$	8,564		$	(1,006	)
Selling, general and administrative expenses	(5,314		)	(2,624		)
Interest expense, net	(995		)	(754		)
Amortization of deferred financing costs	(307		)	(309		)
Other income (expense)	25			(15		)

Income (loss) from continuing operations before non-controlling interest in net income of consolidated subsidiary and income taxes	$	1,973		$	(4,708	)

(1) As restated. See Note 10, Restatement and Reclassifications of Consolidated Financial Statements, to Notes to the Consolidated Financial Statements.

Marketing. Our marketing segment operating income was $2.1 million for the three months ended March 31, 2004, compared to a loss of $4.6 million for the three months ended March 31, 2003, an increase of $6.7 million. The increase is primarily attributable to a $5.2 million reduction in our hedging losses. The remainder of the change is attributable to a more favorable pricing environment coupled with our ability to leverage off of existing storage arrangements thereby allowing us to pre-buy replacement natural gas earlier when prices were lower.

MarkWest Energy Partners. Segment operating income from MarkWest Energy Partners was $6.5 million for the three months ended March 31, 2004, compared to $3.6 million for the three months ended March 31, 2003, an increase of $2.9 million, or 81%. The increase is primarily attributable to the Partnership’s 2003 acquisitions, which increased segment operating income by $2.6 million.

Selling, general and administrative expenses. Selling, general and administrative expenses were $5.3 million for the three months ended March 31, 2004, compared to $2.6 million for the three months ended March 31, 2003, an

increase of $2.7 million, or 92%. The increase is primarily attributable to increased back office costs associated with the growth plans of MarkWest Energy Partners, compensation expense associated with the Participation Plan, compensation expense associated with stock options, bonus and profit sharing (a bonus was not accrued during the quarter ended March 31, 2003) and severance.

Interest expense, net. Interest expense, net was $1.0 million for the three months ended March 31, 2004, compared to $0.8 million for the three months ended March 31, 2003, an increase of $0.2 million, or 25%. The increase was principally attributable to MarkWest Energy Partners’ increased outstanding debt levels, resulting from financing of its 2003 acquisitions.

Income from discontinued operations. Income from discontinued operations was $2.1 million for the three months ended March 31, 2003; there were no discontinued operations for the corresponding quarter ended March 31, 2004. The amounts recorded for discontinued operations were a result of the sale of substantially all of our exploration and production business subsequent to the first quarter of 2003.

Liquidity and Capital Resources

During 2003, we discontinued our exploration and production activities and sold all of our related Canadian oil and gas properties and substantially all of our U.S. oil and gas properties. The sales netted us $106.7 million in cash. The proceeds were primarily used to pay off and terminate our existing credit facility in its entirety in December 2003. We also had $33.4 million in unrestricted cash on hand at December 31, 2003, exclusive of MarkWest Energy Partners’ cash on hand. As a result, exclusive of MarkWest Energy Partners’ debt, we had no debt as of March 31, 2004 and December 31, 2003. In February 2004, we disbursed approximately $4.8 million to pay a special one-time dividend of $0.50 per share to our common shareholders.

Going forward, we expect MarkWest Hydrocarbon’s primary sources of liquidity to be quarterly distributions received from MarkWest Energy Partners and cash flows generated principally from the marketing of natural gas and NGLs.

We own 90% of the general partner of MarkWest Energy Partners. The general partner of MarkWest Energy Partners owns a 2% general partner interest and all of the incentive distribution rights in MarkWest Energy Partners. The incentive distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership upon attainment of target distribution levels. Specifically, they entitle us to receive 13.0% of all cash distributed in a quarter after each unit has received $0.55 for that quarter, 23% of all cash distributed after each unit has received $0.625 for that quarter and 48% of all cash distributed after each unit has received $0.75 for that quarter. For the three months ended March 31, 2004, we received $2.0 million in distributions for our subordinated units, and the general partner received $0.3 million, including $0.2 million representing payments on incentive distribution rights. If the Partnership continues to grow and increase its quarterly distributions per limited partner unit, we expect our distributions to increase accordingly.

Cash flows generated from our marketing operations are subject to volatility primarily in NGLs and natural gas prices. Our cash flows are 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 are 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 frac spread and, consequently, the operating margins, are favorable. 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. We, however, cannot predict with any certainty what the pricing environment will be in the future.

We believe that cash on hand, cash received from quarterly distributions (including the incentive distribution rights) from MarkWest Energy Partners, and cash generated from our marketing operations will be sufficient to meet our working capital requirements and fund our required capital expenditures for the foreseeable

future. Most of our future capital expenditures are discretionary and minimal in nature. During 2004, MarkWest Hydrocarbon has budgeted $1.7 million for our contribution to the Cobb plant replacement and an additional $0.3 million for other miscellaneous projects. Cash generated from our marketing operations will depend on our operating performance, which will be affected by prevailing commodity prices and other factors, some of which are beyond our control.

In an effort to increase our liquidity, we may seek to establish a bank credit facility and renegotiate certain keep-whole contracts in order to reduce our commodity price risk.

MarkWest Energy Partners

The Partnership expects to finance future acquisitions through a combination of debt and issuance of additional units, as is common practice with master limited partnerships.

The Partnership paid down its debt by approximately $42.0 million in January 2004 with the proceeds from its secondary offering. As of March 31, 2004, the Partnership had borrowed $84.2 million of the $140.0 million available under its credit facility.

MarkWest Energy Partners’ Credit Facility

The Partnership’s $140.0 million credit facility is available to fund capital expenditures and acquisitions, working capital requirements (including letters of credit) and distributions to unitholders. Advances to fund distributions to unitholders may not exceed $0.50 per outstanding unit in any 12-consecutive-month period. To date there have been no advances to fund distributions to unitholders. At March 31, 2004, $84.2 million was outstanding, and $55.8 million was available, under the Partnership’s credit facility. The Partnership’s credit facility matures in November 2006. The Partnership’s average interest rate was approximately 4.6% at March 31, 2004.

Cash Flows

	Three Months Ended March 31,
	2004 (1)			2003(1)
	(in thousands)

Net cash provided by operating activities	$	17,373		$	9,619
Net cash used in investing activities	$	(5,676	)	$	(44,949	)
Net cash provided by (used in) financing activities	$	(4,726	)	$	36,714

(1) As restated. See Note 10, Restatement and Reclassifications of Consolidated Financial Statements, to the Notes to the Consolidated Financial Statements.

Net cash provided by operating activities was higher during the three months ended March 31, 2004, than during the three months ended March 31, 2003, primarily due to increased activities as a result of the Partnership’s Pinnacle, Power-Tex lateral pipeline, western Oklahoma, and Michigan Crude Pipeline acquisitions. Net cash used in investing activities during the three months ended March 31, 2004, was due to capital expenditures for existing facilities; net cash used in investing activities during the three months ended March 31, 2003, was primarily due to the Pinnacle acquisition. Net cash used in financing activities during the three months ended March 31, 2004, included net proceeds from a secondary public offering of $44.1 million; of the net proceeds from the secondary offering, $42.0 million were used for the repayment of long-term debt. In addition, the Partnership distributed $3.0 million to unitholders other than MarkWest Hydrocarbon and the general partner, and the Company paid a special dividend of $4.8 million. Other financing activities included $1.0 million of proceeds from the exercise of stock options. Net cash provided by financing activities during the three months ended March 31, 2003, included $45.7 million of net proceeds from long-term debt, the majority of which was used to fund the Pinnacle acquisition, and repayments of long-term debt of $6.5 million. In addition, the Partnership distributed $1.5 million to unitholders other than MarkWest Hydrocarbon and the general partner.

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.

These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. Forward-looking statements include statements relating to, among other things:

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

• Our ability to grow MarkWest Energy Partners, L.P. and successfully integrate its acquisitions.

• Our ability to amend certain producer contracts.

• Our expectations regarding natural gas, NGL product and prices.

• Our efforts to increase fee-based contract volumes.

• Our ability to manage our commodity price risk.

• 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 ability to raise sufficient capital to execute our business plan through borrowing or issuing equity.

Important factors that could cause our actual results of operations or our actual financial condition to differ include, but are not necessarily limited to:

• Changes in general economic conditions in regions in which our products are located.

• The availability and prices of NGL and competing commodities.

• The availability and prices of raw natural gas supply.

• Our ability to negotiate favorable marketing agreements.

• The risks that third party 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.

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.

Item 4. Controls and Procedures

Overview

This Form 10-Q/A reflects adjustments to the consolidated financial report for the first quarter of each of the years 2003 and 2004. Please refer to Note 10, Restatement and Reclassifications of Consolidated Financial Statements, to the consolidated financial statements for further information.

Restatements

The Company has determined that previously issued financial statements for the years 2002 and 2003 and the first three quarters of 2003 and 2004 should be restated to reflect compensation expense for the sale of subordinated Partnership units and interests in the Partnership’s general partner to certain employees and directors of MarkWest Hydrocarbon from 2002 through 2004 and for an error in accounting for natural gas inventory in the fourth quarter of 2003. In addition, certain other adjustments have also been recorded to correct other errors in the financial statements for the first three quarters of 2004, including adjustments to accruals for revenue and purchased product costs, adjustments for cost improperly capitalized as property and equipment, adjustments to properly record capitalized interest on major construction projects in process, adjustments to record as a financing lease, a lease agreement previously entered into by an acquired business and adjustments to accrued property taxes. Adjustments were also made to record compensation expense as a result of the modification of the provisions of certain stock options for two officers who terminated their employment with the Company but who continued to serve on its Board of Directors. Additionally, the Company made an adjustment to reclassify a portion of dividends paid during the three months ended March 31, 2004 from retained earnings to additional paid in capital for the amount of dividends distributed in excess of accumulated earnings.

In addition, on October 28, 2004, the Company’s Board of Directors declared a stock dividend of one share of MarkWest Hydrocarbon’s common stock for each ten shares owned by stockholders. The stock dividend was paid on November 19, 2004 to the stockholders of record as of the close of business on November 9, 2004. Common stock information in this form 10-Q/A has been adjusted to give retroactive effect to the stock dividend paid. Other less significant adjustments and reclassifications were identified and recorded in conjunction with the restatement process. The Company is filing contemporaneously with this Form 10-Q/A for the quarterly period ended March 31, 2004, its Annual Report on Form 10-K for the year ended December 31, 2004, which includes restated financial statements for the years ended December 31, 2002 and 2003. The Company is also filing contemporaneously with this Form 10-Q/A, its quarterly reports on Form 10-Q/A for the quarterly periods ending June 30, 2004 and September 30, 2004.

Disclosure Controls and Procedures

In connection with the preparation of our quarterly report on Form 10-Q, as amended by this Form 10-Q/A, our senior management, with participation of our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of March 31, 2004. Based upon that evaluation, our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded that our disclosure controls and procedures were ineffective, as of March 31, 2004, to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Security Exchange Act of 1934 (the “Act”), is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms and to ensure that information required to be disclosed by us in the reports that we file under the Act is accumulated and communicated to management, including our certifying officers, as appropriate, to allow timely decisions regarding required disclosures. Through the date of the filing of this Form 10-Q/A, we have adopted certain measures to address the deficiencies in our internal controls that existed on March 31, 2004 and have applied compensating procedures and processes as necessary to ensure the reliability of our financial reporting. We believe that this quarterly report on Form 10-Q as amended by this Form 10-Q/A properly reports all information required to be included in such report.

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

PART I—FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements
Consolidated Balance Sheets at March 31, 2004 and December 31, 2003 (unaudited)
Consolidated Statements of Operations for the Three Months Ended March 31, 2004 and 2003 (unaudited)
Consolidated Statements of Other Comprehensive Income for the Three Months Ended March 31, 2004 and 2003 (unaudited)
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2004 and 2003 (unaudited)
Consolidated Statement of Changes in Stockholders’ Equity for the Three Months Ended March 31, 2004 (unaudited)
Notes to the Consolidated Financial Statements (unaudited)

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 4. Controls and Procedures

PART II—OTHER INFORMATION

Item 6. Exhibits

SIGNATURE

31.1		Chief Executive Officer Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act.

31.2		Chief Accounting Officer Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act.

31.3		Chief Financial Officer Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act.

32.1		Certification of the 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 the Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

		MarkWest Hydrocarbon, Inc.
		(Registrant)

Date: October 20, 2005		/s/ James G. Ivey
		James G. Ivey
		Chief Financial Officer

Exhibit Number		Exhibit Index

31.1		Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act.

31.2		Certification of the Chief Accounting Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act.

31.3		Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act.

32.1		Certification of the 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 the Chief Accounting Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.3		Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

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

Bbl/d		barrels of oil per day
Btu		British thermal units, an energy measurement
Gal/d		gallons per day
Gross margin		revenues less purchased product costs
Mcf		thousand cubic feet of natural gas
Mcf/d		thousand cubic feet of natural gas 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

Glossary of Terms

PART I—FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

Pinnacle Acquisition

Western Oklahoma Acquisition

Michigan Crude Pipeline

5. Adoption of SFAS No. 143

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

Management Overview of the Quarter Ended March 31, 2004

Our Business

MarkWest Energy Partners’ Contracts

Items Impacting Comparability of Financial Results

Results of Operations

Cash Flows

Item 4. Controls and Procedures