10-Q/A 1 a05-17570_210qa.htm 10-Q/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

(Amendment No. 1)

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

For the quarterly period ended June 30, 2004

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

For the transition period from to

Commission File Number 001-14841

MARKWEST HYDROCARBON, INC.

(Exact name of registrant as specified in its charter)

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

155 Inverness Drive West, Suite 200, Englewood, CO 80112-5000

(Address of principal executive offices)

Registrant’s telephone number, including area code: 303-290-8700

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes o No ý

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

Yes o No ý

The registrant had 10,734,541 shares of common stock, $.01 per share par value, outstanding as of July 31, 2004.


PART I-FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements
	Consolidated Balance Sheets at June 30, 2004 and December 31, 2003 (unaudited)
	Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2004 and 2003 (unaudited)
	Consolidated Statements of Other Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2004 and 2003 (unaudited)
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2004 and 2003 (unaudited)
	Consolidated Statement of Changes in Stockholders’ Equity for the Six Months Ended June 30, 2004 (unaudited) March 31, 2004
	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

Glossary of Terms

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

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 second 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 August 12, 2004 for the second quarter ended June 30, 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 June 30, 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 11, 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, adjustments for dividends received on marketable securities improperly recorded as a reduction in the carrying value of 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. Compensation expense was also recorded as a result of a policy change that required the Company to account for all outstanding stock options as variable awards. In April 2004, the Company changed its policy to allow participants to exercise their stock options using the cashless exercise method. Under APB 25, Accounting for Stock Issued to Employees, a fixed stock option plan that permits the use of a cashless exercise becomes a variable plan if a pattern of exercising stock options using the cashless method is demonstrated. Additionally, the Company made adjustments to reclassify a portion of dividends paid during the six months ended June 30, 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 11.

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 restated to give retroactive effect to stock dividend paid. 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 March 31, 2004 and September 30, 2004.

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)

	June 30, 2004			December 31, 2003
	(as restated, see note 11)

ASSETS

Current assets:
Cash and cash equivalents	$	36,277		$	42,144
Marketable securities	11,375			—
Restricted marketable securities	2,500			2,500
Receivables, net (including related party receivables of $44 and $40, respectively, and net of allowance for doubtful accounts of $111 and $120, respectively)	29,170			29,910
Inventories	9,112			5,548
Prepaid replacement natural gas	264			5,940
Deferred income taxes	109			534
Other current assets	415			503
Total current assets	89,222			87,079

Property, plant and equipment	240,170			232,257
Less: accumulated depreciation, depletion and amortization	(50,625		)	(44,134		)
Total property, plant and equipment, net	189,545			188,123

Other assets:
Intangibles and other assets, net	136			84
Deferred financing costs, net	3,178			3,747
Deferred offering costs, net	—			995
Investment in and advances to equity investee	232			250
Notes receivable from officers	207			217
Total assets	$	282,520		$	280,495

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable (including related party payables of $40 and $51, respectively)	$	32,957		$	24,052
Accrued liabilities	16,578			16,511
Fair value of derivative instruments	748			1,769
Current portion of long-term debt	86,200			—
Total current liabilities	136,483			42,332

Deferred income taxes	6,050			5,594
Long-term debt	—			126,200
Fair value of derivative instruments	397			125
Other long-term liabilities	3,381			2,901
Non-controlling interest in consolidated subsidiary	92,967			52,429
Commitments and contingencies (Note 9)

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, 10,795,395 and 10,601,775 shares issued, respectively	108			106
Additional paid-in capital	51,356			50,705
Retained earnings (accumulated deficit)	(6,370		)	2,406
Accumulated other comprehensive loss, net of tax	(1,395		)	(1,793		)
Treasury stock, 68,780 and 75,930 shares, respectively	(457		)	(510		)
Total stockholders’ equity	43,242			50,914
Total liabilities and stockholders’ equity	$	282,520		$	280,495

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
	(as restated, see note 11)

Revenues	$	89,024		$	48,241		$	182,724		$	99,472

Operating expenses:
Purchased product costs	77,262			44,357			152,750			90,360
Facility expenses	5,975			4,673			12,061			9,305
Selling, general and administrative expenses	5,070			3,766			10,385			6,390
Depreciation	3,657			2,098			7,185			3,700
Amortization of intangible assets	34			—			68			—
Total operating expenses	91,998			54,894			182,449			109,755

Income (loss) from operations	(2,974		)	(6,653		)	275			(10,283		)

Other income (expense):
Interest expense, net	(702		)	(1,494		)	(1,697		)	(2,248		)
Amortization of deferred financing costs (a component of interest expense)	(307		)	(504		)	(614		)	(813		)
Dividend income	83			—			83			—
Other expense	(31		)	—			(5		)	(16		)
Loss from continuing operations before non-controlling interest in net income of consolidated subsidiary and income taxes	(3,931		)	(8,651		)	(1,958		)	(13,360		)

Provision (benefit) for income taxes:
Current	126			(3,646		)	112			(5,791		)
Deferred	365			160			325			252
Provision (benefit) for income taxes	491			(3,486		)	437			(5,539		)

Non-controlling interest in net income of consolidated subsidiary	(1,946		)	(812		)	(3,255		)	(1,669		)

Loss from continuing operations	(6,368		)	(5,977		)	(5,650		)	(9,490		)

Discontinued operations:
Income from discontinued exploration and production operations (net of income taxes in 2003 of $(188) and $955, respectively)	—			1,739			—			3,868
Gain from disposal of discontinued exploration and production operations (less applicable income taxes of $5,423)	—			14,269			—			14,269
Income from discontinued operations	—			16,008			—			18,137
Income (loss) before cumulative effect of accounting change	(6,368		)	10,031			(5,650		)	8,647
Cumulative effect of change in accounting for asset retirement obligations, net of tax	—			—			—			(29		)

Net income (loss)	$	(6,368	)	$	10,031		$	(5,650	)	$	8,618

Loss from continuing operations per share:
Basic	$	(0.60	)	$	(0.58	)	$	(0.53	)	$	(0.92	)
Diluted	$	(0.60	)	$	(0.58	)	$	(0.53	)	$	(0.92	)

Net income (loss) per share:
Basic	$	(0.60	)	$	0.98		$	(0.53	)	$	0.84
Diluted	$	(0.60	)	$	0.97		$	(0.53	)	$	0.84

Weighted average number of outstanding shares of common stock:
Basic	10,681			10,286			10,628			10,292
Diluted	10,681			10,308			10,628			10,314

Cash dividend per common share	$	0.023		$	—		$	0.477		$	—

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

(in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
	(as restated, see note 11)

Net income (loss)	$	(6,368	)	$	10,031		$	(5,650	)	$	8,618

Other comprehensive income (loss), net of tax:
Foreign currency translation	—			1,797			—			4,061
Unrealized gains (losses) on commodity derivatives accounted for as hedges	(347		)	(131		)	768			(524		)
Unrealized loss on marketable securities	(280		)	—			(370		)	—
Total other comprehensive income (loss)	(627		)	1,666			398			3,537

Other comprehensive income (loss)	$	(6,995	)	$	11,697		$	(5,252	)	$	12,155

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)

	Six Months Ended June 30,
	2004			2003
	(as restated, see note 11)
Cash flows from operating activities:
Net income (loss)	$	(5,650	)	$	8,618
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Cumulative effect of change in accounting	—			29
Depreciation and depletion	7,185			11,138
Amortization of deferred financing costs	614			813
Amortization of intangible assets	68			—
Stock option compensation expense	1,026			—
Restricted unit compensation expense	344			400
Participation Plan compensation expense	489			434
Contribution of treasury shares to 401(k) benefit plan	89			149
Equity in investee losses	18			—
Gain from sale of property, plant and equipment	(42		)	—
Non-controlling interest in net income of consolidated subsidiary	3,255			1,669
Unrealized losses (gains) on derivative instrument	732			(1,475		)
Reclassification of Enron hedges to purchased gas costs	—			(154		)
Deferred income taxes	325			(6,944		)
Gain on sale of San Juan Basin properties	—			(19,692		)
Gain on sale of assets to related parties	—			—
Other	—			238
Changes in operating assets and liabilities:
Decrease in receivables	748			10,763
Increase in inventories	(3,564		)	(897		)
Decrease in prepaid replacement natural gas	5,676			388
Decrease in other current assets	97			—
Increase in accounts payable and accrued liabilities	9,928			6,438
Net cash flow provided by operating activities	21,338			11,915
Cash flows from investing activities:
Purchase of marketable securities	(11,745		)	—
Pinnacle acquisition, net of cash acquired	—			(38,238		)
Hobbs Lateral acquisition	(2,275		)	—
Proceeds from sale of San Juan Basin properties, net of disposal costs	—			49,470
Capital expenditures	(7,813		)	(14,023		)
Proceeds from sale of assets	195			105
Proceeds on financing lease receivable	133			—
Other	8			—
Net cash used in investing activities	(21,497		)	(2,686		)
Cash flows from financing activities:
Proceeds from long-term debt	3,000			68,235
Repayment of long-term debt	(43,000		)	(56,424		)
Payments for debt issuance costs	—			(809		)
Proceeds from MarkWest Energy Partners’ secondary public offering	44,103			—
Proceeds from private placement of MarkWest Energy Partners’ common units, net	—			7,807
Distribution to MarkWest Energy Partners’ unitholders	(6,110		)	(3,199		)
Exercise of stock options	1,380			167
Repurchase of treasury shares	(36		)	(219		)
Payment of dividends	(5,045		)	—
Net cash provided by (used in) financing activities	(5,708		)	15,558

Effect of exchange rate changes on cash	—			105

Net increase (decrease) in cash and cash equivalents	(5,867		)	24,892
Cash and cash equivalents at beginning of period	42,144			6,410
Cash and cash equivalents at end of period	$	36,277		$	31,302

Supplemental cash flow information:
Construction projects in progress obligation	$	179		—
Cash paid for interest, net of amount capitalized	$	2,077		$	941

The accompanying notes are an integral part of these consolidated 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			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total Stockholders’ Equity

Balance, December 31, 2003, as restated, see note 11	10,602	(76	)	$	106	$	50,705		$	2,406		$	(1,793	)	$	(510	)	$	50,914

Stock option exercises	193	—		2		1,544			—			—			—			1,546

Modification of options, as restated, see note 11	—	—		—		1,026			—			—			—			1,026

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

Treasury stock reissued	—	10		—		—			—			—			89			89

Dividends, as restated, see note 11	—	—		—		(1,919		)	(3,126		)	—			—			(5,045		)

Net loss, as restated, see note 11	—	—		—		—			(5,650		)	—			—			(5,650		)

Other comprehensive income	—	—		—		—			—			398			—			398

Balance, June 30, 2004, as restated, see note 11	10,795	(69	)	$	108	$	51,356		$	(6,370	)	$	(1,395	)	$	(457	)	$	43,242

The accompanying notes are an integral part of these consolidated 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 market 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 June 30, 2004, the Company’s partnership interests consisted of 2,469,496 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. As of July 30, 2004, after the common unit offering (see Note 3), the Company owned a 29% limited partner interest in the Partnership. The Company’s ownership interest in the general partner remained unchanged as of July 30, 2004.

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 said adjustments are of a recurring nature. Results for the three and six months ended June 30, 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 (loss), 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.

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

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

June 30, 2004 (as restated, see note 11)	Cost Basis		Unrealized gains		Unrealized losses			Recorded Basis
Equity securities:
Master limited partnership units	$	4,976	$	27	$	(241	)	$	4,762
Equity securities, classified as current	4,976		27		(241		)	4,762
Fixed maturities:
Mortgage backed securities (due after one year through five years)	6,752		—		(139		)	6,613
Mortgage back securities, classified as non-current	6,752		—		(139		)	6,613
Total marketable securities	$	11,728	$	27	$	(380	)	$	11,375

Restricted fixed maturities:
Mortgage backed securities (due December 2007)	$	2,500	$	—	$	—		$	2,500
Total restricted marketable securities	$	2,500	$	—	$	—		$	2,500

December 31, 2003 (as restated, see note 11)	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 June 30, 2004, unrealized losses of $0.3 million relate primarily to investments in domestic equity securities in energy partnerships. Unrealized losses of $0.1 million relate primarily to mortgage backed securities and are primarily attributable to changes in interest rates.

3. Subsequent Event - MarkWest Energy Partners’ Acquisition

On July 30, 2004, the Partnership completed the East Texas System acquisition consisting of American Central Eastern Texas’ Carthage gathering system and gas processing assets located in east Texas for approximately $240.7 million. The Company’s consolidated financial statements will include American Central Eastern Texas’ results of operations from July 30, 2004. The assets acquired consist of processing plants, gathering systems, a processing facility currently under construction and a NGL pipeline to be constructed in 2005.

In conjunction with the closing of the acquisition, the Partnership completed a private offering of 1.3 million common units, at $34.50 per unit, representing approximately $45.0 million in proceeds after transaction costs of approximately $0.9 million and including a contribution from the general partner of $0.9 million to maintain its ownership interest. In addition, the Partnership amended and restated its credit facility, increasing its maximum lending limit from $140.0 million to $315.0 million. The credit facility included a $265.0 million revolving facility and a $50.0 million term loan facility. The Partnership used the proceeds from the private offering and borrowings of $195.7 million under the credit facility to finance the East Texas System acquisition.

4. MarkWest Energy Partners’ Acquisitions

Hobbs Lateral Acquisition

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

On April 1, 2004, the Partnership acquired the Hobbs Lateral pipeline for approximately $2.3 million. The Hobbs Lateral 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 is a New Mexico intrastate pipeline regulated by the Federal Energy Regulatory Commission. The pro forma results of operations of the Hobbs Lateral acquisition have not been presented, as they are not significant.

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, were 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 Partnership’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 accompanying notes are an integral part of these financial statements.

The purchase price was comprised of $38.0 million paid in cash, 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 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 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 June 30, 2003		Six Months Ended June 30, 2003
	(in thousands, except per share data)
	(as restated, see note 11)		(as restated, see note 11)
Revenue	$	59,320	$	140,531
Net income	$	9,541	$	8,455
Basic net income per share	$	0.93	$	0.82
Diluted net income per share	$	0.93	$	0.82

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

5. Property, Plant and Equipment

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

	June 30, 2004			December 31, 2003
	(in thousands)

	(as restated, see note 11)
Property, plant and equipment:
Gas gathering facilities	$	81,895		$	73,424
Gas processing plants	56,322			55,888
Fractionation and storage facilities	22,524			22,160
Natural gas pipelines	38,848			38,790
Crude oil pipeline	18,437			18,352
NGL transportation facilities	4,415			4,415
Marketing assets	1,606			1,987
Oil and gas properties and equipment, full cost method	2,499			2,380
Land, buildings and other equipment	10,716			12,499
Construction in-progress	2,908			2,362
	240,170			232,257
Less: Accumulated depreciation, depletion, amortization and impairment	(50,625		)	(44,134		)
Total property, plant and equipment, net	$	189,545		$	188,123

6. 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 the 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 of $2.4 million in accordance with the provisions of SFAS No. 143. There was no impact on its cash flows as a result of adopting SFAS No. 143. For the year ended December 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 $3.3 at June 30, 2004 and 2003, respectively.

7. MarkWest Energy Partners’ Common Unit Offerings

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 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.

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

During July 2004, the Partnership completed an additional offering of its common units. See Note 3.

8. 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 and six months ended June 30, 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.

				MarkWest
				Energy		Eliminating
	Marketing			Partners		Entries			Total
	(in thousands)
Three Months Ended June 30, 2004(1):
Revenues from external customers	$	37,170		$	51,854	$	—		$	89,024
Intersegment revenues	$	114		$	13,805	$	(13,919	)	$	—
Segment operating income (loss)	$	(4,531	)	$	6,627	$	—		$	2,096

Three Months Ended June 30, 2003(1):
Revenues from external customers	$	28,687		$	19,554	$	—		$	48,241
Intersegment revenues	$	178		$	10,082	$	(10,260	)	$	—
Segment operating income (loss)	$	(7,073	)	$	4,186	$	—		$	(2,887	)

				MarkWest
				Energy		Eliminating
	Marketing			Partners		Entries			Total
	(in thousands)
Six Months Ended June 30, 2004(1):
Revenues from external customers	$	81,339		$	101,385	$	—		$	182,724
Intersegment revenues	$	338		$	28,099	$	(28,437	)	$	—
Segment operating income (loss)	$	(2,470	)	$	13,130	$	—		$	10,660

Six Months Ended June 30, 2003(1):
Revenues from external customers	$	75,619		$	23,853	$	—		$	99,472
Intersegment revenues	$	445		$	23,476	$	(23,921	)	$	—
Segment operating income (loss)	$	(11,698	)	$	7,805	$	—		$	(3,893	)

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

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2004 (1)			2003 (1)			2004 (1)			2003 (1)
	(in thousands)
Segment operating income (loss)	$	2,096		$	(2,887	)	$	10,660		$	(3,893	)
Selling, general and administrative expenses	(5,070		)	(3,766		)	(10,385		)	(6,390		)
Interest expense, net	(702		)	(1,494		)	(1,697		)	(2,248		)
Amortization of deferred financing costs	(307		)	(504		)	(614		)	(813		)
Dividend income	83			—			83			—
Other expense	(31		)	—			(5		)	(16		)
Loss from continuing operations before non-controlling interest in net income of consolidated subsidiary and income taxes	$	(3,931	)	$	(8,651	)	$	(1,958	)	$	(13,360	)

(1) As restated, see note 11.

9. 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 the Company’s financial position or results of operations.

10. 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 four stock-based compensation plans, one of which is through our consolidated subsidiary, MarkWest Energy. The Company accounts for these plans using fixed and variable accounting as appropriate.

Stock Option Plans

Stock options are issued under the Company’s 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan. The plans allow for the exercise of stock options using the cashless method, but only at the discretion of the Company. Under a cashless exercise, the Company withholds from shares that otherwise would be issued upon the exercise of the option, the number of shares with a fair market value equal to the option exercise price and remits the remaining shares to the employee. Prior to April 2004, the Company did not allow participants to exercise their stock options using the cashless method. Accordingly, compensation expense was not recognized for stock options granted unless the options were granted at an exercise price less than the quoted market price of the Company’s stock on the grant date. In April 2004, the Company changed its policy to allow participants to exercise their stock options using the cashless method. Under APB 25, Accounting for Stock Issued to Employees, a fixed stock option plan that permits the use of a cashless exercise becomes variable if a pattern of exercising the stock options using the cashless method is demonstrated. As a result, in April 2004, the Company was required to account for stock options issued under the plans as variable awards. Compensation expense for stock options accounted for as variable awards is measured as the difference in the market value of the Company’s common stock and the exercise price of the stock options. The difference is amortized into earnings over the period of service, adjusted quarterly for the change in the fair value of the unvested stock options awarded. Increases or decreases in the market value of the Company’s common stock between April of 2004 and the end of each reporting period result in a change in the measure of compensation for vested awards, which is reflected currently in operations. The Company recorded compensation expense for options granted under the plans accounted for as variable awards of $0.7 million for the three and six months ended June 30, 2004 and no compensation expense for the three and six months ended

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

June 30, 2003. During the six months ended June 30, 2004, recipients exercised their options to purchase an aggregate of 193,000 shares of the Company’s common stock. Recipients exercised options for 46,437 shares using the cashless method resulting in the net issuance of 17,537 shares of common stock. 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. These charges are included in selling, general and administrative expenses.

Participation Plan

The Company has also entered into agreements 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 $0.1 million and $0.4 million for the three months ended June 30, 2004 and 2003, respectively. For the six months ended June 30, 2004 and 2003, the Company recorded compensation expense of $0.5 million and $0.4 million, 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 June 30, 2004 and 2003, 5,500 and 2,000 restricted units, respectively, were granted. During the six months ended June 30, 2004 and 2003, 8,000 and 3,000 restricted units, respectively, were granted. The Partnership recorded compensation income of less than $0.1 million and compensation expense of $0.2 million for the three months ended June 30, 2004 and 2003, respectively. For the six months ended June 30, 2004 and 2003, the Company recorded compensation expense of

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

$0.3 million and $0.4 million, 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 June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
	(in thousands, except per share data)
	(as restated, see note 11)			(as restated, see note 11)			(as restated, see note 11)			(as restated, see note 11)

Net income (loss), as reported	$	(6,368	)	$	10,031		$	(5,650	)	$	8,618
Add: compensation expense included in reported net income	725			569			1,859			834
Deduct: total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effect	(40		)	(679		)	(845		)	(1,017		)
Pro forma net income (loss)	$	(5,683	)	$	9,921		$	(4,636	)	$	8,435

Net income (loss) per share:
Basic:
As reported	$	(0.60	)	$	0.98		$	(0.53	)	$	0.84
Pro forma	$	(0.53	)	$	0.96		$	(0.44	)	$	0.82
Diluted:
As reported	$	(0.60	)	$	0.97		$	(0.53	)	$	0.84
Pro forma	$	(0.53	)	$	0.96		$	(0.44	)	$	0.82

11. 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 June 30, 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 Partnership’s 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, adjustments to record as a financing lease, a lease agreement previously entered into by an acquired business (“Blackhawk pipeline”), an adjustment to record natural gas inventory at cost, an adjustment to reflect separately restricted marketable securities, adjustments for dividends received on marketable securities improperly

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

recorded as a reduction in the carrying value of marketable securities, adjustments to accrued property taxes payable and adjustments to deferred and current taxes payable. Adjustments were also made to record compensation 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. Compensation expense was also recorded as a result of a policy change that required the Company to account for all outstanding stock options as variable awards. In April 2004, the Company changed its policy to allow participants to exercise their stock options using the cashless exercise method. Under APB 25, Accounting for Stock Issued to Employees, a fixed stock option plan that permits the use of a cashless exercise becomes variable if a pattern of exercising stock options using the cashless method is demonstrated. Additionally, the Company made an adjustment to reclassify a portion of dividends paid during the six months ended June 30, 2004 from retained earnings to additional paid in capital for the amount of dividends distributed in excess of accumulated earnings.

The Company has reclassified certain prior year amounts to conform to the current year’s presentation. The Company has reclassified intangible and other assets to a separate line item on the consolidated balance sheet. The Company has also reclassified interest income and amortization of deferred financing costs to separate line items on the consolidated income statement.

All amounts in the accompanying notes have been restated or reclassified for these adjustments. The following tables present the consolidated balance sheets as of June 30, 2004 and December 31, 2003 as previously reported and as restated, and the consolidated statements of income for the three months and six months ended June 30, 2004 and 2003 as previously reported and as restated and the consolidated statement of cash flows for the six months ended June 30, 2004 and 2003 as previously reported and as restated. The tables also reflect the amounts reported for changes in stockholders’ equity for the six months ended June 30, 2004, as previously reported and as restated. The impact of these restatements was to decrease net income per basic and diluted share by $0.30 for the three and six months ended June 30, 2004. In addition, the impact of these restatements was to increase net income per basic share by $0.01 for the three months ended June 30, 2003 and to decrease net income per basic and diluted share by $0.03 for the six months ended June 30, 2004.

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

Balance Sheet Amounts:

	June 30, 2004
	As Previously Reported			Adjustments			As Restated
	(in thousands, except share and per share data)
ASSETS
Current assets:
Cash and cash equivalents	$	33,777		$	2,500	(1)	$	36,277
Restricted cash	2,500			(2,500		)(1)	—
Marketable securities	13,809			(2,434		)(2)	11,375
Restricted marketable securities	—			2,500		(3)	2,500
Receivables, net	28,300			870		(4)	29,170
Inventories	9,112			—			9,112
Prepaid replacement natural gas	264			—			264
Deferred income taxes	178			(69		)(5)	109
Other current assets	415			—			415
Total current assets	88,355			867			89,222

Property, plant and equipment	241,088			(918		)(6)	240,170
Less: accumulated depreciation, depletion and amortization	(51,188		)	563		(7)	(50,625		)
Total property, plant and equipment, net	189,900			(355		)	189,545

Other assets:
Intangibles and other assets, net	—			136		(8)	136
Deferred financing costs, net	3,178			—			3,178
Deferred offering costs and other, net	42			(42		)(9)	—
Investment in and advances to equity investee	232			—			232
Notes receivable from officers	207			—			207
Total assets	$	281,914		$	606		$	282,520

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	31,237		$	1,720	(10)	$	32,957
Accrued liabilities	16,863			(285		)(11)	16,578
Fair value of derivative instruments	748			—			748
Current portion of long-term debt	86,200			—			86,200
Total current liabilities	135,048			1,435			136,483

Deferred income taxes	5,105			945		(12)	6,050
Fair value of derivative instruments	397			—			397
Other long-term liabilities	501			2,880		(13)	3,381
Non-controlling interest in consolidated subsidiary	94,140			(1,173		)(14)	92,967
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, 10,795,395 shares issued	108			—			108
Additional paid-in capital	52,249			(893		)(15)	51,356
Retained earnings (accumulated deficit)	(3,782		)	(2,588		)(16)	(6,370		)
Accumulated other comprehensive loss, net of tax	(1,395		)	—			(1,395		)
Treasury stock, 68,780 shares	(457		)	—			(457		)
Total stockholders’ equity	46,723			(3,481		)	43,242
Total liabilities and stockholders’ equity	$	281,914		$	606		$	282,520

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

	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		)(17)	—
Restricted marketable securities	—			2,500		(17)	2,500
Receivables, net	30,750			(840		)(18)	29,910
Inventories	4,815			733		(19)	5,548
Prepaid replacement natural gas	5,940			—			5,940
Deferred income taxes	603			(69		)(20)	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:
Intangibles and other assets, net	3,831			(3,747		)(21)	84
Deferred financing costs, net	—			3,747		(21)	3,747
Deferred offering costs and other, net	1,037			(42		)(22)	995
Investment in and advances to equity investee	250			—			250
Notes receivable 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		)(23)	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		)(24)	5,594
Long-term debt	126,200			—			126,200
Fair value of derivative instruments	125			—			125
Other long-term liabilities	504			2,397		(25)	2,901
Non-controlling interest in consolidated subsidiary	52,782			(353		)(26)	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, 75,930 shares	(510		)	—			(510		)
Total stockholders’ equity	52,184			(1,270		)	50,914
Total liabilities and stockholders’ equity	$	280,713		$	(218	)	$	280,495

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

Income Statement Amounts:

	Three Months Ended June 30, 2004
	As Previously Reported			Adjustments			As Restated
	(in thousands, except per share data)

Revenues	$	87,796		$	1,228	(27)	$	89,024

Operating expenses:
Purchased product costs	75,451			1,811		(28)	77,262
Facility expenses	5,747			228		(29)	5,975
Selling, general and administrative expenses	4,262			808		(30)	5,070
Depreciation	3,770			(113		)(31)	3,657
Amortization of intangible assets	—			34		(32)	34
Total operating expenses	89,230			2,768			91,998

Loss from operations	(1,434		)	(1,540		)	(2,974		)

Other income (expense):
Interest expense, net	(1,092		)	390		(33)	(702		)
Amortization of deferred financing costs (a component of interest expense)	—			(307		)(34)	(307		)
Dividend income	—			83		(35)	83
Other expense	(31		)	—			(31		)
Loss before non-controlling interest in net income of consolidated subsidiary and income taxes	(2,557		)	(1,374		)	(3,931		)

Provision (benefit) for income taxes:
Current	(69		)	195			126
Deferred	(1,827		)	2,192			365
Provision (benefit) for income taxes	(1,896		)	2,387		(36)	491

Non-controlling interest in net income of consolidated Subsidiary	(2,549		)	603		(37)	(1,946		)

Net loss	$	(3,210	)	$	(3,158	)	$	(6,368	)

Net loss per share:
Basic	$	(0.30	)	$	(0.30	)	$	(0.60	)
Diluted	$	(0.30	)	$	(0.30	)	$	(0.60	)

Weighted average number of outstanding shares of common stock:
Basic	10,681						10,681
Diluted	10,681						10,681

Cash dividend per common share	$	0.023					$	0.023

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

	Three Months Ended June 30, 2003
	As Previously Reported			Adjustments			As Restated
	(in thousands, except per share data)

Revenues	$	47,888		$	353	(38)	$	48,241

Operating expenses:
Purchased product costs	44,357			—			44,357
Facility expenses	4,417			256		(39)	4,673
Selling, general and administrative expenses	3,363			403		(40)	3,766
Depreciation	2,041			57		(41)	2,098
Total operating expenses	54,178			716			54,894

Loss from operations	(6,290		)	(363		)	(6,653		)

Other income (expense):
Interest expense, net	(1,998		)	504		(42)	(1,494		)
Amortization of deferred financing costs (a component of interest expense)	—			(504		)(42)	(504		)
Other income	105			(105		)(43)	—
Loss before non-controlling interest in net income of consolidated subsidiary income taxes	(8,183		)	(468		)	(8,651		)

Provision (benefit) for income taxes:
Current	(5,875		)	2,229			(3,646		)
Deferred	6,931			(6,771		)	160
Provision (benefit) for income taxes	1,056			(4,542		)(44)	(3,486		)

Non-controlling interest in net income of consolidated subsidiary	(860		)	48		(45)	(812		)

Loss from continuing operations	(10,099		)	4,122			(5,977		)

Discontinued operations:
Income from discontinued exploration and production operations (net of income taxes of $(188))	2,377			(638		)	1,739
Gain from disposal of discontinued exploration and production operations (less applicable income taxes of $5,423)	17,701			(3,432		)	14,269
Income from discontinued operations	20,078			(4,070		)(46)	16,008

Net income	$	9,979		$	52		$	10,031

Loss from continuing operations per share:
Basic	$	(0.98	)	$	0.40		$	(0.58	)
Diluted	$	(0.98	)	$	0.40		$	(0.58	)

Net income per share:
Basic	$	0.97		$	0.01		$	0.98
Diluted	$	0.97		$	—		$	0.97

Weighted average number of outstanding shares of common stock:
Basic	10,286						10,286
Diluted	10,308						10,308

Cash dividend per common share	$	—					$	—

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

	Six Months Ended June 30, 2004
	As Previously Reported			Adjustments			As Restated
	(in thousands, except per share data)

Revenues	$	181,484		$	1,240	(47)	$	182,724

Operating expenses:
Purchased product costs	150,587			2,163		(48)	152,750
Facility expenses	11,866			195		(49)	12,061
Selling, general and administrative expenses	8,746			1,639		(50)	10,385
Depreciation	7,410			(225		)(51)	7,185
Amortization of intangible assets	—			68		(52)	68
Total operating expenses	178,609			3,840			182,449

Income from operations	2,875			(2,600		)	275

Other income (expense):
Interest expense, net	(2,450		)	753		(53)	(1,697		)
Amortization of deferred financing costs (a component of interest expense)	—			(614		)(54)	(614		)
Dividend income	—			83		(55)	83
Other income	32			(37		)(56)	(5		)
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	457			(2,415		)	(1,958		)

Provision (benefit) for income taxes:
Current	—			112			112
Deferred	(1,372		)	1,697			325
Provision (benefit) for income taxes	(1,372		)	1,809		(57)	437

Non-controlling interest in net income of consolidated subsidiary	(4,242		)	987		(58)	(3,255		)

Net loss	$	(2,413	)	$	(3,237	)	$	(5,650	)

Net loss per share:
Basic	$	(0.23	)	$	(0.30	)	$	(0.53	)
Diluted	$	(0.23	)	$	(0.30	)	$	(0.53	)

Weighted average number of outstanding shares of common stock:
Basic	10,628						10,628
Diluted	10,628						10,628

Cash dividend per common share	$	0.477					$	0.477

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

	Six Months Ended June 30, 2003
	As Previously Reported			Adjustments			As Restated
	(in thousands, except per share data)

Revenues	$	98,539		$	933	(59)	$	99,472

Operating expenses:
Purchased product costs	90,360			—			90,360
Facility expenses	8,779			526		(60)	9,305
Selling, general and administrative expenses	5,913			477		(61)	6,390
Depreciation	3,571			129		(62)	3,700
Total operating expenses	108,623			1,132			109,755

Loss from operations	(10,084		)	(199		)	(10,283		)

Other income (expense):
Interest expense, net	(3,061		)	813		(63)	(2,248		)
Amortization of deferred financing costs (a component of interest expense)	—			(813		)(63)	(813		)
Other income (expense)	90			(106		)(64)	(16		)
Loss before non-controlling interest in net income of consolidated subsidiary and income taxes	(13,055		)	(305		)	(13,360		)

Provision (benefit) for income taxes:
Current	(6,045		)	254			(5,791		)
Deferred	4,649			(4,397		)	252
Provision (benefit) for income taxes	(1,396		)	(4,143		)(65)	(5,539		)

Non-controlling interest in net income of consolidated subsidiary	(1,734		)	65		(66)	(1,669		)

Loss from continuing operations	(13,393		)	3,903			(9,490		)

Discontinued operations:
Income from discontinued exploration and production operations (net of income taxes of $955)	4,658			(790		)	3,868
Gain from disposal of discontinued exploration and production operations (less applicable income taxes of $5,423)	17,701			(3,432		)	14,269
Income from discontinued operations	22,359			(4,222		)(67)	18,137
Income (loss) before cumulative effect of accounting change	8,966			(319		)	8,647
Cumulative effect of change in accounting for asset retirement obligations, net of tax	(29		)	—			(29		)

Net income	$	8,937		$	(319	)	$	8,618

Loss from continuing operations per share:
Basic	$	(1.30	)	$	0.38		$	(0.92	)
Diluted	$	(1.30	)	$	0.38		$	(0.92	)

Net income (loss) per share:
Basic	$	0.87		$	(0.03	)	$	0.84
Diluted	$	0.87		$	(0.03	)	$	0.84

Weighted average number of outstanding shares of common stock:
Basic	10,292						10,292
Diluted	10,314						10,314

Cash dividend per common share	$	—					$	—

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

Cash Flow Amounts

	Six Months Ended June 30, 2004
	As Previously Reported			Adjustments			As Restated
	(in thousands)
Cash flows from operating activities:
Net loss	$	(2,413	)	$	(3,237	)	$	(5,650	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and depletion	7,410			(225		)	7,185
Gain from sale of property, plant and equipment	(42		)	—			(42		)
Amortization of deferred financing costs	627			(13		)	614
Amortization of intangible assets	—			68			68
Stock option compensation expense	—			1,026			1,026
Restricted unit compensation expense	344			—			344
Participation Plan compensation expense	—			489			489
Contribution of treasury shares to 401(k) benefit plan	—			89			89
Equity in investee losses	18			—			18
Non-controlling interest in net income of consolidated subsidiary	4,242			(987		)	3,255
Unrealized losses on derivative instrument	732			—			732
Deferred income taxes	(1,372		)	1,697			325
Changes in operating assets and liabilities:
Decrease in receivables	2,458			(1,710		)	748
Increase in inventories	(4,297		)	733			(3,564		)
Decrease in prepaid replacement natural gas	5,676			—			5,676
Decrease in other current assets	88			9			97
Increase in accounts payable and accrued liabilities	7,328			2,600			9,928
Net cash flow provided by operating activities	20,799			539		(68)	21,338

Cash flows from investing activities:
Payments for marketable securities	(11,679		)	(66		)	(11,745		)
Hobbs Lateral acquisition	(2,275		)	—			(2,275		)
Capital expenditures	(7,049		)	(764		)	(7,813		)
Proceeds from sale of assets	195			—			195
Proceeds on financing lease receivable	—			133			133
Other	8			—			8
Net cash used in investing activities	(20,800		)	(697		)(69)	(21,497		)

Cash flows from financing activities:
Proceeds from long-term debt	3,000			—			3,000
Repayment of long-term debt	(43,000		)	—			(43,000		)
Proceeds from MarkWest Energy Partners’ secondary public offering	44,103			—			44,103
Distribution to MarkWest Energy Partners’ unitholders	(6,210		)	100			(6,110		)
Acquisition of general partner’s membership interests and MarkWest Energy Partners’ subordinated units from related parties	(147		)	147			—
Exercise of stock options	1,380			—			1,380
Repurchase of treasury shares	53			(89		)	(36		)
Payment of dividends	(5,045		)	—			(5,045		)
Net cash used in financing activities	(5,866		)	158		(70)	(5,708		)

Net decrease in cash and cash equivalents	(5,867		)	—			(5,867		)
Cash and cash equivalents at beginning of period	42,144			—			42,144
Cash and cash equivalents at end of period	$	36,277		$	—		$	36,277

Supplemental cash flow information:
Construction projects in progress obligation	$	—		$	179		$	179
Cash paid for interest, net of amounts capitalized	$	2,077		$	—		$	2,077

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

	Six Months Ended June 30, 2003
	As Previously Reported			Adjustments			As Restated
	(in thousands)
Cash flows from operating activities:
Net income	$	8,937		$	(319	)	$	8,618
Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect of change in accounting	29			—			29
Depreciation and depletion	11,138			—			11,138
Amortization of deferred financing costs	813			—			813
Restricted unit compensation expense	400			—			400
Participation Plan compensation expense	—			434			434
Contribution of treasury shares to 401(k) benefit plan	—			149			149
Non-controlling interest in net income of consolidated subsidiary	1,735			(65		)	1,670
Unrealized gains on derivative instrument	(1,475		)	—			(1,475		)
Reclassification of Enron hedges to purchased gas costs	(154		)	—			(154		)
Deferred income taxes	(2,552		)	(4,393		)	(6,945		)
Gain on sale of San Juan Basin properties	(19,692		)	—			(19,692		)
Other	237			1			238
Changes in operating assets and liabilities:
Decrease in receivables	10,763			—			10,763
Increase in inventories	(897		)	—			(897		)
Decrease in prepaid	388			—			388
Increase in accounts payable and accrued liabilities	1,910			4,528			6,438
Net cash flow provided by operating activities	11,580			335		(71)	11,915
Cash flows from investing activities:
Pinnacle acquisition, net of cash acquired	(38,238		)	—			(38,238		)
Proceeds from sale of San Juan Basin properties, net of disposal costs	49,470			—			49,470
Capital expenditures	(14,023		)	—			(14,023		)
Proceeds from sale of assets	105			—			105
Proceeds from sale of assets to related parties	229			(229		)	—
Net cash used in investing activities	(2,457		)	(229		)(72)	(2,686		)
Cash flows from financing activities:
Proceeds from long-term debt	68,235			—			68,235
Repayment of long-term debt	(56,424		)	—			(56,424		)
Debt issuance costs	(809		)	—			(809		)
Proceeds from private placement of MarkWest Energy Partners’ common units, net	7,807			—			7,807
Distribution to MarkWest Energy Partners’ unitholders	(3,242		)	43			(3,199		)
Exercise of stock options	167			—			167
Repurchase of treasury shares	(70		)	(149		)	(219		)
Net cash provided by financing activities	15,664			(106		)(73)	15,558
Effect of exchange rate on changes in cash	105			—			105
Net increase in cash and cash equivalents	24,892			—			24,892
Cash and cash equivalents at beginning of period	6,410			—			6,410
Cash and cash equivalents at end of period	$	31,302		$	—		$	31,302
Supplemental cash flow information:
Cash paid for interest	$	709		$	232	(74)	$	941

Changes in Stockholders’ Equity Amounts:

	Shares of Common Stock	Shares of Treasury Stock		Common Stock		Additional Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total Stockholders’ Equity
	(in thousands)
Balance, as previously reported, June 30, 2004	9,814	(69	)	$	98	$	52,259		$	(3,782	)	$	(1,395	)	$	(457	)	$	46,723

Stock dividend	981	—		10		(10		)	—			—			—			—

Reclassification of dividends paid	—	—		—		(1,919		)	1,919			—			—			—

Modification of stock options	—	—		—		1,026			—			—			—			1,026

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

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

Restatement adjustments to net income for the six months ended June 30, 2004	—	—		—		—			(3,237		)	—			—			(3,237		)

Balance, as restated, June 30, 2004	10,795	(69	)	$	108	$	51,356		$	(6,370	)	$	(1,395	)	$	(457	)	$	43,242

June 30, 2004 Balance Sheet

1. Restricted cash was reduced by $2.5 million and cash and cash equivalents increased by a corresponding amount as a result of reclassifying non-restricted cash from restricted cash to cash and cash equivalents.

2. Marketable securities was reduced by $2.4 million primarily as a result of the following restatement adjustments:

• a decrease of $2.5 million to reclassify restricted marketable securities from marketable securities to restricted marketable securities.

• an increase of $0.1 million to properly record dividends received as dividend income. Previously, the dividends received were incorrectly recorded as a reduction to carrying value of marketable securities.

3. Restricted marketable securities was increased by $2.5 million as a result of reclassifying restricted marketable securities from marketable securities to restricted marketable securities.

4. Receivables, net, were adjusted by $0.9 million primarily to correct the amounts recorded for accrued revenue.

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

6. Property, plant and equipment, net, was reduced by $0.9 million primarily as a result of the following restatement adjustments:

• a decrease of $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.

• a decrease of $0.2 million to reclassify repair expense improperly capitalized as property, plant and equipment.

7. Accumulated depreciation was reduced by $0.6 million to reverse the depreciation previously recorded on the Blackhawk pipeline.

8. Intangibles and other assets, net were increased by $0.1 million to record an intangible asset relating to a customer contract acquired as a part of the Pinnacle acquisition.

9. 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.

10. Accounts payable were adjusted by $1.7 million to correct amounts recorded for accrued product costs.

11. Accrued liabilities were decreased by $0.3 million primarily as a result of the following restatement adjustments:

• an increase of $0.1 million to reflect to reflect the tax effect of the restatement adjustments.

• a decrease of $0.3 million to reverse deferred income to other long-term liabilities 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.

12. The non-current deferred income tax liability was increased by $0.9 million to reflect the tax effect of the restatement adjustments.

13. Other long-term liabilities were increased by $2.9 million to reflect compensation expense accrued under the Participation Plan.

14. Non-controlling interest in consolidated subsidiary was decreased by $1.2 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 the 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.

15. Additional paid-in capital decreased by $0.9 million as a result of the following restatement adjustments:

• a decrease of $1.9 million as a result of restating dividends paid during the six months ended June 30, 2004 from retained earnings to additional paid in capital for dividends distributed in excess of accumulated earnings.

• an increase of $1.0 million to record compensation expense for stock options outstanding that were required to be accounted for as variable awards. In April 2004, the Company changed its policy to allow participants to exercise their stock options using the cashless method. Under APB 25, a fixed

stock option plan that permits the use of a cashless exercise becomes variable if a pattern of exercising stock options using the cashless method is demonstrated.

16. Accumulated deficit increased $2.6 million as a result of the following restatement adjustments:

• an decrease of $1.9 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 increase 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 increase of $3.2 million to reflect the effect of the restatement adjustments on net income for the six months ended June 30, 2004.

December 31, 2003 Balance Sheet

17. 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.

18. Receivables, net were reduced by $0.8 million primarily 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.

19. 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.

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

21. 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.

22. 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.

23. 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.

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

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

26. 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 interest 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 June 30, 2004 Income Statement

27. Revenues for the second quarter of 2004 increased by $1.2 million primarily as a result of the following restatement adjustments:

• an increase of $0.8 million to correct the amounts recorded for accrued revenue.

• an increase of $0.5 million to restate a pipeline imbalance credit that was improperly recorded as product costs.

• a decrease of $0.1 million to restate the settlement of a commodity derivative from interest expense to revenue.

28. Purchased product costs for the second quarter of 2004 increased by $1.8 million primarily as a result of the following restatement adjustments:

• an increase of $1.3 million to correct amounts recorded for accrued product costs.

• an increase of $0.5 million to restate a pipeline imbalance that was improperly recorded as product cost.

29. Facility expense increased by $0.2 million to record repair expense improperly capitalized as property, plant and equipment.

30. Selling, general and administrative expenses increased by $0.8 million for the second quarter of 2004 primarily as a result of the following restatement adjustments:

• an increase of $0.7 million to record compensation expense for stock options issued as variable awards. In April 2004, the Company changed its policy to allow participants to exercise their stock options using the cashless method. Under APB 25, a fixed stock option plan that permits the use of a cashless exercise becomes variable if a pattern of exercising stock options using the cashless method is demonstrated.

• an increase of $0.1 million to reflect the compensation expense under the Participation Plan.

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

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

33. Interest expense decreased by $0.4 million for the second 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 $0.1 million to restate the settlement of a commodity derivative from interest expense to revenue.

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

35. Dividend income increased by $0.1 million as a result of recording dividends received on marketable securities as dividend income. Previously, the dividends received were improperly recorded as a reduction to the carrying value of marketable securities.

36. The benefit for income taxes was decreased by $2.4 million to reflect the tax effect of the restatement adjustments.

37. Non-controlling interest in consolidated subsidiary was increased 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 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.

Three months ended June 30, 2003 Income Statement

38. Revenues increased by $0.4 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 expenses increased by $0.4 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 by $0.5 million and the amortization of deferred financing costs increased by a corresponding amount as a result of reclassifying amortization of deferred financing costs from interest expense to a separate line item on the consolidated income statement.

43. Other income was decreased by $0.1 million primarily as a result of the following restatement adjustments:

• a decrease of $0.2 million to reverse a gain improperly recognized on the sale of subordinated partnership units and interests in the Partnership’s general partner to certain employees and directors. The Participation Plan has now been accounted for as a compensatory arrangement.

• an increase of $0.1 million to restate miscellaneous income that was improperly recorded as discontinued operations.

44. The provision for income taxes was decreased by $4.5 million primarily as a result of the following restatement adjustments;

• a decrease of $4.0 million to restate income taxes to an effective rate of 37%. Previously, the Company used an incorrect effective tax rate of (12)%.

• an decrease of $0.5 million to reflect the tax effect of the restatement adjustments.

45. Non-controlling interest in consolidated subsidiary was decreased by $0.05 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 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.

46. Income from discontinued exploration and production operations was decreased by $4.1 million primarily as a result of the following restatement adjustments:

• a decrease of $4.0 million to restate income taxes attributable to discontinued operations using the correct tax rate of 26%. Previously, the Company incorrectly used a tax rate of 6%.

• a decrease of $0.1 million to restate miscellaneous income that was improperly recorded as discontinued operations.

Six months ended June 30, 2004 Income Statement

47. Revenues for the six months ended June 30, 2004 increased by $1.2 million primarily as a result of the following restatement adjustments:

• an increase of $0.9 million to correct the amounts recorded for accrued revenue.

• an increase of $0.5 million to restate a pipeline imbalance credit that was improperly recorded as product cost.

• an increase of $0.1 million to record natural gas inventory at cost. Previously the inventory was incorrectly identified as a pipeline imbalance and was recorded at market value.

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

• a decrease of $0.1 million to restate the settlement of a commodity hedge from interest expense to revenue.

• a decrease of $0.1 million related to miscellaneous other adjustments.

48. Purchased product costs for the six months ended June 30, 2004 increased by $2.2 million primarily as a result of the following restatement adjustments:

• an increase of $1.7 million to correct amounts recorded for accrued product costs.

• an increase of $0.5 million to restate an imbalance credit that was improperly recorded as product cost.

49. Facility costs for the six months ended June 30, 2004 were increased by $0.2 million primarily as a result of the following restatement adjustments:

• 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 $0.22 million to record repair expense improperly capitalized as property, plant and equipment.

• an increase of $0.02 related to miscellaneous other adjustments.

50. Selling, general and administrative expenses increased by $1.6 million for the six months ended June 30, 2004 primarily as a result of the following restatement adjustments:

• an increase of $0.6 million to record compensation expense for stock options issued as variable awards. In April 2004, the Company changed its policy to allow participants to exercise their stock options using the cashless method. Under APB 25, a fixed stock option plan that permits the use of a cashless exercise becomes variable if a pattern of exercising stock options using the cashless method is demonstrated.

• an increase of $0.4 million 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 $0.6 million to reflect the compensation expense under the Participation Plan.

51. Depreciation expense decreased by $0.2 million for the reversal of depreciation expense previously recorded on the Blackhawk pipeline.

52. Amortization of intangible assets expense increased by $0.1 million to record amortization of a customer contract that was acquired with the Blackhawk pipeline.

53. Interest expense decreased by $0.8 million for the second quarter of 2004 primarily as a result of the following restatement adjustments:

• a decrease of $0.6 million to reclassify amortization of deferred financing costs to a separate line item on the consolidated income statement.

• a decrease of $0.1 million to restate the settlement of a commodity hedge from interest expense to revenue.

• a decrease of $0.1 million related to miscellaneous other adjustments.

54. Amortization of deferred financing costs increased by $0.6 million as a result of reclassifying amortization of deferred financing costs from interest expense to a separate line item on the consolidated income statement.

55. Dividend income increased by $0.1 million as a result of recording dividends received on marketable securities as dividend income. Previously, the dividends received were improperly recorded as a reduction to the carrying value of marketable securities.

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

57. The benefit for income taxes was decreased by $1.8 million to reflect the tax effect of the restatement adjustments.

58. Non-controlling interest in consolidated subsidiary was decreased by $1.0 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 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.

Six months ended June 30, 2003 Income Statement

59. Revenues increased by $0.9 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.

60. Facility expenses increased by $0.5 million to reclassify expenses related to the retained exploration and production operations from discontinued operations to continuing operations.

61. Selling, general and administrative expense increased by $0.5 million to reflect the compensation expense under the Participation Plan.

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

63. Interest expense decreased by $0.8 million and amortization of deferred financing costs increased by a corresponding amount as a result of reclassifying amortization of deferred financing costs from interest expense to a separate line item on the consolidated income statement.

64. Other income was decreased by $0.1 million primarily as a result of the following restatement adjustments:

• an increase of $0.1 million to restate miscellaneous income that was improperly recorded as discontinued operations.

65. The benefit for income taxes was increased by $4.1 million as a result of the following restatement adjustments:

• an increase of $4.0 million to restate income taxes to an effective rate of 37%. Previously, the Company used an incorrect effective tax rate of 9%.

• an increase of $0.2 million to reflect the tax effect of the restatement adjustments.

• a decrease of $0.1 million to reclassify expenses related to the retained exploration and production operations from discontinued operations to continued operations.

66. Non-controlling interest in consolidated subsidiary was increased by $0.1 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 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.

67. Income from discontinued exploration and production operations (net of income taxes of $0.4 million) was decreased by $4.2 million primarily as a result of the following restatement adjustments:

• a decrease of $4.0 million to restate income taxes attributable to discontinued operations using the correct tax rate of 26%. Previously the Company incorrectly used a tax rate of 10%.

• a decrease of $0.1 million to restate miscellaneous income that was improperly recorded as discontinued operations.

• a decrease of $0.1 million to reclassify income related to the retained exploration and production operations from discontinued operations to continued operations.

Six months ended June 30, 2004 Cash Flow Statement

68. Net cash provided by operating activities increased by $0.54 million to adjust obligations for construction projects in process, to reflect a portion of amounts received under the lease for the Blackhawk pipeline as payments on the financing lease receivable, to reflect the capitalization of interest expense, to record repair expense improperly capitalized as property, plant and equipment, to reclassify the contribution of treasury shares to the 401(k) benefit plan from financing activities to operating activities, to reflect dividends received on marketable securities as income, to reflect the repurchase of membership interests in the Partnership’s general partner and subordinated units in the Partnership from a related party as an operating activity and to adjust the distributions paid to directors and officers under the Participation Plan from financing activities to operating activities.

69. Net cash used in investing activities increased by $0.7 million to adjust obligations for construction projects in process, to reflect a portion of amounts received under the lease for the Blackhawk pipeline as payments on the financing lease receivable, to reflect for the capitalization of interest expense, to record repair expense improperly capitalized as property, plant and equipment and to reflect dividends received on marketable securities as income.

70. Net cash used in financing activities decreased by $0.16 million to reflect the repurchase of membership interests in the Partnership’s general partner and subordinated units in the Partnership from a related party as an operating activity, to reclassify the contribution of treasury shares to the 401(k) benefit plan from financing activities to operating activities and to reflect the distributions paid to directors and officers under the Participation Plan as an operating activity.

Six months ended June 30, 2003 Cash Flow Statement

71. Net cash provided by operating activities increased by $0.3 million to reflect the sale of membership interests in the Partnership’s general partner and subordinated units in the Partnership from a related party as an operating activity, to reclassify the contribution of treasury shares to the 401(k) benefit plan from financing activities to operating activities and to reflect the distributions paid to directors and officers under the Participation Plan as an operating activity.

72. Net cash used in investing activities increased by $0.2 million to reflect the sale of membership interests in the Partnership’s general partner and subordinated units in the Partnership from a related party as an operating activity.

73. Net cash provided by financing activities decreased by $0.1 million to reclassify the contribution of treasury shares to the 401(k) benefit plan from financing activities to operating activities and to reflect the distributions paid to directors and officers under the Participation Plan as an operating activity.

74. Cash paid for interest, under supplemental cash flow information, was increased by $0.2 million to properly state cash paid for interest.

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 restatement 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 reflect separately restricted marketable securities, adjustments for dividends received on marketable securities improperly recorded as a reduction in the carrying value of 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. Compensation expense was also recorded for stock options issued as variable awards. In April 2004, the Company changed its policy to allow participants to exercise their stock options using the cashless exercise method. Under APB 25, Accounting for Stock Issued to Employees, a fixed stock option plan that permits the use of a cashless exercise becomes variable if a pattern of exercising stock options using the cashless method is demonstrated. Additionally, the Company made an adjustment to reclassify a portion of dividends paid during the six months ended March 31, 2004 from retained earnings to additional paid in capital for the amount of the 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. Common stock information in the Form 10Q/A has been restated to give retroactive effect to stock dividend paid. Other less significant adjustments and reclassifications were identified and recorded in conjunction with the restatement process.

Refer to Note 11, 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 Three and Six Months Ended June 30, 2004

We reported a net loss for the three months ended June 30, 2004 of $6.4 million, or $0.60 per diluted share, compared to net income of $10.0 million, or $0.97 per diluted share, for the second quarter of 2003. For the six months ended June 30, 2004, the Company reported a net loss of $5.7 million, or $0.53 per diluted share, compared to net income of $8.6 million, or $0.84 per diluted share, for the six months ended June 30, 2003.

The decrease in results from 2003 to 2004 primarily relates to the sale of most of the Company’s San Juan Basin properties on June 30, 2003 for a pretax gain of $19.7 million.

The Company reported a net loss from continuing operations of $6.4 million, or $0.60 per diluted share, for the three months ended June 30, 2004, compared to a net loss from continuing operations of $6.0 million, or $0.58 per diluted share, for the second quarter of 2003. For the six months ended June 30, 2004, the Company reported a net loss from continuing operations of $5.7 million, or $0.53 per diluted share, compared to a net loss from continuing operations of $9.5 million, or $0.92 per diluted share, for the same period last year.

On July 22, 2004, the board of directors of the Company declared a cash dividend of $0.025 per share of its common stock payable on August 19, 2004 to the stockholders of record as of the close of business on August 5, 2004. Consistent with the board’s objective to maintain a regular quarterly dividend, this is the second consecutive dividend declared in 2004. However, any such future declaration will be dependent upon the financial performance of the Company.

In addition, on July 30, 2004, MarkWest Energy Partners expanded its midstream business by completing the acquisition of American Central East Texas Gas Company, L.P.’s Carthage gathering system and gas processing assets for approximately $240.7 million. The acquisition was funded with a combination of private equity and interim debt financing. Consistent with its long-term strategy of maintaining a debt-to-total-capital ratio of less than 50%, the Partnership intends in the near term to replace the interim debt financing with additional equity and long-term debt financing. The Carthage gathering system offers both low- and high-pressure service to producers in the Carthage Field, gathering gas from the Cotton Valley, Pettit and Travis Peak formations. The system consists of approximately 180 miles of pipeline connected to approximately 1,700 wells with an additional 82 miles of pipeline currently under construction. The gathering system also includes approximately 65,000 horsepower of compression with an additional 35,000 horsepower currently being installed. Current system through put is approximately 245 MMcf/d and is anticipated to increase to approximately 255 MMcf/d by the end of 2004. The gathering system has a capacity of approximately 350 MMcf/d.

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 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. We also market NGLs and natural gas. We discontinued our exploration and production activities during 2003.

Our assets consist almost entirely of partnership interests in MarkWest Energy Partners. As of June 30, 2004, our partnership interests consisted of the following:

• 2,469,496 subordinated units, representing a 35% limited partner interest in the Partnership; and

• A 90% 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 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, fraction and storage of natural gas liquids, and the gathering and transpiration 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 it’s 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 significant and 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 43% of its gross margin for the six months ended June 30, 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 by 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 a hedging strategy implemented approximately two years ago that was based on our then-existing natural gas production and historical pricing data through that point in time, we incurred significant hedging losses. For the six months ended June 30, 2004 and 2003, we lost approximately $2.7 million and $8.2 million, respectively, as a result of that hedging strategy. The last transactions associated with this hedging strategy 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 by our customers. 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 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 increases 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 keep-whole contracts of MarkWest Energy Partners are associated with the Arapaho processing plant that were assumed as a part of its December 2003 Oklahoma acquisition. At the Arapaho processing plant inlet, the Btu content of the natural gas meets the downstream pipeline specifications, however, MarkWest Energy Partners has the option of extracting NGLs when the processing margin environment is favorable. In addition, approximately half, as measured in volumes, 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, coupled with the additional fees provided

for in the gas gathering contracts, the Partnership’s overall keep-whole contract 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 its 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.

Recent MarkWest Energy Partners Acquisition Activity

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

From its initial public offering through June 30, 2004, the Partnership has completed five acquisitions for an aggregate purchase price of approximately $112.3 million. These five 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;

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

• The Hobbs Lateral acquisition, which closed on April 1, 2004, for consideration of $2.3 million.

The first acquisition closed during the last few days of the first quarter of 2003. Three acquisitions closed during the second half of 2003 and one acquisition closed in the second quarter of 2004. Accordingly, our historical results of operations for the six months ended June 30, 2003, save for three months of activity from the Partnership’s Pinnacle acquisition, do not reflect the impact of these acquisitions on our operations. However, our results of operations for the three and six months ended June 30, 2004, do reflect the impact from the Partnership’s four 2003 acquisitions.

Results of Operations

Operating Data

	Three Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
Marketing
NGL product sales-Siloam plant (gallons)	35,700,000	30,900,000	87,200,000	84,900,000

MarkWest Energy Partners
Appalachia:
Natural gas processed (Mcf/d)(1)	197,000	189,000	202,000	196,000
NGLs fractionated (Gal/d)	480,000	391,000	469,000	418,000
Michigan:
Natural gas volumes transported (Mcf/d)	12,200	14,500	13,000	14,900
NGL product sales (gallons)	2,390,000	2,917,000	5,103,000	5,859,000
Crude oil transported (Bbl/d)(2)	14,700	—	14,700	—
Southwest:
Gathering system throughput (Mcf/d)(3)	103,900	44,600	100,900	NM
Lateral pipeline throughput (Mcf/d)(4)	119,300	—	74,100	—
NGL product sales (gallons) (5)	8,317,000	—	16,512,000	—

NM – Not meaningful.

(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 Foss Lake (OK) gathering system, which was acquired in December 2003.

(4) Includes volumes from the Partnership’s Power-Tex Lateral pipeline, which was acquired in September 2003, and our Hobbs Lateral pipeline, which was acquired in April 2004. The Power-Tex and Hobbs Lateral pipelines are the only laterals the Partnership own that produce 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 and second quarters of 2004 and, therefore, the throughput data from these lateral pipelines is excluded from this statistic.

(5) Includes sales from the Partnership’s Arapaho (OK) processing plant, which was acquired in December 2003.

Three Months Ended June 30, 2004 Compared to the Three Months Ended June 30, 2003

	Marketing			MarkWest Energy Partners		Eliminating Entries			Total
	(in thousands)
Three Months Ended June 30, 2004(1):
Revenues	$	37,284		$	65,659	$	(13,919	)	$	89,024

Purchased product costs	35,620			49,371		(7,729		)	77,262
Facility expenses	5,839			6,326		(6,190		)	5,975
Depreciation	356			3,301		—			3,657
Amortization of intangible assets	—			34		—			34
Total segment operating expenses	41,815			59,032		(13,919		)	86,928

Segment operating income (loss)	$	(4,531	)	$	6,627	$	—		$	2,096

Three Months Ended June 30, 2003(1):
Revenues	$	28,865		$	29,636	$	(10,260	)	$	48,241

Purchased product costs	30,585			18,423		(4,651		)	44,357
Facility expenses	5,115			5,167		(5,609		)	4,673
Depreciation	238			1,860		—			2,098
Total segment operating expenses	35,938			25,450		(10,260		)	51,128

Segment operating income (loss)	$	(7,073	)	$	4,186	$	—		$	(2,887	)

	Three Months Ended June 30,
	2004(1)			2003(1)
	(in thousands)
Segment operating income (loss)	$	2,096		$	(2,887	)
Selling, general and administrative expenses	(5,070		)	(3,766		)
Interest expense, net	(702		)	(1,494		)
Amortization of deferred financing costs	(307		)	(504		)
Dividend income	83			—
Other expense	(31		)	—
Loss before non-controlling interest in net income of consolidated subsidiary and income taxes	$	(3,931	)	$	(8,651	)

(1) As restated. See Note 11, Restatement and Reclassifications of Consolidated Financial Statements, to Notes to the Consolidated Financial Statements.

Marketing. Our marketing segment operating loss was $4.5 million for the three months ended June 30, 2004, compared to $7.1 million for the three months ended June 30, 2003, a decrease of $2.6 million. The decrease is partially attributable to a $1.2 million reduction in our hedging losses. The remainder of the change is primarily attributable to marketing initiatives which maximized storage and other transactional opportunities afforded by a more favorable NGL market environment.

MarkWest Energy Partners. Segment operating income from MarkWest Energy Partners was $6.6 million for the three months ended June 30, 2004, compared to $4.2 million for the three months ended June 30, 2003, an increase of $2.4 million, or 57%. The increase is primarily attributable to the Partnership’s 2003 acquisitions.

Selling, general and administrative expenses. Selling, general and administrative expenses were $5.1 million for the three months ended June 30, 2004, compared to $3.8 million for the three months ended June 30, 2003, an increase of $1.3 million, or 34%. The increase is attributable to several factors, including increased back office costs

associated with the growth of MarkWest Energy Partners, compensation expense associated with the Participation Plan, compliance costs, compensation expense associated with the modification of certain stock options, compensation expense for stock options accounted for as variable awards (the Company changed a policy to allow for the cashless exercise of stock options), bonus and profit sharing (bonus was not accrued during the three months ended June 30, 2003) and severance.

Interest expense, net. Interest expense, net was $0.7 million for the three months ended June 30, 2004, compared to $1.5 million for the three months ended June 30, 2003, a decrease of $0.8 million, or 53%. The decrease was principally attributable to a reduction of average outstanding consolidated debt levels. Additionally, we generated $0.2 million in interest income during the three months ended June 30, 2004, compared to less than $0.1 million for the three months ended June 30, 2003.

Income from discontinued operations. Income from discontinued operations was $16.0 million for the three months ended June 30, 2003. The amounts recorded for discontinued operations was a result of the sale of substantially all of our U.S. exploration and production business near the end the second quarter of 2003.

Six Months Ended June 30, 2004, Compared to the Six Months Ended June 30, 2003

	Marketing			MarkWest Energy Partners		Eliminating Entries			Total
	(in thousands)
Six Months Ended June 30, 2004(1):
Revenues	$	81,677		$	129,484	$	(28,437	)	$	182,724

Purchased product costs	71,471			97,224		(15,945		)	152,750
Facility expenses	11,937			12,616		(12,492		)	12,061
Depreciation	739			6,446		—			7,185
Amortization of intangible assets	—			68		—			68
Total segment operating expenses	84,147			116,354		(28,437		)	172,064

Segment operating income (loss)	$	(2,470	)	$	13,130	$	—		$	10,660

Six Months Ended June 30, 2003(1):
Revenues	$	76,064		$	47,329	$	(23,921	)	$	99,472

Purchased product costs	75,795			26,815		(12,250		)	90,360
Facility expenses	11,472			9,504		(11,671		)	9,305
Depreciation	495			3,205		—			3,700
Total segment operating expenses	87,762			39,524		(23,921		)	103,365

Segment operating income (loss)	$	(11,698	)	$	7,805	$	—		$	(3,893	)

	Six Months Ended June 30,
	2004(1)			2003(1)
	(in thousands)
Segment operating income (loss)	$	10,660		$	(3,893	)
Selling, general and administrative expenses	(10,385		)	(6,390		)
Interest expense, net	(1,697		)	(2,248		)
Amortization of deferred financing costs	(614		)	(813		)
Dividend income	83			—
Other expense	(5		)	(16		)

Loss before non-controlling interest in net income of consolidated subsidiary and income taxes	$	(1,958	)	$	(13,360	)

(1) As restated. See Note 11, Restatement and Reclassifications of Consolidated Financial Statements, to Notes to the Consolidated Financial Statements.

Marketing. Our marketing segment operating loss was $2.5 million for the six months ended June 30, 2004, compared to a loss of $11.7 million for the six months ended June 30, 2003, a decrease of $9.2 million, or 79%. Approximately $5.4 million of the change was attributable to a reduction in our hedging losses. The remainder of the change is primarily attributable to marketing initiatives which maximized storage and other transactional opportunities afforded by a more favorable NGL market environment.

MarkWest Energy Partners. Segment operating income from MarkWest Energy Partners was $13.1 million for the six months ended June 30, 2004, compared to $7.8 million for the six months ended June 30, 2003, an increase of $5.3 million, or 68%. The increase is primarily attributable to the Partnership’s 2003 acquisitions.

Selling, general and administrative expenses. Selling, general and administrative expenses were $10.4 million for the six months ended June 30, 2004, compared to $6.4 million for the six months ended June 30, 2003, an increase of $4.0 million, or 63%. The increase is attributable to increased back office costs associated with the growth of MarkWest Energy Partners, compensation expense associated with the Participation Plan, compensation expense associated with the modification of certain stock options, compensation expense for stock options issued as variable awards (the Company changed a policy to allow for the cashless exercise of stock options), compliance costs, bonus and profit sharing (a bonus was not accrued during the six months ended June 30, 2003), and severance.

Interest expense, net. Interest expense, net was $1.7 million for the six months ended June 30, 2004, compared to $2.2 million for the six months ended June 30, 2003, a decrease of $0.5 million, or 23%. The decrease was principally attributable to a reduction of average outstanding consolidated debt levels. Additionally, we generated $0.4 million in interest income during the six months ended June 30, 2004, compared to less than $0.1 million for the six months ended June 30, 2003.

Income from discontinued operations. Income from discontinued operations was $18.1 million for the six months ended June 30, 2003. The amounts recorded for discontinued operations was a result of the sale of substantially all of our U.S. exploration and production business near the end the second 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 $36.3 million in unrestricted cash on hand at December 31, 2003. As a result, exclusive of MarkWest Energy Partners’ debt, we had no debt as of June 30, 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 stockholders. In May 2004, we disbursed approximately $0.2 million to pay the first quarterly dividend of $0.025 per common share to our common shareholders. On July 22, 2004, our board of directors declared a dividend of $0.025 per common share to be paid August 19, 2004, to stockholders of record as of the close of business on August 5, 2004.

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 90.2% 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, 23.0% of all cash distributed after each unit has received $0.625 for that quarter and 48.0% of all cash distributed after each unit has received $0.75 for that quarter. For the six months ended June 30, 2004, we received $3.4 million in distributions for our subordinated units, and the general partner received $0.5 million, including $0.4 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 exceed the prices paid for 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 January 2004 offering of common units.

During July 2004, the Partnership completed a private offering of 1.3 million common units, at $34.50 per unit, representing approximately $45.0 million in proceeds after transaction costs of approximately $0.9 million and including a contribution from the general partner of $0.9 million to maintain its ownership interest. In addition, the Partnership amended and restated its credit facility, increasing its maximum lending limit from $140.0 million to $315.0 million. The credit facility included a $265.0 million revolving facility and a $50.0 million term loan facility. The Partnership used the proceeds from the private offering and borrowings of $195.7 million under the credit facility to finance the American Central East Texas acquisition.

The credit facility includes a $265.0 million revolving facility and a $50.0 million term-loan facility. The term-loan portion of the amended and restated credit facility matures in December 2004 and the revolving-portion matures in May 2005. At August 2, 2004, $287.0 million was outstanding, and $28.0 million was available, under the credit facility. The Partnership intends to permanently finance this acquisition in the near term with additional equity and long-term debt. The goal remains for the Partnership to maintain a debt-to-capital ratio of less than 50 percent in keeping with its long-term balance sheet objectives.

Cash Flows

	Six Months Ended June 30,
	2004(1)			2003(1)
	(in thousands)
Net cash provided by operating activities	$	21,338		$	11,915
Net cash used in investing activities	$	(21,497	)	$	(2,686	)
Net cash provided by (used in) financing activities	$	(5,078	)	$	15,558

(1) As restated. See Note 11, Restatement and Reclassifications of Consolidated Financial Statements, to Notes to the Consolidated Financial Statements.

Net cash provided by operating activities for the six months ended June 30, 2004, increased relative to the same period in the prior year principally due to an increase in net income (loss) from continuing operations.

Net cash used in investing activities for the six months ended June 30, 2004, increased relative to the same period in the prior year primarily due to the proceeds received in 2003 from the sale of our U.S. exploration and production business.

Net cash used in financing activities for the six months ended June 30, 2004, was primarily attributable to quarterly distributions paid by the Partnership and quarterly dividends paid by the Company. Net cash provided by financing activities for the six months ended June 30, 2003, was primarily attributable to borrowings of long-term debt exceeding repayments of long-term debt.

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 as a result of certain factors as more fully discussed under the heading “Risk Factors” contained in our annual report on Form 10-K filed on March 15, 2004 with the Securities and Exchange Commission (File No. 001-31239) for the Company’s fiscal year ended December 31, 2003. 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 second quarter of each of the years 2003 and 2004. Please refer to Note 11, 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 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 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, an adjustment to reflect separately restricted marketable securities, adjustments for dividends received on marketable securities improperly recorded as a reduction in the carrying value of marketable securities and adjustments to accrued property taxes. Adjustments were also made to record compensation expense as a result of the modification of certain stock options for two officers who terminated their employment with the Company but who continued to serve on its Board of Directors. Compensation expense was also recorded for stock options issued as variable awards. In April 2004, the Company changed its policy to allow participants to exercise their stock options using the cashless exercise method. Under APB 25, Accounting for Stock Issued to Employees, a fixed stock option plan that permits the use of a cashless exercise becomes variable if a pattern of exercising stock options using the cashless method is demonstrated. Additionally, the Company made an adjustment to reclassify a portion of dividends paid during the three months ended June 30, 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. Stock information has been restated to give retroactive effect to stock dividends paid. The Company is filing contemporaneously with this Form 10-Q/A for the quarterly period ended June 30, 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 March 31, 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 June 30, 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 June 30, 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 June 30, 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.

Changes in Internal Controls over Financial Reporting

During the period covered by this quarterly report on Form 10-Q as amended by this Form 10-Q/A, there were no changes in our internal control over financial reporting during the period covered by the original report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 6. Exhibits

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

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

SIGNATURE

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

		MarkWest Hydrocarbon, Inc.
		(Registrant)

Date: 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 Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act.

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