Markwest Hydrocarbon (MWP) 10-Q/A 2004 Q3 Quarterly report (amended)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

(Amendment No. 1)

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

For the quarterly period ended September 30, 2004

OR

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

For the transition period from                   to                 

Commission File Number 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 10,746,218 shares of common stock, $.01 per share par value, outstanding as of October 31, 2004.

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Item 4. Controls and Procedures

PART II—OTHER INFORMATION

Item 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 third 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 November 22, 2004 for the third quarter ended September 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 September 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 16, 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, an adjustment to record losses on derivative instruments that do not qualify for hedge accounting treatment 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 nine months ended September 30, 2004 from retained earnings to additional paid in capital for the amount of dividends distributed in excess of accumulated earnings.

Cash was also adjusted primarily as a result of reclassifying amounts recorded for the purchase of property, plant and equipment, intangible assets and accrued property tax relating to an acquisition, from cash to those respective accounts.  Initially, the purchase of those assets were recorded to a cash clearing account until the purchase price was settled in the fourth quarter of 2004.  Other less significant restatement adjustments and reclassifications, to conform to current year presentation, were identified and recorded in conjunction with the restatement process as discussed in Note 16.

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 ended March 31, 2004 and June 30, 2004.

This Form 10-Q/A amends and restates only Items 1, 2, 3 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)

	September 30, 2004			December 31, 2003
	(as restated, see note 16)
ASSETS
Current assets:
Cash and cash equivalents	$	21,647		$	42,144
Restricted cash	550			—
Marketable securities	12,206			—
Restricted marketable securities	2,500			2,500
Receivables, net (including related party receivables of $87 and $40, respectively, and net of allowance for doubtful accounts of $250 and $120, respectively)	45,448			29,910
Inventories	12,450			5,548
Prepaid replacement natural gas	13,173			5,940
Deferred income taxes	68			534
Other current assets	3,658			503
Total current assets	111,700			87,079
Property, plant and equipment	323,963			232,257
Less: accumulated depreciation, depletion and amortization	(54,967		)	(44,134		)
Total property, plant and equipment, net	268,996			188,123
Other assets:
Intangibles and other assets, net	166,459			84
Deferred financing costs, net	7,184			3,747
Deferred offering costs, net	—			995
Investment in and advances to equity investee	200			250
Notes receivable from officers	207			217
Total other assets	$	174,050		5,293
Total assets	$	554,746		$	280,495
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable (including related party payables of $32 and $51, respectively)	$	46,703		$	24,052
Accrued liabilities	23,309			16,511
Fair value of derivative instruments	2,747			1,769
Total current liabilities	72,759			42,332
Long-term debt	197,500			126,200
Deferred income taxes	6,387			5,594
Fair value of derivative instruments	—			125
Other long-term liabilities	4,780			2,901
Non-controlling interest in consolidated subsidiary	230,451			52,429
Commitments and contingencies (Note 13)
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, 10,817,967 and 10,601,775 shares issued, respectively	108			106
Additional paid-in capital	51,769			50,705
Retained earnings (accumulated deficit)	(8,339		)	2,406
Accumulated other comprehensive loss, net of tax	(230		)	(1,793		)
Treasury stock at cost, 65,999 and 75,930 shares, respectively	(439		)	(510		)
Total stockholders’ equity	42,869			50,914
Total liabilities and stockholders’ equity	$	554,746		$	280,495

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

1

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
	(as restated, see note 16)
Revenues	$	121,511		$	48,719		$	304,235		$	148,191
Operating expenses:
Purchased product costs	95,209			44,521			247,960			134,881
Facility expenses	8,398			5,445			20,459			14,750
Selling, general and administrative expenses	7,252			3,707			17,637			10,097
Depreciation	4,510			2,471			11,695			6,171
Amortization of intangible assets	1,400			—			1,468			—
Accretion of asset retirement obligation	13			—			13			—
Loss on sale of terminals	—			55			—			55
Total operating expenses (a component of interest expense)	116,782			56,199			299,232			165,954
Income (loss) from operations	4,729			(7,480		)	5,003			(17,763		)
Other income (expense):
Interest expense, net	(3,559		)	(658		)	(5,256		)	(2,906		)
Amortization of deferred financing costs (a component of interest expense)	(3,120		)	(457		)	(3,734		)	(1,270		)
Dividend income	86			—			169			—
Other income	553			31			547			15
Income (loss) from continuing operations before non-controlling interest in net income of consolidated subsidiary and income taxes	(1,311		)	(8,564		)	(3,271		)	(21,924		)
Provision (benefit) for income taxes:
Current	39			(3,885		)	151			(9,676		)
Deferred	112			169			438			421
Provision (benefit) for income taxes	151			(3,716		)	589			(9,255		)
Non-controlling interest in net income of consolidated subsidiary	(504		)	(1,519		)	(3,759		)	(3,188		)
Loss from continuing operations	(1,966		)	(6,367		)	(7,619		)	(15,857		)
Discontinued operations:
Income (loss) from discontinued exploration and production operations (net of income taxes in 2003 of $(330) and $625, respectively)	—			(1,262		)	—			2,606
Gain from disposal of discontinued exploration and production operations (less applicable income taxes of $0, $2,750, $0 and $8,173, respectively)	—			593			—			14,862
Income (loss) from discontinued operations	—			(669		)	—			17,468
Income (loss) before cumulative effect of accounting change	(1,966		)	(7,036		)	(7,619		)	1,611
Cumulative effect of change in accounting for asset retirement obligations, net of tax	—			—			—			(29		)
Net income (loss)	$	(1,966	)	$	(7,036	)	$	(7,619	)	$	1,582
Loss from continuing operations per share:
Basic	$	(0.18	)	$	(0.62	)	$	(0.71	)	$	(1.54	)
Diluted	$	(0.18	)	$	(0.62	)	$	(0.71	)	$	(1.54	)
Net income (loss) per share:
Basic	$	(0.18	)	$	(0.68	)	$	(0.71	)	$	0.15
Diluted	$	(0.18	)	$	(0.68	)	$	(0.71	)	$	0.15
Weighted average number of outstanding shares of common stock:
Basic	10,736			10,316			10,665			10,300
Diluted	10,800			10,340			10,715			10,318
Cash dividend per common share	$	0.023		$	—		$	0.50		$	—

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

2

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

(in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
	(as restated, see note 16)
Net income (loss)	$	(1,966	)	$	(7,036	)	$	(7,619	)	$	1,582
Other comprehensive income (loss), net of tax:
Foreign currency translation	—			(265		)	—			3,796
Unrealized gains on commodity derivatives accounted for as hedges	888			3,666			1,656			3,142
Unrealized gains on marketable securities	277			—			(93		)	—
Total other comprehensive income	1,165			3,401			1,563			6,938
Other comprehensive income (loss)	$	(801	)	$	(3,635	)	$	(6,056	)	$	8,520

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

3

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)

	Nine Months Ended September 30,
	2004			2003
	(as restated, see note 16)
Cash flows from operating activities:
Net income (loss)	$	(7,619	)	$	1,582
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Cumulative effect of change in accounting	—			29
Depreciation and depletion	11,694			18,814
Amortization of deferred financing costs	2,265			1,270
Write down of deferred financing costs	1,469			—
Amortization of intangible asset	1,468			—
Stock option compensation expense	1,531			—
Restricted unit compensation expense	732			554
Participation Plan compensation expense	1,205			569
Contribution of treasury shares to 401(k) benefit plan	107			190
Equity in losses of investee	50			—
Loss from sale of property, plant and equipment	145			—
Non-controlling interest in net income of consolidated subsidiary	3,759			3,188
Unrealized losses (gains) on derivative instrument	732			(2,207		)
Reclassification of Enron hedges to purchased product costs	—			(153		)
Deferred income taxes	438			4,637
Gain from non-operating assets sale to related party	—			—
Gain on sale of San Juan Basin properties	—			(23,035		)
Cost of exiting hedges	—			(3,440		)
Other	(51		)	427
Changes in operating assets and liabilities:
(Increase) decrease in receivables	(15,248		)	15,046
Increase in inventories	(6,902		)	(2,540		)
Increase in prepaid replacement natural gas	(7,233		)	(3,941		)
Increase in other current assets	(3,133		)	—
Increase (decrease) in accounts payable and accrued liabilities	30,114			(9,066		)
(Decrease) increase in other long-term liabilities	(2		)	1,565
Net cash flow provided by operating activities	15,521			3,489
Cash flows from investing activities:
Increase in restricted cash	(550		)	—
Purchase of marketable securities	(11,920		)	—
East Texas System acquisition	(240,606		)	—
Hobbs Lateral acquisition	(2,275		)	—
Pinnacle acquisition, net of cash acquired	—			(38,238		)
Lubbock pipeline acquisition	—			(12,222		)
Proceeds from sale of San Juan Basin properties, net of disposal costs	—			55,007
Capital expenditures	(12,668		)	(24,968		)
Proceeds from sales of terminals	—			2,438
Proceeds from sale of assets	206			—
Increase in other contracts	(3,250		)	—
Proceeds on financing lease receivable	133			—
Proceeds from sale of assets to related parties	—			—
Net cash used in investing activities	(270,930		)	(17,983		)

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

4

	Nine Months Ended September 30,
	2004			2003
	(as restated, see note 16)
Cash flows from financing activities:
Proceeds from long-term debt	215,600			86,835
Repayment of long-term debt	(144,300		)	(75,130		)
Payments for debt issuance costs	(7,193		)	(811		)
Proceeds from public offerings of MarkWest Energy Partners’ common units, net	140,014			—
Proceeds from private placement of MarkWest Energy Partners’ common units, net	44,139			9,764
Distributions to MarkWest Energy Partners’ unitholders	(9,437		)	(5,107		)
Acquisitions and dispositions of MarkWest Energy GP general partnership interests and MarkWest Energy Partners subordinated units to related parties	—			17
Exercise of stock options	1,413			333
Repurchase of treasury shares	(36		)	(348		)
Payment of dividends	(5,288		)	—
Net cash provided by financing activities	234,912			15,553
Effect of exchange rate changes on cash	—			111
Net increase (decrease) in cash and cash equivalents	(20,497		)	1,170
Cash and cash equivalents at beginning of period	42,144			6,410
Cash and cash equivalents at end of period	$	21,647		$	7,580
Supplemental cash flow information:
Cash paid for interest, net of amount capitalized	$	4,607		$	1,474
Construction projects in progress obligation	$	1,094		$	—
Property, plant and equipment asset retirement obligation	$	377		$	—

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

5

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 16	10,602	(76	)	$	106	$	50,705		$	2,406		$	(1,793	)	$	(510	)	$	50,914
Stock option exercises	216	—		2		1,695			—			—			—			1,697
Modification of stock options, as restated, see note 16	—	—		—		1,531			—			—			—			1,531
Treasury stock acquired	—	(3	)	—		—			—			—			(36		)	(36		)
Treasury stock reissued	—	13		—		—			—			—			107			107
Dividends, as restated, see note 16	—	—		—		(2,162		)	(3,126		)	—			—			(5,288		)
Net loss, as restated, see note 16	—	—		—		—			(7,619		)	—			—			(7,619		)
Other comprehensive income	—	—		—		—			—			1,563			—			1,563
Balance, September 30, 2004, as restated, see note 16	10,818	(66	)	$	108	$	51,769		$	(8,339	)	$	(230	)	$	(439	)	$	42,869

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

6

MARKWEST HYDROCARBON, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1.General

MarkWest Hydrocarbon, Inc. (“MarkWest Hydrocarbon” or the “Company”) markets natural gas and natural gas liquids itself, and also manages MarkWest Energy Partners, L.P. (“MarkWest Energy Partners” or the “Partnership”), through its majority ownership in the general partner of the Partnership.  MarkWest Energy Partners is 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’s employees are responsible for conducting the Partnership’s business and operating its assets, pursuant to a Services Agreement.

The Company’s assets consist primarily of partnership interests in MarkWest Energy Partners.  As of September 30, 2004, its partnership interests consisted of 2,469,496 subordinated units, representing a 23% limited partner interest in the Partnership and a 90% membership (ownership) interest in MarkWest Energy GP, L.L.C., the general partner of the Partnership, which owns a 2% general partner interest and all of the incentive distribution rights in the Partnership.

The consolidated financial statements include the accounts of MarkWest Hydrocarbon, Inc. and its subsidiaries, including MarkWest Energy Partners. Through consolidation, the Company has eliminated all significant intercompany accounts and transactions. The Company has reclassified certain prior period amounts to conform to the current year’s presentation (See Note 16).

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.  Please read the interim consolidated financial statements in conjunction with the Consolidated Financial Statements and attached notes thereto as of and for the year ended December 31, 2003 (which has 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.  Results for the three and nine months ended September 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.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 its consolidated subsidiary, MarkWest Energy.  The Company accounts for these plans using fixed or 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 stock options using the cashless method is demonstrated.  As a result, in April 2004, the Company was required to account for

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

7

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 $0.5 million and $1.2 million for the three and nine months ended September 30, 2004 and no compensation expense for the three and nine months ended September 30, 2003.  During the nine months ended September 30, 2004, recipients exercised their options to purchase an aggregate of approximately 216,000 shares of the Company’s common stock.  Recipients exercised options for approximately 111,000 shares using the cashless method resulting in the net issuance of approximately 36,000 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 $0.8 million and $0.2 million for the three months ended September 30, 2004 and 2003, respectively. For the nine months ended September 30, 2004 and 2003, the Company recorded compensation expense of $1.2 million and $0.6 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

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

8

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 September 30, 2004, 15,200 restricted units were granted.  There were no restricted units granted during the three months ended September 30, 2003.  During the nine months ended September 30, 2004 and 2003, 23,200 and 3,000 restricted units, respectively, were granted.  The Partnership recorded compensation expense of $0.4 million and $0.2 million for the three months ended September 30, 2004 and 2003, respectively.  For the nine months ended September 30, 2004 and 2003, the Company recorded compensation expense of $0.7 million and $0.6 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 September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
	(in thousands, except per share data)
	(as restated, see note 16)			(as restated, see note 16)			(as restated, see note 16)			(as restated, see note 16)
Net income (loss), as reported	$	(1,966	)	$	(7,036	)	$	(7,619	)	$	1,582
Add: compensation expense included in reported net income (loss)	1,609			289			3,468			1,123
Deduct: total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effect	(1,156		)	(317		)	(1,952		)	(1,416		)
Pro forma net income (loss)	$	(1,513	)	$	(7,064	)	$	(6,103	)	$	1,289
Net income (loss) per share:
Basic:
As reported	$	(0.18	)	$	(0.68	)	$	(0.71	)	$	0.15
Pro forma	$	(0.14	)	$	(0.68	)	$	(0.57	)	$	0.15
Diluted:
As reported	$	(0.18	)	$	(0.68	)	$	(0.71	)	$	0.15
Pro forma	$	(0.14	)	$	(0.68	)	$	(0.57	)	$	0.15

3.MarkWest Energy Partners’ Common Unit Offerings

During January 2004, the Partnership completed an offering of 1,100,444 common units at $39.90 per unit for gross proceeds of $43.9 million.  In addition, of the 172,200 common units available to underwriters to cover over-allotments, 72,500 were sold for gross proceeds of $2.9 million. To maintain its 2% interest, the general partner of the Partnership contributed $1.0 million.  Gross proceeds from parties other than MarkWest Hydrocarbon, Inc. of $46.9 million less associated offering costs of $3.8 million, of which $0.1 million related to the general partner’s share, resulted in net proceeds from the secondary public offering of $43.1 million.  As approximately $1.0 million of the offering costs had been incurred during fiscal 2003, net cash generated from the offering during 2004 was approximately $44.1 million.

During July 2004, the Partnership sold 1,304,438 common units at $34.50 per unit for gross proceeds of $45.0 million in a private placement to certain accredited investors.  Transaction costs were $1.0 million and the capital contribution from the general partner to maintain its 2% general partner interest was $0.9 million.  Net proceeds were used to partially finance the American Central Eastern Texas Gas Co, Limited Partnership (“American Central East Texas”) Carthage gathering system and gas processing assets (See Note 5).

On September 21, 2004, the Partnership completed a secondary public offering of 2,323,609 of its common

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

9

units at $43.41 per unit for gross proceeds of $100.9 million and 157,395 common units sold by certain selling unitholders.  Of the 2,323,609 common units sold, 323,609 common units were sold by the Partnership pursuant to the underwriter’s over-allotment option. MarkWest Energy Partners did not receive any proceeds from the common units sold by the selling unitholders.  The total net proceeds from the offering, after deducting transaction costs of $5.2 million and including the general partner’s 2% capital contribution of $2.1 million, were $97.8 million and were used to repay a portion of the outstanding indebtedness under the amended and restated credit facility.

4.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, dividends and interest income, are reflected in earnings.

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

September 30, 2004 (as restated, see note 16)	Cost Basis		Unrealized gains		Unrealized losses			Recorded Basis
Equity securities:
Master limited partnership units	$	5,150	$	318	$	(25	)	$	5,443
Equity securities, classified as current	5,150		318		(25		)	5,443
Fixed maturities:
Mortgage backed securities (due after one year through five years)	6,753		39		(29		)	6,763
Mortgage back securities, classified as non-current	6,753		39		(29		)	6,763
Total marketable securities	$	11,903	$	357	$	(54	)	$	12,206
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 16)	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 September 30, 2004, unrealized gains of $0.4 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.

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

10

5.MarkWest Energy Partners’ Acquisitions

East Texas System Acquisition

On July 30, 2004, MarkWest Energy Partners completed the acquisition (the “East Texas System acquisition”) of American Central Eastern Texas’ Carthage gathering system and gas processing assets located in East Texas for approximately $240.6 million.  Through the consolidation of the Partnership, the Company included the results of operations of the Carthage gathering system 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 completed in 2005.

In conjunction with the closing of the acquisition, the Partnership completed an offering of 1,304,438 of its common units, at $34.50 per unit, which netted MarkWest Energy Partners approximately $45.0 million 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 the maximum lending limit from $140.0 million to $315.0 million.  The credit facility includes a $265.0 million revolving facility and a $50.0 million term loan facility.  MarkWest Energy Partners used the proceeds from the private offering and borrowings of $195.7 million under the Partnership’s credit facility to finance the East Texas System acquisition.

The purchase price was comprised of $240.6 million, and was allocated as follows (in thousands):

Acquisition costs:
Cash consideration	$	240,211
Direct acquisition costs	396
Total	$	240,607
Allocation of acquisition costs:
Customer contracts	$	164,473
Property, plant and equipment	76,767
Inventory	66
Imbalance payable	(337		)
Property taxes payable	(362		)
Total	$	240,607

Hobbs Lateral Acquisition

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.

Michigan Crude Pipeline

On December 18, 2003, MarkWest Energy Partners 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 five 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 accompanying notes are an integral part of these consolidated financial statements.

11

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

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

Acquisition costs:
Cash consideration	$	21,155
Direct acquisition costs	128
Total	$	21,283
Allocation of acquisition costs:
Property, plant and equipment	$	21,283

Western Oklahoma Acquisition

On December 1, 2003, MarkWest Energy Partners completed the acquisition of certain assets of American Central Western Oklahoma Gas Company, L.L.C. 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 acquired 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.

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

Lubbock Pipeline Acquisition

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

Pinnacle Acquisition

On March 28, 2003, MarkWest Energy Partners completed the acquisition (the “Pinnacle acquisition”) of Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG Transmission Company, Inc., PNG Utility Company

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

12

and Bright Star Gathering, Inc. (collectively, “Pinnacle”).  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

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, the Michigan Crude Pipeline and the East Texas System acquisition each had occurred as of the beginning of the period presented.  The unaudited pro forma results have been prepared for comparative purposes only and may not be indicative of future results.  The pro forma results of operations of the Hobbs Lateral acquisition and the Lubbock Pipeline acquisition have not been presented, as they are not significant.

	Three Months Ended September 30, 2004			Three Months Ended September 30, 2003			Nine Months Ended September 30, 2004			Nine Months Ended September 30, 2003
	(in thousands, except per share data)
	(as restated, see note 16)			(as restated, see note 16)			(as restated, see note 16)			(as restated, see note 16)
Revenue	$	125,084		$	67,440		$	324,913		$	224,466
Income (loss) from continuing operations	$	(1,599	)	$	(8,059	)	$	(7,063	)	$	(27,144	)
Income (loss) from continuing operations per share:
Basic	$	(0.15	)	$	(0.78	)	$	(0.66	)	$	(2.64	)
Diluted	$	(0.15	)	$	(0.78	)	$	(0.66	)	$	(2.64	)

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

13

6.Property, Plant and Equipment

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

	September 30, 2004 (1)			December 31, 2003
	(in thousands)
	(as restated, see note 16)
Property, plant and equipment:
Gas gathering facilities	$	146,721		$	73,424
Gas processing plants	56,277			55,888
Fractionation and storage facilities	22,496			22,160
Natural gas pipelines	39,030			38,790
Crude oil pipeline	18,499			18,352
NGL transportation facilities	4,391			4,415
Marketing assets	1,606			1,987
Oil and gas properties and equipment, full cost method	2,509			2,380
Land, buildings and other equipment	11,258			12,499
Construction in-progress	21,176			2,362
	323,963			232,257
Less: Accumulated depreciation, depletion, amortization and impairment	(54,967		)	(44,134		)
Total property, plant and equipment, net	$	268,996		$	188,123

Cobb Processing Plant

During 2003, the Company entered into an agreement with the Partnership for the construction of a new Cobb processing plant.  Initially, we expected the construction costs of the new plant and the costs to decommission and dismantle the old plant to be approximately $2.1 million, $1.7 million to be funded by the Company and $0.4 million to be funded by the Partnership.  In the third quarter of 2004, this number was revised and the Company now expects the costs to be $3.6 million to construct and $0.4 million to decommission and dismantle.  The Partnership will fund the $1.9 million increase in expected costs.  Construction is expected to be completed by the end of 2004.  As of September 30, 2004, the Company had contributed $1.3 million, resulting in $0.4 million to be contributed during the fourth quarter of fiscal 2004.

7.Adoption of SFAS No. 143

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

The cumulative effect of this accounting change for years prior to 2003 was less than $0.1 million and is reflected in the Company’s statement of operations for the three months ended March 31, 2003. At the time of adoption, the Company recorded an asset retirement obligation of $3.4 million, decreased a site restoration liability of $0.9 million that was recorded prior to the implementation of SFAS No. 143 and increased net property, plant and equipment $2.4 million in accordance with the provisions of SFAS No. 143. There was no impact on the Company’s 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 $0.9 million and $3.8 million at September 30, 2004 and 2003, respectively.

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

14

The following is a reconciliation of the changes in the asset retirement obligation from January 1, 2004 to September 30, 2004 (in thousands):

Asset retirement obligation as of December 31, 2003	$	504
Liabilities accrued during the period	377
Liabilities settled	(4		)
Accretion	13
Asset retirement obligation as of September 30, 2004	$	890

The Company’s assets subject to asset retirement obligations, exclusive of assets owned by MarkWest Energy, were primarily oil and gas wells. The Company discontinued its exploration and production business and sold off substantially all of its assets as of December 31, 2003.

The Partnership reviewed current laws and regulations governing obligations for asset retirements as well as leases.  Based on that review, the Partnership identified certain land leases in East Texas that contain provisions requiring the Partnership to return the land to its original condition upon the termination of the lease.  Based on the review of the leases, the Partnership recorded an asset retirement obligation of $0.4 million during the three months ended September 30, 2004, using an estimated average term of the leases of 25 years.

In accordance with SFAS No. 143, the Partnership has identified certain assets that have an indeterminate life, and thus a future retirement obligation is not determinable.  These assets include certain pipelines and processing plants.  A liability for these asset retirement obligations will be recorded when a fair value is determinable.

The asset retirement obligation associated with the Partnership’s remaining facilities was insignificant and not recognized in the financial statements.

In October 2003, the board of directors of the Company’s general partner approved a plan to shut down the Partnership’s existing Cobb processing facility, and construct a replacement facility. Construction of the new facility was completed in the first quarter of 2005.  During the fourth quarter of 2003, the Partnership estimated the amount of the asset retirement obligation associated with the decommissioning and dismantlement of the old Cobb facility to be $0.5 million and, accordingly, the Company recorded a related accrued liability.  At September 30, 2004, the asset retirement obligation was $0.5 million.

At January 1 and December 31, 2004 and 2003, there were no assets legally restricted for purposes of settling asset retirement obligations.

8.Intangible Assets

On July 30, 2004, the Partnership completed the acquisition of American Central Eastern Texas’ Carthage gathering system and gas processing assets located in East Texas for approximately $240.6 million.  Of the total purchase price, $164.5 million was allocated to amortizable intangible assets (i.e., customer contracts) based on the net present value of the projected cash flows. The key variables that determined the valuation of the customer contracts was the assumption of renewals, economic incentives to retain customers, historical volumes, current and future capacity of the gathering system and pricing volatility.  The Partnership is amortizing the fair value of these customer contracts on a straight-line basis over an estimated economic life of 20 years.  The estimated economic life was determined by assessing the life of the assets to which the contracts relate, likelihood of renewals, competitive factors, regulatory or legal provisions, and maintenance and renewal costs.

The Company entered into a series of agreements with a gas producer in September, under which the Company processes natural gas for the producer under modified keep-whole contracts.  Other intangible assets include $3.3 million in consideration given to the producer in connection with these non-separable contracts that is being amortized over the term of the contracts, October 1, 2004 through February 9, 2015.

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

15

The Company reviews long-lived assets for potential impairment whenever there is an indication that the carrying amount may not be recoverable from future estimated cash flows.  Through September 30, 2004, management believes that there have been no indications of impairment of the intangible assets.

The Company’s purchased intangible assets associated with the East Texas System acquisition and other non-acquisition contract costs at September 30, 2004, are composed of (in thousands):

	Gross		Accumulated Amortization		Net
Customer contracts (1-20 years)	$	164,677	$	1,468	$	163,209
Other (October 1, 2004 – February 9, 2015)	3,250		—		3,250
Total intangible assets	$	167,927	$	1,468	$	166,459

Amortization expense related to customer contracts was $1.4 million for the nine months ended September 30, 2004.

Estimated future amortization expense related to intangible assets at September 30, 2004 is as follows (in thousands):

Year ending December 31:
2004	$	2,162
2005	8,579
2006	8,511
2007	8,511
2008	8,511
2009	8,511
Thereafter	121,674

9.Debt

In July 2004 and August 2004, the Partnership amended and restated its credit facility, increasing its maximum lending limit from $140.0 million to $315.0 million.  The credit facility includes a $265.0 million revolving facility and a $50.0 million term loan facility.  MarkWest Energy Partners used the proceeds from the offering and borrowings under its amended and restated credit facility to finance the East Texas System acquisition. All of the Partnership’s assets are pledged to the credit facility lenders to secure the repayment of the outstanding borrowings under the credit facility. The term loan portion of the amended and restated credit facility matures in December 2004 and the revolving portion matures in May 2005.  Under the term loan, to the extent that a portion or all of the term loan is repaid, then those amounts may not be reborrowed.  In addition, there are certain restrictions on the reborrowing amounts paid under the revolver loan.  At September 30, 2004, $197.5 million was outstanding, and $46.5 million was available under the Partnership credit facility.

The interest rate on the credit facility is determined using a variable interest rate based on one of two indices that include either (i) LIBOR plus 3.5% to LIBOR plus 4.5% or (ii) Base Rate (“BR”) (as defined for any day, a fluctuating rate per annum equal to the higher of (a) the Federal Funds Rate plus ½ of 1% and (b) the rate of interest in effect for such day as publicly announced from time to time by the Administrative Agent of the debt as its “prime rate”) plus 2.5% to BR plus 3.5%, depending on our maintenance of certain financial leverage ratios.  The Partnership is also required to pay a commitment fee equal to the applicable rate (as defined in the credit agreement) times the actual daily amount by which the aggregate revolver commitments exceed the sum of (i) the outstanding amount of revolver loans plus (ii) the outstanding amount of letters of credit obligations.  The commitment fee is due and payable quarterly in arrears on the last business day of each March, June, September and December.  For the nine months ended September 30, 2004, the weighted average interest rate was 5.4%.

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

16

Subsequent event

In October 2004, the Partnership amended and restated its credit facility, decreasing the maximum lending limit from $315.0 million to $200.0 million and increasing the term of the facility to five years.  The credit facility includes a revolving facility of $200.0 million with the potential to increase the maximum lending limit to $300.0 million.  The credit facility is guaranteed by the Partnership and all of its present and future subsidiaries and is collateralized by substantially all of its existing and future assets and those of its subsidiaries, including stock and other equity interests.  The borrowing under the Partnership’s credit facility will bear interest at a variable interest rate based on one of two indices that include either (i) LIBOR plus an applicable margin, which is fixed at a rate of 2.75% for the first two quarters following the closing of the credit facility or (ii) Base Rate (as defined for any day, a fluctuating rate per annum equal to the higher of (a) the Federal Funds Rate plus ½ of 1% and (b) the rate of interest in effect for such day as publicly announced from time to time by the Administrative Agent of the debt as its “prime rate”) plus an applicable margin, which shall be fixed at a rate of 2.00% for the first two quarters following the closing of the credit facility.  After that period, the applicable margin will be adjusted quarterly based on its ratio of funded debt to EBITDA (as defined in the credit agreement).  Consequently, as of September 30, 2004, the Company has classified the debt balance as non-current.

In connection with the credit facility, the Partnership is subject to a number of restrictions on its business, including restrictions on its ability to grant liens on assets, merge, consolidate or sell assets, incur indebtedness (other than subordinate indebtedness), make acquisitions, engage in other businesses, enter into capital or operating leases, engage in transactions with affiliates, make distributions on equity interests and other usual and customary covenants.  In addition, the Partnership is subject to certain financial maintenance covenants, including its ratios of total debt to EBITDA, total senior secured debt to EBITDA, EBITDA to interest and a minimum net worth requirement.  Failure to comply with the provisions of any of these covenants could result in acceleration of the Partnership’s debt and other financial obligations.

In October 2004, the Partnership issued $225.0 million of senior notes at a fixed rate of 6.875% and with a maturity date of November 1, 2014.  Subject to compliance with certain covenants, the Partnership may issue additional notes from time to time under the indenture.  Interest on the notes accrue at the rate of 6.875% per year and are payable semi-annually in arrears on May 1 and November 1, commencing on May 1, 2005.  The Partnership may redeem some or all of the notes at any time on or after November 1, 2009 at certain redemption prices together with accrued and unpaid interest to the date of redemption, and the Partnership may redeem all of the notes at any time prior to November 1, 2009 at a make-whole redemption price.  In addition, prior to November 1, 2007, MarkWest Energy Partners may redeem up to 35% of the aggregate principal amount of the notes with the proceeds of certain equity offerings at a certain redemption price.  If the Partnership sells certain assets and does not reinvest the proceeds or repay senior indebtedness, or if it experiences specific kinds of changes in control, it must offer to repurchase notes at a specified price.  Each of MarkWest Energy Partner’s existing subsidiaries, other than MarkWest Energy Finance Corporation, has guaranteed the notes initially and so long as such subsidiary guarantees any of the Partnership’s other debt.  Not all of the Partnership’s future subsidiaries will have to become guarantors.  The notes are senior unsecured obligations with equal in right of payment with all of the existing and future senior debt.  These notes are senior in right of payment to all of the Partnership’s future subordinated debt but effectively junior in right of payment to its secured debt to the extent of the assets securing the debt, including its obligations in respect to its bank credit facility.  The proceeds from these notes were used to pay down the outstanding debt under the Partnership’s credit facility.

On October 25, 2004, the Company entered into a $25.0 million senior credit facility with a term of one year.  The $25.0 million revolving facility has a variable interest rate based on the base rate, which is equal to the higher of a) the Federal Funds Rate plus ½ of 1%, and b) the rate of interest in effect for such day as publicly announced from time to time by the Administrative Agent as its prime rate, plus the applicable rate, which is based on a utilization percentage.  The amount available to be drawn under the credit facility is based upon the amount of the Company’s eligible accounts receivable and inventory balance.  In addition, the Company is required to pay a commitment fee equal to the applicable rate times the actual daily amount by which the aggregate commitment exceeds the sum of (i) the outstanding amount of loans plus (ii) the outstanding amount of its letter of credit obligations.  Substantially all of the Company’s assets and those of its subsidiaries (other than excluded MarkWest Energy Partners entities) are pledged to the lender to secure the repayment of the outstanding borrowings under the credit facility.  The proceeds from this borrowing will be used to finance inventory and accounts receivable, issue

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

17

letters of credit and pay fees, costs and expenses related to this agreement.  As of October 31, 2004, the Company had no outstanding borrowings.

10.Recovery of Receivable

During the fourth quarter of 2001, Enron Corporation and its subsidiaries (“Enron”) filed for bankruptcy protection.  In response to this filing, MarkWest Hydrocarbon terminated all derivative contracts where Enron was the counterparty.  As a result, in 2001 the Company wrote off $1.1 million of fair value derivative instrument assets related to its cash flow hedges offset by $0.1 million of fair value derivative instrument liabilities related to its fair value hedges.  In the third quarter of 2004, the Company sold its claim to these assets for $0.8 million.  As a result, the Company recorded $0.8 million as other income in the third quarter of 2004.

11.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 nine months ended September 30, 2004 and 2003. Segment operating income (loss) includes total revenues less purchased product costs, facility expenses, depreciation, amortization of intangible assets and accretion of asset retirement obligation. 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.

				MarkWest
				Energy		Eliminating
	Marketing			Partners		Entries			Total
	(in thousands)
Three Months Ended September 30, 2004(1):
Revenues from external customers	$	58,919		$	62,592	$	—		$	121,511
Intersegment revenues	$	121		$	15,250	$	(15,371	)	$	—
Segment operating income (loss)	$	(28	)	$	12,009	$	—		$	11,981
Total segment assets	$	93,828		$	480,345	$	(19,427	)	$	554,746
Three Months Ended September 30, 2003(1):
Revenues from external customers	$	29,831		$	18,888	$	—		$	48,719
Intersegment revenues	$	313		$	12,524	$	(12,837	)	$	—
Segment operating income (loss)	$	(9,198	)	$	5,480	$	—		$	(3,718	)
Total segment assets	$	159,588		$	142,290	$	(14,176	)	$	287,702

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

18

				MarkWest
				Energy		Eliminating
	Marketing			Partners		Entries			Total
	(in thousands)
Nine Months Ended September 30, 2004(1):
Revenues from external customers	$	140,258		$	163,977	$	—		$	304,235
Intersegment revenues	$	460		$	43,349	$	(43,809	)	$	—
Segment operating income (loss)	$	(2,499	)	$	25,139	$	—		$	22,640
Total segment assets	$	93,828		$	480,345	$	(19,427	)	$	554,746
Nine Months Ended September 30, 2003(1):
Revenues from external customers	$	105,450		$	42,741	$	—		$	148,191
Intersegment revenues	$	758		$	36,000	$	(36,758	)	$	—
Segment operating income (loss)	$	(20,896	)	$	13,285	$	—		$	(7,611	)
Total segment assets	$	159,630		$	142,248	$	(14,176	)	$	287,702

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 September 30,						Nine Months Ended September 30,
	2004 (1)			2003 (1)			2004 (1)			2003 (1)
	(in thousands)
Segment operating income (loss)	$	11,981		$	(3,718	)	$	22,640		$	(7,611	)
Selling, general and administrative expenses	(7,252		)	(3,707		)	(17,637		)	(10,097		)
Loss on sale of terminals	—			(55		)	—			(55		)
Interest expense, net	(3,559		)	(658		)	(5,256		)	(2,906		)
Amortization of deferred financing costs	(3,120		)	(457		)	(3,734		)	(1,270		)
Dividend income	86			—			169			—
Other income	553			31			547			15
Loss from continuing operations before non-controlling interest in net income of consolidated subsidiary and income taxes	$	(1,311	)	$	(8,564	)	$	(3,271	)	$	(21,924	)

(1)  As Restated.  See Note 16.

12.Related Party Transactions

William P. Nicoletti, who serves as a member of MarkWest Energy Partners general partner’s board of directors, the general partner of the Partnership, is a member of the board of directors of Star Gas LLC, the general partner of Star Gas Partners, L.P., a retail propane and heating oil master limited partnership.  Star Gas Propane, a subsidiary of Star Gas Partners, L.P., is a significant customer of the Company, and generated revenue of approximately $4.3 million and $16.3 million for the three and nine months ended September 30, 2004, respectively, and $2.0 million and $14.1 million for the three and nine months ended September 30, 2003, respectively.  On September 30, 2004, the Company’s outstanding receivable balance with Star Gas Partners, L.P. was $0.9 million.

Star Gas Partners, L.P.’s heating oil distribution subsidiary, Petro, announced on October 18 that it has been unable to pass along record heating-oil prices to its customers and that its 2004 net income will be substantially below net income for 2003. Through the Company’s discussions with Star Gas Propane, the Company expects to receive full payment for the outstanding receivable balance because Star Gas Propane has its own financing that is not connected to Petro.  As a result, the Company has not reserved for the outstanding receivable balance.  However, the Company will assess doing business with Star Gas Propane and the allowance, if any, for doubtful accounts.  Should there be a change in circumstance, the Company will adjust the reserve accordingly.  In addition, the Company believes that it will be able to sustain the revenue generated from this customer in 2004 and the foreseeable future.

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

19

13.Commitments and Contingencies

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

A summary of the Company’s total contractual cash obligations as of September 30, 2004, is as follows (in thousands):

Type of Obligation	Total Obligation		Due in 2004-2005		Due in 2006-2007		Thereafter
Operating Leases	$	14,050	$	5,600	$	4,448	$	4,002
Debt	197,500		—		—		197,500
Total	$	211,550	$	5,600	$	4,448	$	201,502

14.Recent Accounting Pronouncements

On March 31, 2004, the Emerging Issues Task Force issued EITF No. 03-6 which clarifies the computation of earnings per share in SFAS No. 128, for companies that have issued securities other than common stock that entitle the holder to participate in the company’s declared dividends and earnings.  The consensus states that securities should be included in basic earnings per share calculations when the holder is entitled to receive dividends rather than if the holder is entitled to receive earnings or value upon redemption of the securities or liquidation of assets.  The effective date of EITF No. 03-6 is the first fiscal period beginning after March 31, 2004, and requires restatement of prior period information.  Implementation of the consensus had no effect on the financial results and resulted in no change in earnings per share for the three month and nine month periods ended September 30, 2004, and 2003.

15.Subsequent Event

On November 8, 2004, a leak occurred in a natural gas liquids (NGLs) line owned by Equitable Supply, and leased and operated by MarkWest Energy Appalachia, LLC, a subsidiary of MarkWest Energy Partners.  The 4-inch pipeline transports NGLs from the Partnership’s Maytown gas processing plant to its Siloam fractionator.  A subsequent ignition and fire from the leaked vapors resulted in property damage to five homes and injuries to some of the residents.  The exact cause of the leak and resulting fire is unknown and is being investigated by MarkWest Energy Partners and the U.S. Department of Transportation Office of Pipeline Safety.  Until repairs are completed and service is resumed on the line, NGLs from the Maytown plant will be trucked directly to the Siloam fractionator, resulting in a minor impact to the Company’s operations.

While investigation into the incident continues, at this time the Partnership believes that it has adequate insurance coverage for property damage and personal injury liability, if any, resulting from the incident.

16.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 nine months and quarterly periods ended September 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 employees and directors from 2002 through 2004.  MarkWest Hydrocarbon had historically recorded its 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

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

20

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 recorded as a reduction in the carrying value of marketable securities, an adjustment to record losses on derivative instruments that do not qualify for hedge accounting treatment and adjustments to accrued property taxes.  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 restate a portion of dividends paid during the nine months ended September 30, 2004 from retained earnings to additional paid in capital for the amount of dividends distributed in excess of accumulated earnings.

Cash was also adjusted primarily as a result of reclassifying amounts recorded for the purchase of property, plant and equipment, intangible assets and accrued property tax relating to an acquisition, from cash to those respective accounts.  Initially, the purchase of those assets were recorded to a cash clearing account until the purchase price was settled in the fourth quarter of 2004. The Company has also restated restricted marketable securities from restricted cash.

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 the Form 10-Q/A has been restated to give retroactive effect to the stock dividend paid.

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 September 30, 2004 and December 31, 2003 as previously reported and as restated, and the consolidated statements of income for the three months and nine months ended September 30, 2004 and 2003 as previously reported and as restated and the consolidated statement of cash flows for the nine months ended September 30, 2004 and 2003 as previously reported and as restated.  The tables also reflect the amounts reported for changes in stockholders’ equity for the nine months ended September 30, 2004, as previously reported and as restated.  The impact of these restatements was to decrease net income per basic and diluted share by $0.23 for the three months ended September 30, 2004.  In addition, the impact of these restatements was to decrease net income per basic and diluted share by $0.54 and $0.04 for the nine months ended September 30, 2004 and 2003, respectively.

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

21

Balance Sheet Amounts:

	September 30, 2004
	As Previously Reported			Adjustment			As Restated
	(in thousands, except share and per share data)
ASSETS
Current assets:
Cash and cash equivalents	$	22,258		$	(611	)(1)	$	21,647
Restricted cash	3,050			(2,500		)(2)	550
Marketable securities	12,062			144		(3)	12,206
Restricted marketable securities	—			2,500		(2)	2,500
Receivables, net	44,162			1,286		(4)	45,448
Inventories	12,450			—			12,450
Prepaid replacement natural gas	13,173			—			13,173
Deferred income taxes	968			(900		)(5)	68
Other current assets	3,645			13		(6)	3,658
Total current assets	111,768			(68		)	111,700
Property, plant and equipment	324,144			(181		)(7)	323,963
Less: accumulated depreciation, depletion and amortization	(55,629		)	662		(8)	(54,967		)
Total property, plant and equipment, net	268,515			481			268,996
Other assets:
Intangibles and other assets, net	165,857			602		(9)	166,459
Deferred financing costs, net	7,184			—			7,184
Investment in and advances to equity investee	200			—			200
Notes receivable from officers	207			—			207
Other assets	42			(42		)(10)	—
Total other assets	173,490			560			174,050
Total assets	$	553,773		$	973		$	554,746
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	45,044		$	1,659	(11)	$	46,703
Accrued liabilities	20,962			2,347		(12)	23,309
Fair value of derivative instruments	2,747			—			2,747
Total current liabilities	68,753			4,006			72,759
Long-term debt	197,500			—			197,500
Deferred income taxes	8,434			(2,047		)(13)	6,387
Other long-term liabilities	502			4,278		(14)	4,780
Non-controlling interest in consolidated subsidiary	231,558			(1,107		)(15)	230,451
Commitments and contingencies (Note 13)
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, 10,817,967 shares issued	108			—			108
Additional paid-in capital	52,399			(630		)(16)	51,769
Accumulated deficit	(3,457		)	(4,882		)(17)	(8,339		)
Accumulated other comprehensive loss, net of tax	(1,585		)	1,355		(18)	(230		)
Treasury stock at cost, 65,999 shares	(439		)	—			(439		)
Total stockholders’ equity	47,026			(4,157		)	42,869
Total liabilities and stockholders’ equity	$	553,773		$	973		$	554,746

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

22

	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		)(19)	—
Restricted marketable securities	—			2,500		(19)	2,500
Receivables, net	30,750			(840		)(20)	29,910
Inventories	4,815			733		(21)	5,548
Prepaid replacement natural gas	5,940			—			5,940
Deferred income taxes	603			(69		)(22)	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, amortization and impairment	(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		)(23)	84
Deferred financing costs, net	—			3,747		(23)	3,747
Deferred offering costs and other, net	1,037			(42		)(24)	995
Investment in and advances to equity investee	250			—			250
Notes receivable from officers	217			—			217
Total other assets	5,335			(42		)	5,293
Total assets	$	280,713		$	(218	)	$	280,495
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable (including related party payables of $51)	$	24,052		$	—		$	24,052
Accrued liabilities	16,751			(240		)(25)	16,511
Fair value of derivative instruments	1,769			—			1,769
Total current liabilities	42,572			(240		)	42,332
Long-term debt	126,200			—			126,200
Deferred income taxes	6,346			(752		)(26)	5,594
Fair value of derivative instruments	125			—			125
Other long-term liabilities	504			2,397		(27)	2,901
Non-controlling interest in consolidated subsidiary	52,782			(353		)(28)	52,429
Commitments and contingencies (Note 13)
Stockholders’ equity:
Preferred stock, par value $0.01, 5,000,000 shares authorized, no shares outstanding	—			—			—
Common stock, par value $0.01, 20,000,000 shares authorized, 10,601,775 shares issued	106			—			106
Additional paid-in capital	50,705			—			50,705
Retained earnings	3,676			(1,270		)	2,406
Accumulated other comprehensive loss, net of tax	(1,793		)	—			(1,793		)
Treasury stock at cost, 75,930 shares	(510		)	—			(510		)
Total stockholders’ equity	52,184			(1,270		)	50,914
Total liabilities and stockholders’ equity	$	280,713		$	(218	)	$	280,495

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

23

Income Statement Amounts:

	Three Months Ended September 30, 2004
	As Previously Reported			Adjustments			As Restated
	(in thousands, except per share data)
Revenues	$	122,938		$	(1,427	)(29)	$	121,511
Operating expenses:
Purchased product costs	95,128			81		(30)	95,209
Facility expenses	8,281			117		(31)	8,398
Selling, general and administrative expenses	5,966			1,286		(32)	7,252
Depreciation	5,975			(1,465		)(33)	4,510
Amortization of intangible assets	—			1,400		(34)	1,400
Accretion of asset retirement obligation	—			13		(35)	13
Total operating expenses	115,350			1,432			116,782
Income from operations	7,588			(2,859		)	4,729
Other income (expense):
Interest expense, net	(7,002		)	3,443		(36)	(3,559		)
Amortization of deferred financing costs (a component of interest expense)	—			(3,120		)(37)	(3,120		)
Dividend income	—			86		(38)	86
Other income	553			—			553
Income (loss) from continuing operations before non-controlling interest in net income of consolidated subsidiary income taxes	1,139			(2,450		)	(1,311		)
Provision (benefit) for income taxes:
Current	(2,744		)	2,783			39
Deferred	3,104			(2,992		)	112
Provision (benefit) for income taxes	360			(209		)(39)	151
Non-controlling interest in net income of consolidated subsidiary	(210		)	(294		)(40)	(504		)
Net income (loss)	$	569		$	(2,535	)	$	(1,966	)
Net income (loss) per share:
Basic	$	0.05		$	(0.23	)	$	(0.18	)
Diluted	$	0.05		$	(0.23	)	$	(0.18	)
Weighted average number of outstanding shares of common stock:
Basic	10,736						10,736
Diluted	10,800						10,800
Cash dividend per common share	$	0.023					$	0.023

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

24

	Three Months Ended September 30, 2003
	As Previously Reported			Adjustments			As Restated
	(in thousands, except per share data)
Revenues	$	48,228		$	491	(41)	$	48,719
Operating expenses:
Purchased product costs	44,521			—			44,521
Facility expenses	5,204			241		(42)	5,445
Selling, general and administrative expenses	3,549			158		(43)	3,707
Depreciation	2,220			251		(44)	2,471
Loss on sale of terminals	55			—			55
Total operating expenses	55,549			650			56,199
Loss from operations	(7,321		)	(159		)	(7,480		)
Other income (expense):
Interest expense, net	(1,115		)	457		(45)	(658		)
Amortization of deferred financing costs (a component of interest expense)	—			(457		)(45)	(457		)
Other income	31			—			31
Loss from continuing operations before income taxes	(8,405		)	(159		)	(8,564		)
Provision (benefit) for income taxes:
Current	—			(3,885		)	(3,885		)
Deferred	(3,701		)	3,870			169
Provision (benefit) for income taxes	(3,701		)	(15		)(46)	(3,716		)
Non-controlling interest in net income of consolidated subsidiary	(1,607		)	88		(47)	(1,519		)
Loss from continuing operations	(6,311		)	(56		)	(6,367		)
Discontinued operations:
Loss from discontinued exploration and production operations (net of income taxes of $(303))	(1,260		)	(2		)	(1,262		)
Gain from disposal of discontinued exploration and production operations (less applicable income taxes of $2,750)	593			—			593
Loss from discontinued operations	(667		)	(2		)(48)	(669		)
Net loss	$	(6,978	)	$	(58	)	$	(7,036	)
Loss from continuing operations per share:
Basic	$	(0.61	)	$	(0.01	)	$	(0.62	)
Diluted	$	(0.61	)	$	(0.01	)	$	(0.62	)
Net loss per share:
Basic	$	(0.68	)	$	—		$	(0.68	)
Diluted	$	(0.68	)	$	—		$	(0.68	)
Weighted average number of outstanding shares of common stock:
Basic	10,316						10,316
Diluted	10,340						10,340
Cash dividend per common share	$	—					$	—

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

25

	Nine Months Ended September 30, 2004
	As Previously Reported			Adjustments			As Restated
	(in thousands, except per share data)
Revenues	$	304,422		$	(187	)(49)	$	304,235
Operating expenses:
Purchased product costs	245,715			2,245		(50)	247,960
Facility expenses	20,147			312		(51)	20,459
Selling, general and administrative expenses	14,712			2,925		(52)	17,637
Depreciation	13,385			(1,690		)(53)	11,695
Amortization of intangible assets	—			1,468		(54)	1,468
Accretion of asset retirement obligation	—			13		(55)	13
Total operating expenses	293,959			5,273			299,232
Income from operations	10,463			(5,460		)	5,003
Other income (expense):
Interest expense, net	(9,452		)	4,196		(56)	(5,256		)
Amortization of deferred financing costs (a component of interest expense)	—			(3,734		)(57)	(3,734		)
Dividend income	—			169		(58)	169
Other income	585			(36		)(59)	547
Loss from continuing operations before non-controlling interest in net income of consolidated subsidiary and income taxes	1,596			(4,867		)	(3,271		)
Provision (benefit) for income taxes:
Current	(2,744		)	2,895			151
Deferred	1,733			(1,295		)	438
Benefit for income taxes	(1,011		)	1,600		(60)	589
Non-controlling interest in net income of consolidated subsidiary	(4,452		)	693		(61)	(3,759		)
Net loss	$	(1,845	)	$	(5,774	)	$	(7,619	)
Net loss per share:
Basic	$	(0.17	)	$	(0.54	)	$	(0.71	)
Diluted	$	(0.17	)	$	(0.54	)	$	(0.71	)
Weighted average number of outstanding shares of common stock:
Basic	10,665						10,665
Diluted	10,715						10,715
Cash dividend per common share	$	0.50					$	0.50

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

26

	Nine Months Ended September 30, 2003
	As Previously Reported			Adjustments			As Restated
	(in thousands, except per share data)
Revenues	$	146,767		$	1,424	(62)	$	148,191
Operating expenses:
Purchased product costs	134,881			—			134,881
Facility expenses	13,983			767		(63)	14,750
Selling, general and administrative expenses	9,462			635		(64)	10,097
Depreciation	5,791			380		(65)	6,171
Loss on sale of terminals	55			—			55
Total operating expenses	164,172			1,782			165,954
Loss from operations	(17,405		)	(358		)	(17,763		)
Other income (expense):
Interest expense, net	(4,176		)	1,270		(66)	(2,906		)
Amortization of deferred financing costs (a component of interest expense)	—			(1,270		)(66)	(1,270		)
Gain on sale to related party	188			(188		)(67)	—
Other income	15			—			15
Loss from continuing operations before non-controlling interest in net income of consolidated subsidiary and income taxes	(21,378		)	(546		)	(21,924		)
Provision (benefit) for income taxes:
Current	—			(9,676		)	(9,676		)
Deferred	(9,058		)	9,479			421
Provision (benefit) for income taxes	(9,058		)	(197		)(68)	(9,255		)
Non-controlling interest in net income of consolidated subsidiary	(3,342		)	154		(69)	(3,188		)
Loss from continuing operations	(15,662		)	(195		)	(15,857		)
Discontinued operations:
Income from discontinued exploration and production operations (net of income taxes of $625)	2,788			(182		)	2,606
Gain from disposal of discontinued exploration and production operations (less applicable income taxes of $8,173)	14,862			—			14,862
Income from discontinued operations	17,650			(182		)(70)	17,468
Income before cumulative effect of accounting change	1,988			(377		)	1,611
Cumulative effect of change in accounting for asset retirement obligations, net of tax	(29		)	—			(29		)
Net income	$	1,959		$	(377	)	$	1,582
Loss from continuing operations per share:
Basic	$	(1.52	)	$	(0.02	)	$	(1.54	)
Diluted	$	(1.52	)	$	(0.02	)	$	(1.54	)
Net income per share:
Basic	$	0.19		$	(0.04	)	$	0.15
Diluted	$	0.19		$	(0.04	)	$	0.15
Weighted average number of outstanding shares of common stock:
Basic	10,300						10,300
Diluted	10,318						10,318
Cash dividend per common share	$	—					$	—

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

27

Cash Flow Amounts:

	Nine Months Ended September 30, 2004
	As Previously Reported			Adjustments			As Restated
	(in thousands)
Cash flows from operating activities:
Net loss	$	(1,845	)	$	(5,774	)	$	(7,619	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and depletion	12,018			(324		)	11,694
Amortization of deferred financing costs	3,836			(1,571		)	2,265
Write down of deferred financing costs	—			1,469			1,469
Amortization of intangible assets	1,366			102			1,468
Stock option compensation expense	—			1,531			1,531
Restricted unit compensation expense	732			—			732
Participation Plan compensation expense	—			1,205			1,205
Contribution of treasury shares to 401(k) benefit plan	—			107			107
Equity in losses of investee	50			—			50
Loss from sale of property, plant and equipment	145			—			145
Non-controlling interest in net income of consolidated subsidiary	4,452			(693		)	3,759
Unrealized losses on derivative instruments	732			—			732
Deferred income taxes	1,732			(1,294		)	438
Other	(51		)	—			(51		)
Changes in operating assets and liabilities:
Increase in receivables	(13,122		)	(2,126		)	(15,248		)
Increase in inventories	(7,635		)	733			(6,902		)
Increase in prepaid replacement natural gas	(7,233		)	—			(7,233		)
Increase in other current assets	(3,142		)	9			(3,133		)
Increase in accounts payable and accrued liabilities	25,424			4,690			30,114
Decrease in other long-term liabilities	(2		)	—			(2		)
Net cash flow provided by operating activities	17,457			(1,936		)(71)	15,521
Cash flows from investing activities:
Increase in restricted cash	(550		)	—			(550		)
Purchase of marketable securities	(11,776		)	(144		)	(11,920		)
East Texas System acquisition	(240,606		)	—			(240,606		)
Hobbs Lateral acquisition	(2,275		)	—			(2,275		)
Capital expenditures	(13,798		)	1,130			(12,668		)
Proceeds from sale of assets	206			—			206
Increase in other contracts	(3,250		)	—			(3,250		)
Proceeds on financing lease receivable	—			133			133
Proceeds from sale of assets to related parties	10			(10		)	—
Net cash used in investing activities	(272,039		)	1,109		(72)	(270,930		)

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

28

	Nine Months Ended September 30, 2004
	As Previously Reported			Adjustments			As Restated
	(in thousands)
Cash flows from financing activities:
Proceeds from long-term debt	215,600			—			215,600
Repayment of long-term debt	(144,300		)	—			(144,300		)
Debt issuance costs	(7,193		)	—			(7,193		)
Proceeds from public offerings of MarkWest Energy Partners’ common units, net	140,014			—			140,014
Proceeds from private placement of MarkWest Energy Partners’ common units, net	44,139			—			44,139
Distributions to MarkWest Energy Partners’ unitholders	(9,603		)	166			(9,437		)
Acquisitions and dispositions of MarkWest Energy GP general partnership interests and MarkWest Energy Partners subordinated units to related parties	(157		)	157			—
Exercise of stock options	1,413			—			1,413
Repurchase of treasury shares	71			(107		)	(36		)
Payment of dividends	(5,288		)	—			(5,288		)
Net cash provided by financing activities	234,696			216		(73)	234,912
Effect of exchange rate on changes in cash	—			—			—
Net decrease in cash and cash equivalents	(19,886		)	(611		)	(20,497		)
Cash and cash equivalents at beginning of period	42,144			—			42,144
Cash and cash equivalents at end of period	$	22,258		$	(611	)	$	21,647
Supplemental cash flow information:
Cash paid for interest, net of amounts capitalized	$	4,607		$	—		$	4,607
Construction projects in progress obligation	$	—		$	1,094		$	1,094
Property, plant and equipment asset retirement obligation	$	—		$	377		$	377

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

29

	Nine Months Ended September 30, 2003
	As Previously Reported			Adjustments			As Restated
Cash flows from operating activities:
Net income	$	1,959		$	(377	)	$	1,582
Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect of change in accounting	29			—			29
Depreciation, depletion and amortization	18,814			—			18,814
Amortization of deferred financing costs	1,270			—			1,270
Restricted unit compensation expense	554			—			554
Participation Plan compensation expense	—			569			569
Contribution of treasury shares to 401(k) benefit plan	—			190			190
Non-controlling interest in net income of consolidated subsidiary	3,342			(154		)	3,188
Unrealized gains on derivative instruments	(2,207		)	—			(2,207		)
Reclassification of Enron hedges to purchased gas costs	(153		)	—			(153		)
Deferred income taxes	(4,846		)	9,483			4,637
Gain on sale of San Juan Basin properties	(23,035		)	—			(23,035		)
Cost of exiting hedges	(3,440		)	—			(3,440		)
Other	427			—			427
Changes in operating assets and liabilities:
Decrease in receivables	15,046			—			15,046
Increase in inventories	(2,540		)	—			(2,540		)
Increase in prepaid replacement natural gas	(3,941		)	—			(3,941		)
Increase (decrease) in accounts payable and accrued liabilities	309			(9,375		)	(9,066		)
Increase in other long-term liabilities	1,565			—			1,565
Net cash flow provided by operating activities	3,153			336		(74)	3,489
Cash flows from investing activities:
Pinnacle acquisition, net of cash acquired	(38,238		)	—			(38,238		)
Lubbock pipeline acquisition	(12,222		)	—			(12,222		)
Proceeds from sale of San Juan Basin properties, net of disposal costs	55,007			—			55,007
Capital expenditures	(24,968		)	—			(24,968		)
Proceeds from sales of terminals	2,438			—			2,438
Proceeds from sale of assets to related parties	212			(212		)	—
Net cash used in investing activities	(17,771		)	(212		)(75)	(17,983		)

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

30

	Nine Months Ended September 30, 2003
	As Previously Reported			Adjustments			As Restated
Cash flows from financing activities:
Proceeds from long-term debt	86,835			—			86,835
Repayment of long-term debt	(75,130		)	—			(75,130		)
Debt issuance costs	(811		)	—			(811		)
Proceeds from private placement of MarkWest Energy Partners’ common units, net	9,764			—			9,764
Distributions to MarkWest Energy Partners’ unitholders	(5,173		)	66			(5,107		)
Acquisitions and dispositions of MarkWest Energy GP general partnership interests and MarkWest Energy Partners subordinated units to related parties	17			—			17
Exercise of stock options	333			—			333
Repurchase of treasury shares	(158		)	(190		)	(348		)
Net cash provided by financing activities	15,677			(124		)(76)	15,553
Effect of exchange rate on changes in cash	111			—			111
Net increase in cash and cash equivalents	1,170			—			1,170
Cash and cash equivalents at beginning of period	6,410			—			6,410
Cash and cash equivalents at end of period	$	7,580		$	—		$	7,580
Supplemental cash flow information:
Cash paid for interest	$	1,201		$	273	(77)	$	1,474

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

31

Changes in Stockholders’ Equity Amounts:

	Shares of Common Stock	Shares of Treasury Stock		Common Stock		Additional Paid-In Capital			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total Stockholders’ Equity
	(in thousands)
Balance, as previously reported, September 30, 2004	9,835	(66	)	$	98	$	52,409		$	(3,457	)	$	(1,585	)	$	(439	)	$	47,026
Stock dividend	983	—		10		(10		)	—			—			—			—
Reclassification of dividends paid	—	—		—		(2,162		)	2,162			—			—			—
Modification of stock options	—	—		—		1,531			—			—			—			1,531
Recognition of losses on derivative instruments that do not qualify for hedge accounting treatment	—	—		—		—			—			1,355			—			1,355
Restatement adjustment to net income for the year ended December 31, 2002	—	—		—		—			(213		)	—			—			(213		)
Restatement adjustments to net income for the year ended December 31, 2003	—	—		—		—			(1,057		)	—			—			(1,057		)
Restatement of results of operations for the nine months ended September 30, 2004	—	—		—		—			(5,774		)	—			—			(5,774		)
Balance, as restated, September 30, 2004	10,818	(66	)	$	108	$	51,769		$	(8,339	)	$	(230	)	$	(439	)	$	42,869

September 30, 2004 Balance Sheet

(1)Cash was decreased by $0.6 million primarily as a result of restating amounts recorded for the purchase of property, plant and equipment of $0.2 million, intangible assets of $0.5 million and accrued property tax of $0.1 million relating to the East Texas acquisition from cash to those respective accounts.  Initially, the purchase of those assets were recorded to a cash clearing account until the purchase price was settled in the fourth quarter of 2004.

(2)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.

(3)Marketable securities was increased by $0.1 million to properly record dividends received as dividend income.  Previously, the dividends were incorrectly recorded as a reduction to the carrying value of marketable securities.

(4)Receivables net, were increased by $1.3 million to correct the amounts recorded for accrued revenue.

(5)The current portion deferred income tax asset was decreased by $0.9 million to reflect the tax effect of the restatement adjustments.

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

32

(6)Other assets were increased by $0.01 million primarily due to restating a prepayment of maintenance fees from construction in-progress to prepaid expenses.

(7)Property, plant and equipment were decreased by $0.2 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 $0.3 million to record repair expense improperly capitalized as property, plant and equipment.

•an increase of $0.4 million to record an asset retirement obligation assumed in our East Texas acquisition.  The Company identified certain land leases in East Texas that contain provisions requiring the Partnership to return the land to its original condition upon the termination of the lease.

•an increase of $0.3 million to capitalize interest on major construction projects in progress.

•an increase of $0.2 million to restate amounts recorded for the purchase of property, plant and equipment from the East Texas acquisition from a cash clearing account.

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

(8)Accumulated depreciation was reduced by $0.7 million to reverse the depreciation previously recorded on the Blackhawk pipeline.

(9)Intangible assets were increased by $0.6 million primarily as a result of the following restatement adjustments:

•an increase of $0.1 million to record an intangible asset relating to a customer contract acquired as a part of the Pinnacle acquisition.

•an increase of $0.5 million to restate the amounts recorded for the purchase of intangible assets from the East Texas acquisition from a cash clearing account.

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

(11)Accounts payable were increased by $1.7 million to correct amounts recorded for accrued product costs.

(12)Accrued liabilities were increased by $2.3 million primarily as a result of the following restatement adjustments:

•an increase of $2.8 million to reflect the current tax effect of the restatement adjustments.

•a decrease of $0.3 million to correct amounts recorded for accrued product costs.

•a decrease of $0.3 million to reverse deferred income previously recorded under the Participation Plan as a result of accounting for the 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.

•an increase of $0.1 million to restate the amounts recorded for accrued property taxes from the East Texas acquisition from a cash clearing account.

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

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

33

(13)The non-current portion of deferred income tax liabilities decreased by $2.0 million primarily as a result of the following restatement adjustments to reflect the tax effect of the restatement adjustments.

(14)Other long-term liabilities were increased by $4.3 million primarily as a result of the following restatement adjustments:

•an increase of $3.9 million to reflect compensation expense accrued under the Participation Plan.

•an increase of $0.4 million to record an asset retirement obligation assumed in our East Texas acquisition.  We identified certain land leases in East Texas that contain provisions requiring the Partnership to return the land to its original condition upon the termination of the lease.

(15)Non-controlling interest in consolidated subsidiary were decreased by $1.1 million to reflect the impact of the portion of the restatement adjustments attributable to the effect of 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.

(16)Additional paid-in capital decreased by $0.6 million as a result of the following restatement adjustments:

•a decrease of $2.2 million as a result of restating dividends paid during the nine months ended September 30, 2004 from retained earnings to additional paid in capital for dividends distributed in excess of accumulated earnings.

•an increase of $1.1 million to reflect compensation expense for stock options 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.

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

•an increase of $0.1 million relating to miscellaneous other adjustments.

(17)Accumulated deficit increased by $4.9 million as a result of the following restatement adjustments:

•a decrease of $2.2 million as a result of restating dividends paid from retained earnings to additional paid in capital for dividends distributed in excess of accumulated earnings.

•an 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.

•an increase of $5.8 million to reflect the effect of the restatement adjustments on net income for the nine months ended September 30, 2004.

(18)Accumulated other comprehensive loss, net of tax decreased by $1.4 million as a result of recognizing losses on derivative instruments of $2.2 million that do not qualify for hedge accounting treatment, net of related deferred income taxes of $0.8 million. Previously, the losses had been deferred in accumulated other comprehensive income.

December 31, 2003 Balance Sheet

(19)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.

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

34

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

(21)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.

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

(23)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.

(24)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.

(25)Accrued liabilities were decreased by $0.3 million primarily as a result of the following restatement adjustments:

•an increase 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.

•an increase of $0.02 million to reflect the current tax effect of the restatement adjustments.

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

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

(28)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 September 30, 2004 Income Statement

(29)Revenues for the third quarter of 2004 were decreased by $1.4 million primarily as a result of the following restatement adjustments:

•a decrease of $2.2 million to recognize losses on derivative instruments that did not qualify for hedge accounting.

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

35

•an increase of $0.4 million to correct the amounts recorded for accrued revenue.

•an increase of $0.4 million to restate a pipeline imbalance credit that was improperly recorded as an adjustment of product costs.

(30)Purchased product costs for the third quarter of 2004 were increased by $0.1 million primarily as a result of the following restatement adjustments:

•an increase of $0.4 million to restate a pipeline imbalance credit that was improperly recorded as an adjustment of product costs.

•a decrease of $0.3 million to correct amounts recorded for accrued product costs.

(31)Facility expense increased by $0.1 million to record repair expense improperly capitalized as property, plant and equipment.

(32)Selling, general and administrative expenses increased by $1.3 million for the third quarter of 2004 primarily as a result of the following restatement adjustments:

•an increase of $0.8 million to reflect the compensation expense under the Participation Plan.

•an increase of $0.5 million to record compensation expense for stock options 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.

(33)Depreciation expense for the third quarter of 2004 were decreased by $1.5 million primarily as a result of the following restatement adjustments:

•a decrease of $0.1 million for the reversal of depreciation expense previously recorded on the Blackhawk pipeline.

•a decrease of $1.4 million to reclassify amortization of intangible assets to a separate line item on the consolidated income statement.

(34)Amortization of intangible assets for the third quarter of 2004 were increased by $1.4 million primarily as a result of the following restatement adjustments:

•an increase of $1.4 million to reclassify amortization of intangible assets from depreciation expense to a separate line item on the consolidated income statement.

•increase of $0.03 million to record amortization of a customer contract that was acquired with the Blackhawk pipeline.

(35)Accretion expense increased by $0.01 million to record accretion expense attributed to the asset retirement obligation assumed in our East Texas acquisition.

(36)Interest expense decreased by $3.4 million for the third quarter of 2004 primarily as a result of the following restatement adjustments:

•a decrease of $3.1 million to reclassify amortization of deferred financing costs to a separate line item on the consolidated income statement.

•a decrease of $0.3 million to capitalize interest expense on major construction projects in progress.

(37)Amortization of deferred financing costs increased $3.1 million as a result of reclassify the amortization of deferred financing costs from interest expense to a separate line item on the consolidated income statement.

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

36

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

(39)The provision for income taxes was decreased by $0.2 million to reflect the tax effect of the restatement adjustments.

(40)Non-controlling interest in consolidated subsidiary was increased by $0.3 million to reflect the impact of the portion of the restatement adjustments attributable to the non-controlling interest in MarkWest Energy Partners and to eliminate the effect of the subordinated units and general partner interests owned by employees and directors under the Participation Plan, which were previously accounted for as non-controlling interests.  The Participation Plan is now accounted for as a compensatory arrangement and as a result the Company records a separate liability for the fair value of the subordinated units and general partner interests held by participants in the Plan.

Three months ended September 30, 2003 Income Statement

(41)Revenues increased by $0.5 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.

(42)Facility expenses increased by $0.2 million to reclassify expenses related to the retained exploration and production operations from discontinued operations to continuing operations.

(43)Selling, general and administrative expenses increased by $0.2 million for the third quarter of 2003 to reflect compensation expense under the Participation Plan.

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

(45)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 to a separate line item on the consolidated income statement.

(46)The benefit for income taxes was decreased by $0.02 million to reflect the tax effect of the restatement adjustments.

(47)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 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.

(48)Loss from discontinued exploration and production operations was decreased by less than $0.01 million related to miscellaneous other adjustments.

Nine months ended September 30, 2004 Income Statement

(49)Revenues for the nine months ended September 30, 2004 decreased by $0.2 million primarily as a result of the following restatement adjustments:

•a decrease of $2.2 million to recognize losses on derivative instruments that did not qualify for hedge accounting..

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

37

•an increase of $1.3 million to correct the amounts recorded for accrued revenue.

•an increase of $0.9 million to restate a pipeline imbalance credit that was improperly recorded as an adjustment of 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 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.

(50)Purchasedproduct costs for the nine months ended September 30, 2004 increased by $2.2 million primarily as a result of the following restatement adjustments:

•an increase of $1.4 million to correct amounts recorded for accrued product costs.

•an increase of $0.9 million to restate a pipeline imbalance credit that was improperly recorded as an adjustment of product cost to revenue.

(51)                        �� Facility costs for the nine months ended September 30, 2004 were increased by $0.3 million primarily as a result of the following restatement adjustments:

•a decrease of $0.08 million to adjust the property tax accrual from estimate to actual taxes paid.

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

•an increase of $0.3 million to record repair expense improperly capitalized as property, plant and equipment.

(52)Selling, general and administrative expenses increased by $2.9 million for the nine months ended September 30, 2004 primarily as a result of the following restatement adjustments:

•an increase of $1.1 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 reflect compensation as a result of the modification of the provisions of stock options for two employees who terminated their employment with the Company but who continued to serve on the Company’s Board of Directors.

•an increase of $1.4 million to reflect compensation expense under the Participation Plan

(53)Depreciation expense for the nine months ended September 30, 2004 were decreased by $1.7 million primarily as a result of the following restatement adjustments:

•a decrease of $1.4 million to reclassify amortization of intangible assets to a separate line item on the consolidated income statement.

•a decrease of $0.3 million for the reversal of depreciation expense previously recorded on the Blackhawk pipeline.

(54)Amortization of intangible assets for the nine months ended September 30, 2004 were increased by $1.5 million primarily as a result of the following restatement adjustments:

•an increase of $1.4 million to reclassify amortization of intangible assets from depreciation expense to a separate line item on the consolidated income statement.

•an increase of $0.1 million to record amortization of a customer contract that was acquired with the Blackhawk pipeline.

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

38

(55)Accretion expense increased by $0.01 million to record accretion expense attributed to our East Texas segment asset retirement obligation.

(56)Interest expense decreased by $4.2 million for the nine months ended September 30, 2004 primarily as a result of the following restatement adjustments:

•a decrease of $3.7 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 $0.4 million to capitalize of interest expense on major construction projects in-progress.

(57)Amortization of deferred financing costs increased $3.7 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.

(58)Dividend income increased by $0.2 million as a result of recording dividends received on marketable securities as dividend income.  Previously, the dividends were improperly recorded as a reduction of the carrying value of marketable securities.

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

(60)The benefit for income taxes was decreased by $1.6 million to reflect the tax effect of the restatement adjustments.

(61)Non-controlling interest in consolidated subsidiary was increased by $0.7 million to reflect the impact of the portion of the restatement adjustments attributable to the non-controlling interest in MarkWest Energy Partners and to eliminate the effect of the subordinated units and general partner interests owned by employees and directors under the Participation Plan, which were previously accounted for as non-controlling interests.  The Participation Plan is now accounted for as a compensatory arrangement and as a result the Company records a separate liability for the fair value of the subordinated units and general partner interests held by participants in the Plan.

Nine months ended September 30, 2003 Income Statement

(62)Revenues increased by $1.4 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.

(63)Facility expenses increased by $0.8 million to reclassify expenses related to the retained exploration and production operations from discontinued operations to continuing operations.

(64)Selling, general and administrative expense increased by $0.6 million to reflect compensation expense under the Participation Plan.

(65)Depreciation expense increased by $0.4 million to reclassify expenses related to the retained exploration and production operations from discontinued operations to continuing operations.

(66)Interest expense decreased by $1.3 million and amortization of deferred financing costs increased by a corresponding amount as a result of reclassifying amortization of deferred financing costs to a separate line item on the consolidated income statement.

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

39

(67)Gain on sale to related party was decreased by $0.2 million to eliminate 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.

(68)The benefit for income taxes was increased by $0.2 million to reflect the tax effect of the restatement adjustments.

(69)Non-controlling interest in consolidated subsidiary was increased by $0.2 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 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.

(70)Income from discontinued exploration and production operations (net of income tax provision of $0.6 million) was decreased by $0.2 million to reclassify income related to the retained exploration and production operations from discontinued operations to continued operations.

Nine months ended September 30, 2004 Cash Flow Statement

(71)Net cash provided by operating activities decreased by $1.9 million, after an adjustment to cash of $0.6 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 as income, to reflect the repurchase and proceeds from 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 and to reflect distributions paid under the Participation Plan as an operating activity.  Cash was adjusted by $0.6 million primarily as a result of reclassifying amounts recorded for the purchase of property, plant and equipment of $0.2 million, intangible assets of $0.5 million and accrued property tax of $0.1 million relating to the East Texas acquisition from cash to those respective accounts.

(72)Net cash used in investing activities decreased by $1.1 million to reflect proceeds from 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 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 record repair expense improperly capitalized as property, plant and equipment and to reflect dividends received on marketable securities as income.

(73)Net cash used in financing activities decreased by $0.2 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 distributions paid under the Participation Plan as an operating activity.

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

40

Nine months ended September 30, 2003 Cash Flow Statement

(74)Net cash provided by operating activities increased by $0.3 million to reflect proceeds from 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 distributions paid under the Participation Plan as an operating activity.

(75)Net cash used in investing activities increased by $0.2 million to reflect proceeds from 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.

(76)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 distributions paid under the Participation Plan as an operating activity.

(77)Cash paid for interest, under supplemental cash flow information, was increased by $0.3 million to properly state cash paid for interest.

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

41

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 attributable to 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 costs improperly capitalized as property, plant and equipment, adjustments to 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, adjustment to reverse transactions improperly recorded as a derivative transaction with hedge accounting treatment 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 nine months ended September 30, 2004 from retained earnings to additional paid in capital for the amount of the dividends distributed in excess of accumulated earnings.

Cash was also adjusted primarily as a result of reclassifying amounts recorded for the purchase of property, plant and equipment, intangible assets and accrued property tax relating to an acquisition, from cash to those respective accounts.  Initially, the purchase of those assets were recorded to a cash clearing account until the purchase price was settled in the fourth quarter of 2004.  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 adjusted 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 16, 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 Nine Months Ended September 30, 2004

We reported a net loss for the three months ended September 30, 2004 of $2.0 million, or $0.18 per diluted share, compared to a net loss of $7.0 million, or $0.68 per diluted share, for the third quarter of 2003.  For the nine months ended September 30, 2004, we reported a net loss of $7.6 million, or $0.71 per diluted share, compared to net income of $1.6 million, or $0.15 per diluted share, for the nine months ended September 30, 2003.

We reported a net loss from continuing operations of $2.0 million, or $0.18 per diluted share, for the three months ended September 30, 2004, compared to a net loss from continuing operations of $6.4 million, or $0.62 per diluted share, for the third quarter of 2003.  For the nine months ended September 30, 2004, we reported a net loss from continuing operations of $7.6 million, or $0.71 per diluted share, compared to a net loss from continuing operations of $15.9million, or $1.54 per diluted share, for the corresponding nine months of 2003.

The improved results for the third quarter of 2004 as compared to the corresponding quarter of 2003 was attributed to the impact of better NGL product margins, the non-recurrence of approximately $1.7 million of crude oil hedging losses and higher NGL product sales volumes.  Other matters benefiting third quarter results included an

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

42

approximate $0.8 million in other income from the sale of the rights to a former Enron receivable that had been previously written-off.

The improved net income from continuing operations for the first nine months of 2004 as compared to the corresponding period of 2003 was also attributed to the factors impacting the third quarter comparisons.  Approximately $8.7 million of the change was attributable to a reduction in our crude oil hedging losses.  The remainder of the change was primarily due to better NGL product margins and due to acquisitions made by MarkWest Energy Partners, late in 2003 and in the third quarter of 2004.

Finally, in September 2004, we entered into several new and amended agreements with one of the largest Appalachia producers, which allow us to significantly reduce our exposure to commodity price risk for approximately 25% of our keep-whole gas volumes.

On October 28, 2004, our board of directors declared a stock dividend of one share of our common stock for each ten shares of common stock held by our common stockholders.  The stock dividend is to be paid on November 19, 2004 to stockholders of record as of the close of business on November 9, 2004.

On the same date, our board of directors declared a cash dividend of $0.05 per share of its common stock held by our common stockholders.  This represented a $0.025 per share increase over the previous quarter’s dividend.  The indicated annual rate is $0.20 per share.  Our board has declared that the dividend is to be paid on December 6, 2004, to the stockholders of record as of the close of business on November 24, 2004.

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 growing the value of our investment in MarkWest Energy Partners, our consolidated subsidiary, and 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 September 30, 2004, our partnership interests consisted of the following:

•2,469,496 subordinated units, representing a 23% 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 Entergy — 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 its exploration and production business segment.

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

43

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 to us in Appalachia in exchange for fees. 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 20% and 21% of its revenues for the three and nine months ended September 30, 2004, respectively, and 24% and 31% of its gross margin for the three and nine months ended September 30, 2003, respectively. We expect we will account for less of MarkWest Energy Partners’ business in the future as MarkWest Energy Partners expands its existing operations, continues to acquire assets and increases 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 manage the business operations of 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 our marketing of NGLs and, to a lesser extent, natural gas.  As compensation for providing processing services to Appalachian producers (we have since outsourced these services to MarkWest Energy Partners as discussed above), 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

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

44

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. However, in September, we entered into several new and amended agreements with one of the largest Appalachia producers, which allow us to significantly reduce our exposure to commodity price risk for approximately 25% of our keep-whole gas volumes. We also 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 nine months ended September 30, 2004 and 2003, we lost approximately $2.7 million and $13.6 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 five 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 the Partnership earns from these contracts is 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 contracts provide for minimum annual payments.  To the extent a sustained decline in commodity prices results in a decline in volumes, however, the Partnership’s revenues from these contracts would be reduced.

•Percent-of-proceeds contracts.  Under percent-of-proceeds contracts, the Partnership 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, MarkWest Energy Partners 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, the Partnership’s 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.  With respect to (1) and (3) above, the gross margins the Partnership realizes under the arrangements described above decrease in periods wherein natural gas prices are falling because these gross margins are based on a percentage of the index price. Conversely, our gross margins increase during periods of rising 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, the Partnership 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 increase relative to the price of natural gas, and its revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs.

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

45

•East Texas System gathering arrangements.  The Partnership gathers volumes on the East Texas System under contracts with fee arrangements that are unique to that system.  These contracts typically contain one or more of the following revenue components:

•Fixed gathering and compression fees.  Typically, gathering and compression fees are comprised of a fixed fee portion in which producers pay a fixed rate per unit to transport their natural gas through the gathering system.  Under the majority of these arrangements, fees are adjusted annually based on the Consumer Price Index.

•Settlement margin.  Typically, the terms of the Partnership’s East Texas System gathering arrangements specify that it is allowed to retain a fixed percentage of the volume gathered to cover the compression fuel charges and deemed line losses.  To the extent the East Texas System is operated more efficiently than provided for by contracted allowances, MarkWest Energy Partners is entitled to retain the difference for its own account.

•Condensate sales.  During the gathering process, thermodynamic forces contribute to changes in operating conditions of the natural gas flowing through the pipeline infrastructure.  As a result, hydrocarbon dew points are reached, causing condensation of hydrocarbons in the high-pressure pipelines.  The East Texas System sells 100% of the condensate collected in the system at a monthly crude-oil based price.

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

At September 30, 2004, the Partnership’s primary exposure to keep-whole contracts was limited to its Arapaho (OK) processing plant and its East Texas (“Carthage”) processing contract with a third party.  At the Arapaho (OK) 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 the Partnership’s 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 regards to the exposure to keep-whole contracts in Carthage, the Partnership has a third party processing agreement to offer percent of liquids (“POL”) processing services to area customers and to process gas for its own account.  Of the total system inlet, approximately 26% of the volume is processed under POL terms and 16% is processed as keep-whole gas.  The remaining 58% is subject to gathering services.  However, the exposure is limited by the Partnership’s ability to reject or recover ethane to help manage the keep-whole processing volumes.

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 September 30, 2004, the Partnership has completed six acquisitions for an aggregate purchase price of approximately $354.3 million. These six acquisitions include:

•the Pinnacle acquisition, which closed on March 28, 2003, for consideration of $39.9 million;

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

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

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

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

•the Hobbs Lateral acquisition, which closed on April 1, 2004, for consideration of $2.3 million; and

•the East Texas System acquisition, which closed on July 30, 2004, for consideration of $240.6 million.

Our historical results of operations for the nine months ended September 30, 2003, save for six months of activity from the Pinnacle acquisition and one month for the Lubbock pipeline acquisition, do not reflect the impact of these acquisitions on our operations. However, our results of operations for the three months ended September 30, 2004, do reflect the impact from the four 2003 acquisitions, three months of operations for the Hobbs Lateral acquisition and two months of results from the East Texas System acquisition.  The results of operations for the nine months ended September 30, 2004, reflect the impact from the four 2003 acquisitions, six months of operations for the Hobbs Lateral acquisition and two months of results from the East Texas acquisition.

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

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Results of Operations

Operating Data

	Three Months Ended September 30,		Nine Months Ended September 30,
	2004	2003	2004	2003
Marketing
NGL product sales (gallons)	42,900,000	40,800,000	130,100,000	125,700,000
Wholesale(1)
NGL product sales (gallons)	10,879,000	—	15,816,000	—
MarkWest Energy Partners
Appalachia:
Natural gas processed for a fee (Mcf/d)(2)	196,000	204,000	201,000	198,000
NGLs fractionated for a fee (Gal/d)	489,000	511,000	474,000	449,000
NGL product sales (gallons)	10,710,000	10,771,000	32,638,000	29,142,000
Michigan:
Natural gas processed for a fee (Mcf/d)	12,300	17,300	12,800	15,900
NGL product sales (gallons)	2,453,000	3,982,000	7,557,000	9,112,000
Crude oil transported for a fee (Bbl/d)(3)	15,100	—	14,800	—
Southwest:
Gathering systems throughput (Mcf/d):
East Texas System(4)	246,600	—	246,600	—
Foss Lake (OK)(5)	63,300	—	60,700	—
Appleby (6)	24,500	25,200	23,300	24,300
Other gathering systems (6)	15,500	21,300	17,700	21,100
Lateral throughput volumes (Mcf/d)(7)	97,200	43,600	83,100	43,600
NGL product sales (gallons):
Arapaho (OK)(8)	12,174,000	—	28,686,000	—
East Texas System(4)	12,268,000	—	12,268,000	—

(1)Wholesale NGL product sales started in February 2004.

(2)Includes throughput from our Kenova, Cobb, and Boldman processing plants.

(3)We acquired our Michigan Crude Pipeline in December 2003.

(4)We acquired our East Texas System in late July 2004.

(5)We acquired our Foss Lake (OK) gathering system in December 2003.

(6)We acquired our Pinnacle gathering systems in late March 2003.

(7)We acquired our Power-Tex Lateral pipeline (a/k/a the Lubbock Pipeline) in September 2003 and our Hobbs lateral pipeline in April 2004.  The Power-Tex and Hobbs Lateral pipelines are the only laterals we own that produce revenue on a per-unit-of-throughput basis.  We receive a flat fee from our other lateral pipelines and, consequently, the throughput data from these three lateral pipelines is excluded from this statistic.

(8)We acquired our Arapaho (OK) processing plant in December 2003.

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

48

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

	Marketing			MarkWest Energy Partners		Eliminating Entries			Total
	(in thousands)
Three Months Ended September 30, 2004(1):
Revenues	$	59,041		$	77,842	$	(15,372	)	$	121,511
Purchased product costs	52,564			51,716		(9,071		)	95,209
Facility expenses	6,202			8,497		(6,301		)	8,398
Depreciation	303			4,207		—			4,510
Amortization of intangible assets	—			1,400		—			1,400
Accretion of asset retirement obligation	—			13		—			13
Total segment operating expenses	59,069			65,833		(15,372		)	109,530
Segment operating income (loss)	$	(28	)	$	12,009	$	—		$	11,981
Three Months Ended September 30, 2003(1):
Revenues	$	30,144		$	31,412	$	(12,837	)	$	48,719
Purchased product costs	32,294			18,510		(6,283		)	44,521
Facility expenses	6,603			5,396		(6,554		)	5,445
Depreciation and amortization	445			2,026		—			2,471
Total segment operating expenses	39,342			25,932		(12,837		)	52,437
Segment operating income (loss)	$	(9,198	)	$	5,480	$	—		$	(3,718	)

	Three Months Ended September 30,
	2004 (1)			2003 (1)
	(in thousands)
Segment operating income (loss)	$	11,981		$	(3,718	)
Selling, general and administrative	(7,252		)	(3,707		)
Loss on sale of terminals	—			(55		)
Interest expense, net	(3,559		)	(658		)
Amortization of deferred financing costs	(3,120		)	(457		)
Dividend income	86			—
Other income	553			31
Loss from continuing operations before non-controlling interest in net income of consolidated subsidiary and income taxes	$	(1,311	)	$	(8,564	)

(1)  As Restated.  See Note 16, Restatement and Reclassifications of Consolidated Financial Statements, to Notes to the Consolidated Financial Statements.

Marketing. Our marketing segment operating loss was $0.03 million for the three months ended September 30, 2004, compared to a loss of $9.2 million for the three months ended September 30, 2003, a change of $9.2 million. The increase is primarily due to higher NGL product sales prices and volumes.

MarkWest Energy Partners. Segment operating income from MarkWest Energy Partners was $12.0 million for the three months ended September 30, 2004, compared to $5.5 million for the three months ended September 30, 2003, an increase of $6.5 million, or 118%. The increase is primarily attributable to the Partnership’s late 2003 and 2004 acquisitions, which contributed $7.3million to operating income.  This was offset in part by an increase of $0.7 million in depreciation expense primarily as a result of accelerating the depreciation of our Michigan gathering pipeline and processing plant by reducing the estimated useful lives of the related assets from twenty years to fifteen years to more closely match expected lives of reserves behind our facilities.

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

49

Selling, general and administrative expenses. Selling, general and administrative expenses were $7.3 million for the three months ended September 30, 2004, compared to $3.7 million for the three months ended September 30, 2003, an increase of $3.6 million, or 97%.  The increase is attributable to additional administrative costs associated with the growth of MarkWest Energy Partners compensation expense associated with the Participation Plan, compensation expense associated with stock options, Sarbanes Oxley compliance expenses, bonus and profit sharing (a bonus was not accrued during the three months ended September 30, 2003) and increases in franchise taxes and insurance.

Interest expense, net.  Interest expense, net was $3.6 million for the three months ended September 30, 2004, compared to $0.7 million for the three months ended September 30, 2003, an increase of $2.9 million, or 414%. The increase was principally attributable to amortization and write off of deferred financing costs from the amendment and restatement of our credit facility in July 2004.  In addition, interest expense increased due to greater debt levels resulting from the financing of our late 2003 and 2004 acquisitions and an increase in our average interest rate.

Loss from discontinued operations. Loss from discontinued operations was $0.7 million for the three months ended September 30, 2003. The amounts recorded for discontinued operations were a result of the sale of substantially all of our U.S. exploration and production business near the end of the second quarter of 2003.

Nine Months Ended September 30, 2004 Compared to the Nine Months Ended September 30, 2003

	Marketing			MarkWest Energy Partners		Eliminating Entries			Total
	(in thousands)
Nine Months Ended September 30, 2004(1):
Revenues	$	140,718		$	207,326	$	(43,809	)	$	304,235
Purchased product costs	124,036			148,940		(25,016		)	247,960
Facility expenses	18,139			21,113		(18,793		)	20,459
Depreciation	1,042			10,653		—			11,695
Amortization of intangible assets	—			1,468		—			1,468
Accretion of asset retirement obligation	—			13		—			13
Total segment operating expenses	143,217			182,187		(43,809		)	281,595
Segment operating income (loss)	$	(2,499	)	$	25,139	$	—		$	22,640
Nine Months Ended September 30, 2003(1):
Revenues	$	106,208		$	78,741	$	(36,758	)	$	148,191
Purchased product costs	108,089			45,325		(18,533		)	134,881
Facility expenses	18,075			14,900		(18,225		)	14,750
Depreciation	940			5,231		—			6,171
Total segment operating expenses	127,104			65,456		(36,758		)	155,802
Segment operating income (loss)	$	(20,896	)	$	13,285	$	—		$	(7,611	)

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

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	Nine Months Ended September 30,
	2004 (1)			2003 (1)
	(in thousands)
Segment operating income (loss)	$	22,640		$	(7,611	)
Selling, general and administrative	(17,637		)	(10,097		)
Loss on sale of terminals	—			(55		)
Interest expense, net	(5,256		)	(2,906		)
Amortization of deferred financing costs	(3,734		)	(1,270		)
Dividend income	169			—
Other income	547			15
Loss from continuing operations before non-controlling interest in net income of consolidated subsidiary and income taxes	$	(3,271	)	$	(21,924	)

(1)  As Restated.  See Note 16, 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 nine months ended September 30, 2004, compared to a loss of $20.9 million for the nine months ended September 30, 2003, a decrease of $18.4 million, or 88%. Approximately $6.5 million of the change was attributable to a reduction in our hedging losses.  The remainder of the change is primarily attributable to higher NGL product sales prices and volumes.

MarkWest Energy Partners. Segment operating income from MarkWest Energy Partners was $25.1 million for the nine months ended September 30, 2004, compared to $13.3 million for the nine months ended September 30, 2003, an increase of $11.8 million, or 89%. The increase is primarily attributable to the Partnership’s late 2003 and 2004 acquisitions, which contributed $13.1million to operating income. This was offset by an increase in depreciation expense primarily as a result of accelerating the depreciation of our Michigan gathering pipeline and processing plant by reducing the estimated useful lives of the related assets from twenty years to fifteen years to more closely match expected lives of reserves behind our facilities.

Selling, general and administrative expenses. Selling, general and administrative expenses were $17.6 million for the nine months ended September 30, 2004, compared to $10.1 million for the nine months ended September 30, 2003, an increase of $7.5 million, or 74%.  The increase is attributable to several factors, including additional administrative costs associated with the growth of MarkWest Energy Partners, through its 2003 and 2004 acquisitions, costs associated with the growth of MarkWest Energy Partners compensation expense associated with the Participation Plan, compensation expense associated with stock options, Sarbanes Oxley compliance expenses, bonus and profit sharing (bonus was not accrued during the nine months ended September 30, 2003) and increases in franchise taxes and insurance.

Interest expense, net.  Interest expense, net was $5.3 million for the nine months ended September 30, 2004, compared to $2.9 million for the nine months ended September 30, 2003, an increase of $2.4 million, or 83%. The increase was primarily attributable to amortization and write off of deferred financing costs from the amendment and restatement of our credit facility in July 2004.  In addition interest expense increased due to heightened debt levels resulting from the financing of our late 2003 and 2004 acquisitions and an increase in our average interest rate.

Income from discontinued operations. Income from discontinued operations was $17.7 million, net of tax, for the nine months ended September 30, 2003. The amounts recorded for discontinued operations were a result of the sale of substantially all of our U.S. exploration and production business near the end the second quarter of 2003.

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

51

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 then existing credit facility in its entirety in December 2003. We also had $33.4 million in unrestricted cash on hand at December 31, 2003, exclusive of MarkWest Energy Partners’ $8.7 million cash on hand. As a result, exclusive of MarkWest Energy Partners’ debt, we had no debt as of September 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 August 19, 2004, we disbursed approximately $0.2 million to pay the second quarterly dividend of $0.025 per share to our common stockholders.  On October 28, 2004, our board of directors declared a stock dividend of one share of our common stock for each ten shares of common stock held by our common stockholders.  The stock dividend is to be paid on November 19, 2004, to the stockholders of record as of the close of business on November 9, 2004. On the same date, our board of directors also announced that it declared a quarterly cash dividend of $0.05 per share of our common stock.  This represented a $0.025 per share increase over the previous quarter’s dividend.  The indicated annual rate is $0.20 per share.  Our Board has declared that the dividend is to be paid on December 6, 2004, to the stockholders of record as of the close of business on November 24, 2004.

Going forward, we expect our primary sources of liquidity to be quarterly distributions received from MarkWest Energy Partners and cash flows generated principally from providing processing services and the associated marketing of natural gas and NGLs.

We own 90% of the general partner of MarkWest Energy Partners.  The general partner of MarkWest Energy Partners owns a 2% general partner interest and all of the incentive distribution rights in MarkWest Energy Partners.  The incentive distribution rights entitle us to receive, through the general partner, an increasing percentage of cash distributed by the Partnership upon attainment of target distribution levels. Specifically, incentive distribution rights entitle us to receive 13% of the incremental cash distributed in a quarter greater than $0.55 per unit and up to and including $0.625 per unit for that quarter; 23% of the incremental cash distributed in a quarter greater than $0.625 per unit and up to and including $0.75 per unit for that quarter; and 48% of the incremental cash distributed in a quarter above $0.75 per unit for that quarter. For the nine months ended September 30, 2004, we received $5.2 million in distributions for our subordinated units, and the general partner received $0.9 million, including $0.7 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 providing processing services and 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, compared to NGL products, the cost of keeping the producer “whole”, in conjunction with our operating costs, can result in operating losses. As noted previously, we entered into several new and amended agreements in September with one of the largest Appalachia producers that allow us to significantly reduce our exposure to commodity price risk for approximately 25% of our keep-whole gas volumes. We, however, cannot predict with any certainty what the pricing environment will be in the future.

On October 25, 2004, we entered into a $25.0 million senior credit facility with a term of one year.  The $25.0 million revolving facility has a variable interest rate based on the base rate, which is equal to the higher of a) the Federal Funds Rate plus ½ of 1%, and b) the rate of interest in effect for such day as publicly announced from time to time by the Administrative Agent as its prime rate, plus the applicable rate, which is based on a utilization percentage.  The amount available to be drawn under the credit facility is based upon the amount of our eligible

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

52

accounts receivable and inventory balance.  In addition, we are required to pay a commitment fee equal to the applicable rate times the actual daily amount by which the aggregate commitment exceeds the sum of (i) the outstanding amount of loans plus (ii) the outstanding amount of our letter of credit obligations.  Substantially all of our assets and our subsidiaries (other than excluded MarkWest Energy Partners entities) are pledged to the lender to secure the repayment of the outstanding borrowings under the credit facility.   The proceeds from this borrowing will be used to finance inventory and accounts receivable, issue letters of credit and pay fees, costs and expenses related to this agreement.  As of October 31, 2004, we had no outstanding borrowings.

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 processing services and marketing operations will be sufficient to meet our working capital requirements and fund our required capital expenditures, if any, for the foreseeable future. Most of our future capital expenditures are discretionary and minimal in nature.  During 2004, we have budgeted $1.0 million for our capital contribution to MarkWest Energy Partners for our share of the costs to replace the Cobb plant and an additional $0.1 million for other miscellaneous projects.  As of September 30, 2004 we had contributed $1.3 million for the Cobb plant, including amounts contributed in 2003, resulting in $0.4 million to be contributed during the fourth quarter of fiscal 2004.  Cash generated from our processing services and 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 renegotiate certain keep-whole contracts in order to reduce our commodity price risk.

MarkWest Energy Partners

Partnership Equity Offerings

During January 2004, the Partnership completed an offering of 1,100,444 of its common units, at $39.90 per unit, which netted approximately $44.9 million after transaction costs and the general partner contribution.  The Partnership primarily used the proceeds to pay down its outstanding debt.

During July 2004, MarkWest Energy Partners completed a private placement of 1,304,438 of its common units, at $34.50 per unit, which netted approximately $44.9 million after transaction costs and the general partner contribution.  The Partnership used the proceeds from the offering to finance the East Texas System acquisition.

On September 21, 2004, MarkWest Energy Partners completed a public offering of 2,323,609 of its common units at $43.41 per unit for gross proceeds of $100.9 million and 157,395 common units sold by certain selling unitholders.  Of the 2,323,609 common units sold, 323,609 common units were sold pursuant to the underwriter’s over-allotment option.  The Partnership did not receive any proceeds from the common units sold by the selling unitholders.  Total net proceeds from the offering, after deducting transaction costs of $5.2 million and including the general partner’s 2% capital contribution of $2.1 million, were $97.8 million and were used to repay a portion of the outstanding indebtedness under the amended and restated credit facility.

Partnership Debt

The Partnership’s $315.0 million credit facility, as amended and restated in August 2004, is available to fund capital expenditures and certain permitted acquisitions and distributions to unitholders. Advances to fund distributions to unitholders may not exceed $0.50 per outstanding unit in any 12-consecutive-month period. To date there have been no advances under the credit facility to fund distributions to unitholders.  Under the term loan, to the extent that a portion or all of the term loan is repaid, then those amounts may not be reborrowed.  In addition, there are certain restrictions on the reborrowing of amounts paid under the revolver loan.  At September 30, 2004, $197.5 million was outstanding, and $46.5 million was available for borrowing, under the Partnership’s credit facility.

In October 2004, the Partnership’s credit facility was amended and restated, decreasing the maximum lending limit from $315.0 million to $200.0 million and increasing the term of the facility to five years.  The credit facility includes a revolving facility of $200.0 million with the potential to increase the maximum lending limit to

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

53

$300.0 million.  The credit facility is guaranteed by the Partnership and all of its present and future subsidiaries and is collateralized by substantially all of its existing and future assets and those of its subsidiaries, including stock and other equity interests.  The borrowing under the credit facility will bear interest at a variable interest rate based on one of two indices that include either (i) LIBOR plus an applicable margin, which is fixed at a rate of 2.75% for the first two quarters following the closing of the credit facility or (ii) Base Rate (as defined for any day, a fluctuating rate per annum equal to the higher of (a) the Federal Funds Rate plus ½ of 1% and (b) the rate of interest in effect for such day as publicly announced from time to time by the Administrative Agent of the debt as its “prime rate”) plus an applicable margin, which shall be fixed at a rate of 2% for the first two quarters following the closing of the credit facility.  After that period, the applicable margin will be adjusted quarterly based on the Partnership’s ratio of funded debt to EBITDA (as defined in the credit agreement).  The Partnership is also required to pay a commitment fee equal to the applicable rate (as defined in the credit agreement) times the actual daily amount by which the aggregate revolver commitments exceed the sum of (i) the outstanding amount of revolver loans plus (ii) the outstanding amount of letters of credit obligations.  The commitment fee is due and payable quarterly in arrears on the last business day of each March, June, September and December.

In connection with the credit facility, the Partnership is subject to a number of restrictions on its business, including restrictions on its ability to grant liens on assets, merge, consolidate or sell assets, incur indebtedness (other than subordinate indebtedness), make acquisitions, engage in other businesses, enter into capital or operating leases, engage in transactions with affiliates, make distributions on equity interests and other usual and customary covenants.  In addition, MarkWest Energy Partners is subject to certain financial maintenance covenants, including ratios of total debt to EBITDA, total senior secured debt to EBITDA, EBITDA to interest and a minimum net worth requirement.  Failure to comply with the provisions of any of these covenants could result in acceleration of the debt and other financial obligations.

Concurrent with the amendment of the credit facility, in October 2004, the Partnership issued $225.0 million in senior notes at a fixed rate of 6.875% and with a maturity date of November 1, 2014.  Subject to compliance with certain covenants, the Partnership may issue additional notes from time to time under the indenture.   Interest on the notes accrue at the rate of 6.875% per year and are payable semi-annually in arrears on May 1 and November 1, commencing on May 1, 2005.  MarkWest Energy Partners may redeem some or all of the notes at any time on or after November 1, 2009 at certain redemption prices together with accrued and unpaid interest to the date of redemption, and the Partnership may redeem all of the notes at any time prior to November 1, 2009 at a make-whole redemption price.  In addition, prior to November 1, 2007, the Partnership may redeem up to 35% of the aggregate principal amount of the notes with the proceeds of certain equity offerings at a certain redemption price.  If MarkWest Energy Partners sells certain assets and does not reinvest the proceeds or repay senior indebtedness, or if it experiences specific kinds of changes in control, it must offer to repurchase notes at a specified price.  Each of its existing subsidiaries, other than MarkWest Energy Finance Corporation, has guaranteed the notes initially and so long as such subsidiary guarantees any of the other debt.  Not all of the Partnership’s future subsidiaries will have to become guarantors.  The notes are senior unsecured obligations with equal in right of payment with all of the existing and future senior debt.  These notes are senior in right of payment to all of the Partnership’s future subordinated debt but effectively junior in right of payment to its secured debt to the extent of the assets securing the debt, including its obligations in respect of the bank credit facility.  Borrowings under these notes were used to pay down the outstanding debt under the credit facility.

On October 31, 2004, after the closing of the senior indentured notes and after the Partnership had amended and restated the credit agreement, the Partnership had $225.0 million of senior indebtedness outstanding, comprised of $225.0 million unsecured senior notes at a fixed rate of 6.875%.

Cash generated from operations, borrowings under the credit facility and funds from the private and public equity offerings are the Partnership’s primary source of liquidity. We believe that funds from these sources will be sufficient to meet both the Partnership’s short-term and long-term working capital requirements and anticipated capital expenditures.  The Partnership’s ability to fund additional acquisitions will likely require the issuance of additional common units, the expansion of the credit facility, additional debt financing or a combination of all three.  In the event that the Partnership needs or desires to raise additional capital, it cannot be sure that additional funds will be available at times or on terms favorable to the Partnership.

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

54

The Partnership’s ability to pay distributions to its unitholders and to fund planned capital expenditures and to make acquisitions will depend upon its future operating performance, which will be affected by prevailing economic conditions in the industry and financial, business and other factors, some of which are beyond our control.

The Partnership’s largest customer is MarkWest Hydrocarbon, Inc. Consequently, matters affecting our business and financial condition—including our operations, management, customers, vendors, and the like—have the potential to impact, both positively and negatively, the Partnership’s liquidity.

Sustaining capital expenditures, which are expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives, are estimated to approximate $0.7 million for the Partnership for the remainder of 2004. For the nine months ended September 30, 2004, these expenditures were $1.0 million.

Total Contractual cash obligations

A summary of our total contractual cash obligations as of September 30, 2004, is as follows (in thousands):

Type of Obligation	Total Obligation			Due in 2004-2005			Due in 2006-2007			Thereafter
Operating Leases	$		14,050	$	5,600		$	4,448		$	4,002
Debt	197,500			—			—			197,500
Total	$	211,550		$		5,600	$		4,448	$		201,502

Cash Flows

	Nine Months Ended September 30,
	2004(1)			2003(1)
	(in thousands)
Net cash provided by operating activities	$	15,521		$	3,489
Net cash used in investing activities	$	(270,930	)	$	(17,983	)
Net cash provided by financing activities	$	234,912		$	15,553

(1)  As Restated.  See Note 16, Restatement and Reclassifications of Consolidated Financial Statements, to Notes to the Consolidated Financial Statements..

Net cashprovided by operating activities for the nine months ended September 30, 2004, increased relative to the same period in the prior year principally due to an increase in accounts payable and accrued liabilities as a result of the 2003 and 2004 acquisitions.

Net cash used in investing activities for the nine months ended September 30, 2004, increased relative to the same period in the prior year primarily due to the Partnership’s acquisition of the East Texas System in July 2004 for $240.6 million.  Additionally, we invested $11.9 million in marketable securities.

Net cash provided by financing activities for the nine months ended September 30, 2004, was primarily attributable to equity financings and borrowings under our Partnership’s credit facility.  In January 2004, the Partnership completed a secondary public offering generating net proceeds of $44.9 million in 2004.  The proceeds were used to pay down the outstanding debt.  The Partnership also amended and restated its credit facility in July 2004 to increase its total borrowing capacity to $315.0 million.  MarkWest Energy Partners borrowed $200.8 million under this credit facility to partially finance its East Texas System acquisition.  In July 2004, the Partnership completed a private placement of 1,304,438 of common units to a group of institutional investors, generating total net proceeds of $44.9 million.  These funds were also used to partially finance the East Texas System acquisition.  In addition, the Partnership raised net proceeds of $97.8 million through a public offering of 2,323,609 common units in September 2004.  Proceeds from this offering were used to reduce our outstanding indebtedness.  Additionally, we paid dividends of $5.3 million and MarkWest Energy Partners paid distributions to its unitholders of $9.4 million.

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

55

Recent Accounting Pronouncements

On March 31, 2004, the Emerging Issues Task Force issued EITF No. 03-6 which clarifies the computation of earnings per share in SFAS No. 128, for companies that have issued securities other than common stock that entitle the holder to participate in the company’s declared dividends and earnings.  The consensus states that securities should be included in basic earnings per share calculations when the holder is entitled to receive dividends rather than if the holder is entitled to receive earnings or value upon redemption of the securities or liquidation of assets.  The effective date of EITF No. 03-6 is the first fiscal period beginning after March 31, 2004, and requires restatement of prior period information.  Implementation of the consensus had no effect on the financial results and resulted in no change in earnings per share for the three month and nine month periods ending September 30, 2004, and 2003.

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

56

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 our fiscal year ended December 31, 2003. Forward-looking statements include statements relating to, among other things:

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

•The continued growth of MarkWest Energy Partners, L.P.

•Our ability to amend certain producer contracts.

•Our ability to increase fee-based contract volumes.

•Our expectations regarding natural gas and NGL production and prices.

•Our ability to manage our commodity price risk.

•Our ability to maximize the value of our NGL output.

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.

In addition, certain of the Partnership’s pipelines could in the future become subject to the jurisdiction of the Federal Energy Regulatory Commission, or FERC, depending upon possible changes in the factual circumstances upon which each pipeline’s jurisdictional status is based.  Such a change could adversely affect the terms of service, rates and revenues of such pipelines.

The Michigan Crude Pipeline is not currently subject to the jurisdiction of the FERC.  If a shipper sought to challenge the jurisdictional status of this pipeline, however, FERC could determine that transportation on this pipeline is within its jurisdiction under the Interstate Commerce Act, thereby requiring the Partnership to file a tariff and cost-based rates for such transportation with FERC.  While no shipper has filed a formal complaint, one shipper on the Michigan Crude Pipeline has contacted FERC about the transportation rates and question the jurisdictional status of the pipeline.  FERC requested that MarkWest Energy Partners and the shipper resolve the dispute.  If the Partnership is unable to successfully resolve this dispute or any future dispute over the jurisdictional status of the Michigan Crude Pipeline, it could become subject to FERC regulation, and the cost of compliance with that

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

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regulation could adversely affect our profitability.

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

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Item 3.  Quantitative and Qualitative Disclosures about Market Risk

Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity price variations and also incur, to a lesser extent, credit risks and risks related to interest rate variations.

Commodity Price Risk

We market natural gas and NGL products.  In addition, through our consolidated subsidiary, MarkWest Energy Partners, we are engaged in the gathering processing and transmission of natural gas, the transportation, fractionation and storage of NGLs and the gathering and transportation of crude oil.  Our products are commodities that are subject to price risk resulting from material changes in response to fluctuations in supply and demand, general economic conditions and other market conditions, such as weather patterns, over which we have no control.

Our primary risk management objective is to reduce volatility in our cash flows.  Our hedging approach includes statistical methods that analyze momentum and average pricing over time, and various fundamental data such as industry inventories, industry production, demand and weather. A committee, which includes members of senior management, oversees all of our hedging activity.

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

We enter OTC swaps with financial institutions and other energy company counterparties. We conduct a standard credit review on counterparties and have agreements containing collateral requirements where deemed necessary. We use standardized swap agreements that allow for offset of positive and negative exposures.  Net credit exposure is marked to market daily.  We are subject to margin deposit requirements under OTC agreements and NYMEX positions.

The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (i) NGLs do not trade at historical levels relative to crude oil, (ii) sales volumes are less than expected requiring market purchases to meet commitments, or (iii) our OTC counterparties fail to purchase or deliver the contracted quantities of natural gas, NGLs, or crude oil or otherwise fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market.  However, we are similarly insulated against decreases in such prices.

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

NGL Price Risk

Within our NGL marketing segment, our price risk varies by contract as well as by spot market prices for both NGL and natural gas commodities.  The Appalachian producers compensate us for providing midstream services under the following contract types:

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

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

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in operating losses.  The spread between the NGL product sales price and the purchase price of natural gas with an equivalent Btu content is called the “frac spread”.

•Under “percent-of-proceeds” contracts, the Partnership takes title to the NGLs produced in its processing operations, sells the NGLs to third parties and pays the producer a specified percentage of the proceeds received from the sales.  Percent-of-proceeds contracts therefore expose the Partnership to NGL product price risk.  All of the Michigan processing business is also governed by percent-of-proceeds contracts.

Our consolidated subsidiary, MarkWest Energy Partners, is also subject to NGL price risk.  For the nine months ended September 30, 2004, approximately 39% of the Partnership’s business (as measured by gross margin, which is defined as revenue less purchased product cost) was directly subject to natural gas and NGL product price risk.  This includes the entire gross margin from the Partnership’s business based on percent-of-index contracts, percent-of-proceeds contracts and keep-whole contracts.  Regarding the 19% of the gross margin governed by keep-whole contracts, MarkWest Energy Partners actively manages the related commodity price risk exposure, to the extent possible, by not operating its Arapaho processing plant in Oklahoma during low processing margin environments and through our ability to reject or recover ethane in Carthage.  See related discussion in Item 2. Management’s Discussion and Analysis”.

As of September 30, 2004, we had contracts in place to manage our NGL product price risk as follows:

	Year Ending December 31,
	2004		2005
Hedged NGL product price
NGL gallons	8,778,000		8,274,000
$/gallons	$	0.88	$	0.86

As of September 30, 2004, we hedged our natural gas price risk via pre-purchases as follows:

	Year Ending December 31
	2004		2005
Hedged Natural Gas Purchases:
MMBtu	850,929		802,071
$/MMBtu	$	5.56	$	5.56

The NGL and natural gas swaps are not designed as hedges.  As a result, changes in the fair value of the NGL and natural gas swaps are reflected currently in earnings.

MarkWest Energy Partners

The Partnership hedges its natural gas price risk in Texas (part of our Pinnacle acquisition) by entering into fixed-for-float price swaps or buying puts.  As of September 30, 2004, the Partnership hedged its Texas natural gas price risk via swaps as follows:

	Year Ending December 31,
	2004		2005
MMBtu	30,500		182,500
$/MMBtu	$	4.57	$	4.26

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

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As of September 30, 2004, MarkWest Energy Partners also had hedged its Texas natural gas price risk via puts as follows:

	Year Ending December 31,
	2004		2005
MMBtu	61,000		—
Strike price ($/MMBtu)	$	4.00	$	—

Additionally, at September 30, 2004, the Partnership had hedged its Oklahoma natural gas basis risk via swap as follows:

	Year Ending December 31,
	2004			2005
MMBtu	951,000			900,000
($/MMBtu)	$	(0.035	)	$	(0.035	)

Interest Rate Risk

The Partnership is exposed to changes in interest rates, primarily as a result of its long-term debt under the credit facility with floating interest rates.  The Partnership makes use of interest rate swap and collar agreements to adjust the ratio of fixed and floating rates (LIBOR plus an applicable margin) in the debt portfolio.

As of September 30, 2004, the Partnership was a party to interest rate swap agreements to fix interest rates on debt of $8.0 million at 3.84% through May 2005 and $25.0 million at 3.33% through November 2006 (currently $33.0 million with a weighted average interest rate of 3.46%).  In addition, the Partnership is a party to an interest-rate collar agreement on $20.0 million of debt with a maximum rate of 3.33% through May 2005, and a minimum rate of 1.25% through August 2004, 1.30% through November 2004, 2.10% through February 2005 and 2.60% through May 2005.

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

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Item 4. Controls and Procedures

Overview

This Form 10-Q/A reflects adjustments to the consolidated financial report for the third quarter of each of the years 2003 and 2004.  Please refer to Note 16, 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, an adjustment to reverse transactions improperly recorded as a derivative transaction with hedge accounting treatment and adjustments to accrued property taxes. 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 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 nine months ended September 30, 2004 from retained earnings to additional paid in capital for the amount of dividends distributed in excess of accumulated earnings.   Cash was also adjusted primarily as a result of reclassifying amounts recorded for the purchase of property, plant and equipment, intangible assets and accrued property tax relating to an acquisition from cash to those respective accounts.  Initially, the purchase of those assets was recorded to a cash clearing account until the purchase price was settled in the fourth quarter of 2004.  Other less significant adjustments and reclassifications were identified and recorded in conjunction with the restatement process.  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 adjusted to give retroactive effect to stock dividends paid.  The Company is filing contemporaneously with this Form 10-Q/A for the quarterly period ended September 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 June 30, 2004.

Disclosure Controls and Procedures

In connection with the preparation of this 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 September 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 September 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

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

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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 September 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.

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

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PART II—OTHER INFORMATION

Item 1.  Legal Proceedings

Reference is made to Note 13 of our Consolidated Financial Statements in Part I, Item 1, of this Form 10-Q/A (Amendment No. 1), which is incorporated herein by reference.

Item 6.  Exhibits

2.1	(1)	Asset Purchase and Sale Agreement and addendum, thereto, dated as of July 1, 2004 by and between American Central Eastern Texas Gas Company Limited Partnership, ACGC Gathering Company, L.L.C. and MarkWest Energy East Texas Gas Company’s L.P.
4.1	(1)	Unit Purchase Agreement dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and MarkWest Energy GP, L.L.C. and each of Kayne Anderson Energy Fund II, L.P., Kayne Anderson Capital Income Partners, L.P., Kayne Anderson MLP Fund, L.P., Kayne Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR RV Performance Master Trust, Tortoise Energy Infrastructure Corporation and Energy Income and Growth Fund, as Purchasers.
4.2	(1)	Registration Rights Agreement dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and each of Kayne Anderson Energy Fund II, L.P., Kayne Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR RV Performance Master Trust, Tortoise Energy Infrastructure Corporation and Energy Income and Growth Fund.
31.1		Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.3		Certification of the Chief Accounting Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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.
99.1	(1)	Second Amended and Restated Credit Agreement dated as of July 30, 2004 among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe Generale, as Documentation Agent to the $315,000,000 Senior Credit Facility.
99.2	(1)	First Amendment to the Second Amended and Restated Credit Agreement dated as of August 20, 2004, among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe Generale, as Documentation Agent.

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

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99.3	(2)	Firm Gas Processing Agreement (Dwale) entered into on September 23, 2004 between Equitable Production Company and MarkWest Hydrocarbon, Inc.
99.4	(2)	Sale and Purchase of Natural Gas Agreement entered into on September 23, 2004 between Equitable Production Company and MarkWest Hydrocarbon, Inc.
99.5	(2)	Netting, Financial Responsibility and Security Agreement entered into on September 23, 2004 between Equitable Production Company and MarkWest Hydrocarbon, Inc.

(1)  Filed as an exhibit to the Registrants’ Form 8-K/A dated July 30, 2004 and filed on October 12, 2004.

(2)  Portions of the agreement have been redacted, as we will request confidential treatment from the Securities and Exchange Commission.

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

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SIGNATURE

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

	MarkWest Hydrocarbon, Inc.
	(Registrant)
Date:  October 20, 2005			/s/ James G. Ivey
				James G. Ivey
		Chief Financial Officer

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

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Exhibit Number		Exhibit Index
2.	1(1)	Asset Purchase and Sale Agreement and addendum, thereto, dated as of July 1, 2004 by and between American Central Eastern Texas Gas Company Limited Partnership, ACGC Gathering Company, L.L.C. and MarkWest Energy East Texas Gas Company’s L.P.
4.	1(1)	Unit Purchase Agreement dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and MarkWest Energy GP, L.L.C. and each of Kayne Anderson Energy Fund II, L.P., Kayne Anderson Capital Income Partners, L.P., Kayne Anderson MLP Fund, L.P., Kayne Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR RV Performance Master Trust, Tortoise Energy Infrastructure Corporation and Energy Income and Growth Fund, as Purchasers.
4.2	(1)	Registration Rights Agreement dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and each of Kayne Anderson Energy Fund II, L.P., Kayne Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR RV Performance Master Trust, Tortoise Energy Infrastructure Corporation and Energy Income and Growth Fund.
31.	1	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.	2	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.	3	Certification of the Chief Accounting Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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.
99.	1(1)	Second Amended and Restated Credit Agreement dated as of July 30, 2004 among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe Generale, as Documentation Agent to the $315,000,000 Senior Credit Facility.
99.	2(1)	First Amendment to the Second Amended and Restated Credit Agreement dated as of August 20, 2004, among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe Generale, as Documentation Agent.
99.	3(2)	Firm Gas Processing Agreement (Dwale) entered into on September 23, 2004 between Equitable Production Company and MarkWest Hydrocarbon, Inc.
99.	4(2)	Sale and Purchase of Natural Gas Agreement entered into on September 23, 2004 between Equitable Production Company and MarkWest Hydrocarbon, Inc.

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

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99. 5(2) Netting, Financial Responsibility and Security Agreement entered into on September 23, 2004 between Equitable Production Company and MarkWest Hydrocarbon, Inc.

(1)Filed as an exhibit to the Registrants’ Form 8-K/A dated July 30, 2004 and filed on October 12, 2004.

(2)Portions of the agreement have been redacted, as we will request confidential treatment from the Securities and Exchange Commission.

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

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