PART I—FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements

MARKWEST HYDROCARBON, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share and per share data)

	September 30, 2005			December 31, 2004
ASSETS
Current assets:
Cash and cash equivalents	$	2,158		$	12,844
Restricted cash	15,000			15,000
Marketable securities	15,307			14,815
Receivables, net (including related party receivables of $110 and $44, respectively, and allowance for doubtful accounts of $319 and $249, respectively)	75,134			64,856
Inventories	26,280			11,292
Prepaid replacement natural gas	6,814			10,245
Deferred income taxes	—			25
Other current assets	10,112			1,898
Total current assets	150,805			130,975

Property, plant and equipment	391,982			342,636
Less: accumulated depreciation, depletion, amortization and impairment	(73,219		)	(59,443		)
Total property, plant and equipment, net	318,763			283,193

Other assets:
Investment in Starfish	39,805			—
Intangible assets, net of accumulated amortization of $9,907 and $3,640, respectively	155,713			162,001
Deferred financing costs, net of accumulated amortization of $7,480 and $5,541, respectively	17,095			13,849
Deferred contract cost, net of accumulated amortization of $312 and $78, respectively	2,938			3,172
Investment in and advances to other equity investee	203			177
Notes receivable from related parties	154			207
Total other assets	215,908			179,406
Total assets	$	685,476		$	593,574

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable (including related party payables of $25 and $30, respectively)	$	60,866		$	45,103
Accrued liabilities	43,779			30,908
Fair value of derivative instruments	441			1,057
Deferred income taxes	77			—
Asset retirement obligation	291			—
Total current liabilities	105,454			77,068

Deferred income taxes	3,358			6,258
Senior notes	225,000			225,000
Long-term debt	85,500			—
Other long-term liabilities	10,357			7,487
Non-controlling interest in consolidated subsidiary	212,979			228,000

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, 10,851,556 and 10,821,760 shares issued, respectively	108			108
Additional paid-in capital	50,044			51,455
Deferred compensation	(79		)	—
Accumulated deficit	(7,381		)	(1,623		)
Accumulated other comprehensive income, net of tax	592			246
Treasury stock, 55,619 and 63,586 shares, respectively	(456		)	(425		)
Total stockholders’ equity	42,828			49,761
Total liabilities and stockholders’ equity	$	685,476		$	593,574

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

MARKWEST HYDROCARBON, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands, except per share data)

	Three Months Ended September 30,
	2005			2004

Revenues	$	170,625		$	121,511

Operating expenses:
Purchased product costs	145,876			95,209
Facility expenses	12,082			8,398
Selling, general and administrative expenses	7,913			7,252
Depreciation	5,025			4,510
Amortization of intangible assets	2,098			1,400
Accretion of asset retirement and lease obligations	116			13
Total operating expenses	173,110			116,782

Income (loss) from operations	(2,485		)	4,729

Other income (expense):
Loss from unconsolidated subsidiary	(999		)	(32		)
Interest income	271			180
Interest expense	(4,980		)	(3,739		)
Amortization of deferred financing costs (a component of interest expense)	(557		)	(3,120		)
Dividend income	101			86
Other income	65			585

Loss before non-controlling interest in net income of consolidated subsidiary and income taxes	(8,584		)	(1,311		)

Provision (benefit) for income taxes:
Current	—			39
Deferred	(2,868		)	112
Provision (benefit) for income taxes	(2,868		)	151

Non-controlling interest in net income of consolidated subsidiary	28			(504		)

Net loss	$	(5,688	)	$	(1,966	)

Net loss per share:
Basic	$	(0.53	)	$	(0.18	)
Diluted	$	(0.53	)	$	(0.18	)

Weighted average number of outstanding shares of common stock:
Basic	10,792			10,736
Diluted	10,879			10,800
Cash dividend per common share	$	0.10		$	0.023

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

MARKWEST HYDROCARBON, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands, except per share data)

	Nine Months Ended September 30,
	2005			2004

Revenues	$	450,018		$	304,235

Operating expenses:
Purchased product costs	362,929			247,960
Facility expenses	32,327			20,459
Selling, general and administrative expenses	25,140			17,637
Depreciation	14,761			11,695
Amortization of intangible assets	6,288			1,468
Accretion of asset retirement and lease obligations	137			13
Total operating expenses	441,582			299,232

Income from operations	8,436			5,003

Other income (expense):
Loss from unconsolidated subsidiary	(9		)	(49		)
Interest income	841			536
Interest expense	(13,273		)	(5,792		)
Amortization of deferred financing costs (a component of interest expense)	(1,651		)	(3,734		)
Dividend income	289			169
Other income	300			596

Loss before non-controlling interest in net income of consolidated subsidiary and income taxes	(5,067		)	(3,271		)

Provision (benefit) for income taxes:
Current	—			151
Deferred	(2,900		)	438
Provision (benefit) for income taxes	(2,900		)	589

Non-controlling interest in net income of consolidated subsidiary	(3,591		)	(3,759		)

Net loss	$	(5,758	)	$	(7,619	)

Net loss per share:
Basic	$	(0.53	)	$	(0.71	)
Diluted	$	(0.53	)	$	(0.71	)

Weighted average number of outstanding shares of common stock:
Basic	10,780			10,665
Diluted	10,889			10,715
Cash dividend per common share	$	0.275		$	0.50

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

MARKWEST HYDROCARBON, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)

(in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004

Net loss	$	(5,688	)	$	(1,966	)	$	(5,758	)	$	(7,619	)

Other comprehensive income (loss), net of tax:
Unrealized gains on commodity derivatives accounted for as hedges, net of income tax provision of $240, $531, $118 and $1,002	392			888			195			1,656
Unrealized gains (losses) on marketable securities, net of income tax provision (benefit) of $(24), $168, $92 and $(56)	(40		)	277			151			(93		)
Total other comprehensive income	352			1,165			346			1,563

Comprehensive loss	$	(5,336	)	$	(801	)	$	(5,412	)	$	(6,056	)

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

MARKWEST HYDROCARBON, INC.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

(in thousands)

	Shares of Common Stock	Shares of Treasury Stock		Common Stock		Additional Paid-In Capital			Deferred Compensation			Accumulated Deficit			Accumulated Other Comprehensive Income		Treasury Stock			Total Stockholders’ Equity

Balance, December 31, 2004	10,822	(64	)	$	108	$	51,455		$	—		$	(1,623	)	$	246	$	(425	)	$	49,761

Stock option exercises	30	—		—		77			—			—			—		—			77

Issuance of restricted stock	—	7		—		76			(134		)	—			—		58			—

Amortization of deferred stock-based compensation	—	—		—		—			55			—			—		—			55

Cashless stock options	—	—		—		1,285			—			—			—		—			1,285

Treasury stock acquired	—	(7	)	—		—			—			—			—		(161		)	(161		)

Contribution of treasury shares to 401(k) benefit plan	—	8		—		116			—			—			—		72			188

Net loss	—	—		—		—			—			(5,758		)	—		—			(5,758		)

Dividend	—	—		—		(2,965		)	—			—			—		—			(2,965		)

Other comprehensive income	—	—		—		—			—			—			346		—			346

Balance, September 30, 2005	10,852	(56	)	$	108	$	50,044		$	(79	)	$	(7,381	)	$	592	$	(456	)	$	42,828

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

MARKWEST HYDROCARBON, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Nine Months Ended September 30,
	2005			2004
Cash flows from operating activities:
Net loss	$	(5,758	)	$	(7,619	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation	14,761			11,694
Amortization of intangible assets	6,288			1,468
Amortization of deferred financing costs	1,651			2,265
Write down of deferred financing costs	—			1,469
Amortization of deferred contract costs reflected in purchase product costs	234			—
Accretion of asset retirement and lease obligations	137			—
(Gain) loss from sale of property, plant and equipment	(220		)	145
Gain from sale of marketable securities	(56		)	—
Imputed interest income on debt securities	(11		)	—
Phantom unit compensation expense	900			732
Participation Plan compensation expense	3,610			1,205
Stock option compensation expense	1,285			1,531
Restricted stock compensation expense	55			—
Losses from unconsolidated subsidiaries in excess of distributions	1,857			50
Deferred income taxes (benefit)	(2,900		)	438
Non-controlling interest in net income of consolidated subsidiary	3,591			3,759
Contribution of treasury shares to 401(k) benefit plan	188			107
(Gains) losses on derivative instruments	(739		)	732
Other	1			(51		)
Changes in operating assets and liabilities:
Increase in receivables	(10,278		)	(15,248		)
Increase in inventories	(14,988		)	(6,902		)
(Increase) decrease in prepaid replacement natural gas	3,431			(7,233		)
Increase in other current assets	(8,214		)	(3,133		)
Increase in accounts payable and accrued liabilities	28,413			30,114
Increase (decrease) in other long-term liabilities	44			(2		)
Net cash flow provided by operating activities	23,282			15,521

Cash flows from investing activities:
Increase in restricted cash	—			(550		)
Purchase of marketable securities	(8,725		)	(11,920		)
Proceeds from the sales of marketable securities	8,536			—
Starfish acquisition	(41,688		)	—
East Texas System acquisition	—			(240,606		)
Hobbs Lateral acquisition	—			(2,275		)
Capital expenditures	(50,368		)	(12,668		)
Proceeds from sale of assets	248			206
Increase in other contracts	—			(3,250		)
Proceeds from financing lease receivable	—			133
Net cash used in investing activities	(91,997		)	(270,930		)

	Nine Months Ended September 30,
	2005			2004
Cash flows from financing activities:
Collection of notes receivable	53			—
Proceeds from long-term debt	97,000			215,600
Repayment of long-term debt	(11,500		)	(144,300		)
Payments for debt issuance costs	(5,096		)	(7,193		)
Proceeds from MarkWest Energy Partners’ common unit public offerings, net	—			140,014
Proceeds from MarkWest Energy Partners’ common unit private placement, net	—			44,139
Distribution to MarkWest Energy Partners’ unitholders	(19,379		)	(9,437		)
Exercise of stock options	77			1,413
Purchase of treasury shares	(161		)	(36		)
Payment of dividends	(2,965		)	(5,288		)
Net cash provided by financing activities	58,029			234,912

Net decrease in cash and cash equivalents	(10,686		)	(20,497		)

Cash and cash equivalents at beginning of period	12,844			42,144

Cash and cash equivalents at end of period	$	2,158		$	21,647

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest, net of amounts capitalized	$	13,009		$	4,607
Income taxes	$	549		$	—

Supplemental schedule of non-cash investing and financing activities:
Construction projects in-progress obligations	$	329		$	1,094
Property, plant and equipment asset retirement obligations	$	479		$	377

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

MARKWEST HYDROCARBON, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Organization

MarkWest Hydrocarbon, Inc. (“MarkWest Hydrocarbon” or the “Company”) manages MarkWest Energy Partners, L.P. (“MarkWest Energy Partners” or the “Partnership”), a publicly traded master limited partnership engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids (“NGLs”); and the gathering and transportation of crude oil. The Company also markets natural gas and NGLs. MarkWest Hydrocarbon and MarkWest Energy Partners provide services primarily in Appalachia, Michigan, east Texas, western Oklahoma and other areas of the southwest. Through eight acquisitions completed by MarkWest Energy Partners in 2003, 2004 and 2005, the Company has significantly expanded its natural gas activities.

2. Basis of Presentation

The condensed consolidated financial statements include the accounts of MarkWest Hydrocarbon and its subsidiaries, including MarkWest Energy Partners (collectively “MarkWest Hydrocarbon” or the “Company”). Through consolidation, MarkWest Hydrocarbon has eliminated all significant intercompany accounts and transactions. Equity investments in which the Company exercises significant influence but does not control and is not the primary beneficiary are accounted for using the equity method. The Company regularly reviews its investments to determine whether a decline in fair value below the cost basis is other than temporary. The Company’s accounting policy requires it to evaluate operating losses (if any), credit defaults and other factors that may be indicative of a decrease in value of the investment that which is other than temporary. The primary factors the Company considers in its determination of an impairment that is other than temporary are the length of time that the fair value of the investment is below the Company’s carrying value and the financial condition, operating performance and near-term prospects of the investee. In addition, the Company considers the reason for the decline in fair value, be it general market conditions, industry-specific or investee-specific; and the Company’s intent and ability to hold the investment for a period of time sufficient to allow for a recovery in fair value. The Company evaluates fair value based on specific information (valuation methodologies, financial statements, estimates of appraisals, etc.). Due to a lack of a public market price for the Company’s current investments, it uses its best estimates and assumptions to arrive at the estimated fair value of such investment. If the decline in fair value is deemed to be other than temporary, the cost basis of the security is written down to fair value. The Company’s assessment of the foregoing factors involves a high degree of judgment and, accordingly, actual results may differ materially from the Company’s estimates and judgments.

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial reporting. The year-end condensed consolidated balance sheet data was derived from audited financial statements. In management’s opinion, the Company has made all adjustments necessary for a fair presentation of the Company’s results of operations, financial position and cash flows for the periods shown. These adjustments are of a normal recurring nature. In addition to reviewing these condensed consolidated financial statements and accompanying notes, you should also consult the audited financial statements and notes that make up the Company’s December 31, 2004, Annual Report on Form 10-K. Finally, results for the nine months ended September 30, 2005, are not necessarily indicative of results for the full year 2005, or for any other future period.

3. Recent Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (“SFAS”) No. 123 (revised 2004), Share-Based Payment (“SFAS No. 123 (R)”). This statement addresses the accounting for share-based payment transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the enterprise, or (b) liabilities that are based on the fair value of the enterprise’s equity instruments or that may be settled by the issuance of such equity instruments. SFAS No. 123(R) requires an entity to recognize the grant-date fair-value of stock options and other equity-based compensation issued to employees in the income statement. The revised Statement generally requires that an entity account for those transactions using the fair-value-based method, and eliminates the intrinsic value method of accounting in Accounting Principles Board Opinion (“APB”) No. 25, Accounting for Stock Issued to Employees, which was

permitted under SFAS No. 123, as originally issued. The revised Statement requires entities to disclose information about the nature of the share-based payment transactions and the effects of those transactions on the financial statements. SFAS No. 123(R) is effective for public companies for the first fiscal year beginning after December 15, 2005. All public companies must use either the modified prospective or the modified retrospective transition method. On March 29, 2005, the SEC staff issued Staff Accounting Bulletin (“SAB”) No. 107, Share-Based Payment to express the views of the staff regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. The Company will take into consideration the additional guidance provided by SAB 107 in connection with the implementation of SFAS No. 123(R). The Company has not yet evaluated the impact of the adoption of this pronouncement, which must be adopted in the first quarter of calendar year 2006.

In March 2005, the FASB issued FASB Interpretation (FIN) No. 47, Accounting for Conditional Asset Retirement Obligations, which clarifies the accounting for conditional asset retirement obligations as used in SFAS No. 143, Accounting for Asset Retirement Obligations. A conditional asset retirement obligation is an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation under SFAS No. 143 if the fair value of the liability can be reasonably estimated. FIN 47 permits, but does not require, restatement of interim financial information. The provisions of FIN 47 are effective for reporting periods ending after December 15, 2005. The Company has not yet assessed the impact of adopting FIN 47 on its consolidated financial statements.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3. SFAS No. 154 replaces Accounting Principles Board Opinion No. 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements, and changes the requirements for the accounting for and reporting of a change in accounting principle. This statement applies to all voluntary changes in accounting principle and also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. The statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company will adopt the provisions of SFAS No. 154 beginning in calendar year 2006. Management believes that the adoption of the provisions of SFAS No. 154 will not have a material impact on the Company’s consolidated financial statements.

4. 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, and SFAS No. 148, Accounting for Stock Based Compensation — Transition and Disclosure. The Company has two fixed compensation plans and two variable plans, one of which is through the Company’s consolidated subsidiary, MarkWest Energy Partners. The Company accounts for these plans using fixed and variable accounting as appropriate.

The Company’s 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Plan

Stock Options

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 those 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 employees. 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 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 No. 25, a fixed stock option plan that permits the use of a cashless exercise becomes variable if a pattern of exercising the stock options using the cashless method is demonstrated. As a result, in April 2004, the Company was required to account for stock options issued under the plans as variable awards. Compensation expense for stock options issued 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 as the options vest, 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 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 in selling, general and administrative expenses. The Company recorded compensation expense for options granted under the plans of $0.3 million and $1.3 million for the three and nine months ended September 30, 2005, respectively; and $0.5 million and $1.2 for the three and nine months ended September 30, 2004, respectively.

During the three and nine months ended September 30, 2005, recipients exercised their options to purchase an aggregate 9,043 and 39,708 shares of the Company’s common stock, respectively. During the three and nine months ended September 30, 2005, recipients exercised options for 6,623 and 28,000 shares using the cashless method, respectively, resulting in the net issuance of 4,689 and 17,780 shares of common stock, respectively. During the three and nine months ended September 30, 2004, recipients exercised their options to purchase an aggregate of 23,000 and 216,000 shares of the Company’s common stock, respectively. During the three and nine months ended September 30, 2004, recipients exercised options for 64,563 and 111,000 shares using the cashless method resulting in the net issuance of 18,463 and 36,000 shares of common stock, respectively.

During the three months ended March 31, 2004, two officers resigned from the Company. Because 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. Due to the modification to the stock options for these officers, the outstanding stock options are accounted for as a variable award. As a result, the Company recorded compensation expense of $0.4 million for the nine months ended September 30, 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.

Restricted Stock

The Company also issues restricted stock under the Company’s 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan. In accordance with APB No. 25, the Company applies fixed accounting for the plans. As a result, since the restricted stock is granted for no consideration, compensation expense is recognized on the date of grant equal to the market price of the Company’s common stock. The fair value of the stock awarded is amortized into earnings over the period of service. The restricted stock vests over a stated period. During the nine months ended September 30, 2005, the Company granted 6,973 shares of restricted stock; none of the shares were issued during the three months ended September 30, 2005. The Company recorded compensation expense of less than $0.1 million and $0.1 million for the three and nine months ended September 30, 2005, respectively. The Company recorded no compensation expense for the three and nine months ended September 30, 2004. These charges are included in selling, general and administrative expenses.

Participation Plan

The Company has also entered into arrangements with certain directors and employees of the Company referred to as the Participation Plan. The Company 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, and EITF No. 95-16, Accounting for Stock Compensation Arrangements with Employer Loan Features, the Participation Plan is accounted for as a variable plan. Since the employees and directors are 100% vested on the date they purchase the subordinated units or general partner interest, compensation expense for the subordinated units is measured as the difference between the market value of the subordinated Partnership units and the amount paid by those individuals.

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 market 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 employees 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 Partner’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 some 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 an identified certain number of consecutive quarters, vesting of the employee’s phantom units is accelerated. However, the vesting of any phantom units may not occur until at least one year following the date of grant. The general partner of the Partnership may also elect to accelerate the vesting of outstanding awards, which results in an immediate charge to operations for the unamortized portion of the award. The Partnership recorded compensation expense of $0.2 million and $0.4 million for the three months ended September 30, 2005 and 2004, respectively; and, compensation expense of $0.9 million and $0.7 million for the nine months ended September 30, 2005 and 2004, respectively.

Had compensation cost for the Company’s stock-based compensation plans been determined based on the fair value at the grant dates under those plans consistent with the method prescribed by SFAS No. 123, the Company’s net loss and net loss per share would have been revised to the pro forma amounts listed below (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004

Net loss, as reported	$	(5,688	)	$	(1,966	)	$	(5,758	)	$	(7,619	)
Add: compensation expense included in reported net loss, net of related tax effect	922			1,744			3,894			3,758
Deduct: total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effect	(708		)	(1,291		)	(3,050		)	(2,242		)
Pro forma net loss	$	(5,474	)	$	(1,513	)	$	(4,914	)	$	(6,103	)

Net loss per share:
Basic:
As reported	$	(0.53	)	$	(0.18	)	$	(0.53	)	$	(0.71	)
Pro forma	$	(0.51	)	$	(0.14	)	$	(0.46	)	$	(0.57	)
Diluted:
As reported	$	(0.53	)	$	(0.18	)	$	(0.53	)	$	(0.71	)
Pro forma	$	(0.51	)	$	(0.14	)	$	(0.46	)	$	(0.57	)

5. 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 temporary losses are reflected in other comprehensive income, net of applicable income taxes. For losses that are other than temporary, the cost basis of the securities is written down to fair value and the amount of the write down is reflected in the statement of operations.

The Company utilizes a first-in first-out cost basis to compute realized gains and losses. Realized gains and losses, dividends, interest income, and the amortization of discounts and premiums are reflected in operations.

The following are the components of marketable securities (in thousands):

	Cost Basis		Unrealized gains		Unrealized losses			Recorded Basis
September 30, 2005
Equity securities:
Master limited partnership units	$	5,497	$	1,224	$	(18	)	$	6,703
Fixed maturities:
Mortgage backed securities (due after one year through five years)	8,740		—		(136		)	8,604
Total marketable securities, classified as current	$	14,237	$	1,224	$	(154	)	$	15,307

December 31, 2004
Equity securities:
Master limited partnership units	$	5,248	$	872	$	(19	)	$	6,101
Fixed maturities:
Mortgage backed securities (due after one year through five years)	8,750		10		(46		)	8,714
Total marketable securities, classified as current	$	13,998	$	882	$	(65	)	$	14,815

At September 30, 2005, unrealized gains of $1.2 million relate primarily to investments in equity securities of domestic energy partnerships. Unrealized losses of $0.2 million relate primarily to mortgage backed securities and are primarily attributable to changes in interest rates. Net unrealized gains on marketable securities of $1.1 million, net of the related tax effect of $0.4 million, are reflected as a component of other comprehensive loss at September 30, 2005.

At December 31, 2004, unrealized gains of $0.9 million relate primarily to investments in equity securities of domestic energy partnerships. Unrealized losses of $0.1 million relate primarily to mortgage backed securities and are primarily attributable to changes in interest rates. Net unrealized gains on marketable securities of $0.8 million, net of the related tax effect of $0.3 million, are reflected as a component of other comprehensive income at December 31, 2004.

6. Income Taxes

The Company accounts for income taxes under the asset and liability method pursuant to SFAS No. 109, Accounting for Income Taxes. Under SFAS No. 109, deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized as income in the period that includes the enactment date of the tax rate change. Realizability of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value. The Company bases the effective corporate tax rate for interim periods on the estimated annual effective corporate tax rate. Income tax benefit totaled $2.9 million for both the three and nine months ended September 30, 2005, respectively, resulting in an effective tax rate of 33.5%. Income tax expense totaled $0.1 million and $0.6 million for the three and nine months ended September 30, 2004, respectively, resulting in an effective income tax rate of (8.4)% for both the three and nine months ended September 30, 2004.

7. MarkWest Energy Partners’ Acquisitions

Starfish Acquisition

On March 31, 2005, MarkWest Energy Partners completed the acquisition of a 50% non-operating membership interest in Starfish Pipeline Company, LLC, (“Starfish”) from an affiliate of Enterprise Products Partners L.P. for $41.7 million. Starfish is a joint venture with Enbridge Offshore Pipelines LLC, which the Company accounts for using the equity method. Starfish owns the FERC-regulated Stingray natural gas pipeline and the unregulated Triton natural gas gathering system and West Cameron dehydration facility, all located in the Gulf of Mexico and Southwestern Louisiana.

East Texas System Acquisition

On July 30, 2004, MarkWest Energy Partners completed the acquisition of American Central Eastern Texas’ Carthage gathering system located in east Texas (the “East Texas System”) for approximately $240.7 million. The Company’s condensed consolidated financial statements include the East Texas System’s results of operations from July 30, 2004. The assets acquired consist of gathering systems, compressor stations and a processing facility currently under construction, as well as a NGL pipeline currently under construction.

The total adjusted purchase price was $240.7 million, and was allocated as follows (in thousands):

Acquisition costs:
Cash consideration	$	240,269
Direct acquisition costs	457
Total	$	240,726

Allocation of acquisition costs:
Customer contracts	$	165,379
Property, plant and equipment	76,012
Inventory	65
Imbalance payable	(337		)
Property taxes payable	(393		)
Total	$	240,726

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 East Texas System and Starfish acquisitions had occurred on January 1, 2004. The unaudited pro forma results have been prepared for comparative purposes only and may not be indicative of future results.

	Nine Months Ended September 30, 2005
	MarkWest Hydrocarbon			Starfish		Adjustments (1)			Total
	(in thousands, except per share data)
Revenue	$	450,018		$	—	$	—		$	450,018
Net loss	$	(5,758	)	$	984	$	(957	)	$	(5,731	)
Net loss per share:
Basic	$	(0.53	)						$	(0.53	)
Diluted	$	(0.53	)						$	(0.53	)

	Three Months Ended September 30, 2004
	MarkWest Hydrocarbon			East Texas		Starfish		Adjustments (1)			Total
	(in thousands, except per share data)
Revenue	$	121,511		$	3,573	$	—	$	—		$	125,084
Net loss	$	(1,966	)	$	2,101	$	950	$	(3,582	)	$	(2,497	)
Net loss per share:
Basic	$	(0.18	)								$	(0.23	)
Diluted	$	(0.18	)								$	(0.23	)

	Nine Months Ended September 30, 2004
	MarkWest Hydrocarbon			East Texas		Starfish		Adjustments (1)			Total
	(in thousands, except per share data)
Revenue	$	304,235		$	20,679	$	—	$	—		$	324,914
Net loss	$	(7,619	)	$	9,328	$	3,042	$	(12,978	)	$	(8,227	)
Net loss per share:
Basic	$	(0.71	)								$	(0.77	)
Diluted	$	(0.71	)								$	(0.77	)

(1) Adjustments primarily for amortization and financing costs.

8. Related Party Transactions

Through the Company’s wholly owned subsidiary, Matrex, LLC, the Company holds interests in a few exploration and production assets in which MAK-J Energy Partners Ltd. (“MAK-J”) also owns interests. The general partner of MAK-J is a corporation owned and controlled by the Company’s former President and Chief Executive Officer and current Chairman of the Board of Directors.

The Company has receivables due from MAK-J, representing its share of operating and capital costs generated in the normal course of business, of $0.1 million and less than $0.1 million as of September 30, 2005 and December 31, 2004, respectively. The Company also has payables to MAK-J, representing its share of revenues generated in the normal course of business, of less than $0.1 million as of both September 30, 2005 and December 31, 2004.

9. Asset Retirement Obligations

In June 2001 the FASB issued SFAS 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 Company’s assets subject to asset retirement obligations are primarily certain gas gathering pipelines and processing facilities, a crude oil pipeline and other related pipeline assets operated by the Partnership.

The Partnership reviews applicable laws and regulations governing obligations for asset retirement obligations, as well as the leases. Based on the Partnership’s review, there are certain land leases in East Texas, Oklahoma, Appalachia and Other Southwest that require the Partnership to return the land to its original condition upon the termination of the lease. Based on the review of these leases, the Partnership recorded an asset retirement obligation of $0.5 million and $0.4 million during the nine months ended September 30, 2005 and 2004,

respectively, using an estimated average term of the leases of 25 years. Accretion expense for the nine months ended September 30, 2005 and 2004 was $0.1 million and less than $0.1 million, respectively.

In October 2003, the Board of Directors of the general partner approved a plan to shut down the existing Cobb processing plant and construct a replacement facility. Construction 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 shut down of the old Cobb facility to be $0.5 million and recorded an accrued liability. The Partnership began the process of shutting down the old Cobb facility during the third quarter of 2005. As a result, the Partnership settled $0.2 million of the liability in the three months ended September 30, 2005. The Partnership completed the decommissioning and dismantlement of the old Cobb facility in the fourth quarter of 2005. At September 30, 2005, the asset retirement obligation was $0.3 million.

At September 30, 2005 and 2004, there were no assets legally restricted for purposes of settling asset retirement obligations.

The following is a reconciliation of the Company’s asset retirement obligation activity for the nine months ended September 30, 2005 (in thousands):

Asset retirement obligation as of December 31, 2004	$	892
Liability accrued	479
Accretion	133
Liability settled	(159		)
Asset retirement obligation as of September 30, 2005	$	1,345

Current	$	291
Long-term	1,054
Asset retirement obligation as of September 30, 2005	$	1,345

10. Property, Plant and Equipment

Property, plant and equipment consists of:

	September 30, 2005			December 31, 2004
	(in thousands)
Property, plant and equipment:
Gas gathering facilities	$	201,541		$	160,763
Gas processing plants	58,218			56,239
Fractionation and storage facilities	22,531			22,112
Natural gas pipelines	38,167			38,167
Crude oil pipelines	19,451			18,499
NGL transportation facilities	4,425			4,381
Furniture, office equipment and other	3,701			4,113
Land, buildings and other equipment	10,371			9,418
Construction in progress	33,577			28,944
	391,982			342,636
Less: Accumulated depreciation, depletion, amortization and impairment	(73,219		)	(59,443		)
Total property, plant and equipment, net	$	318,763		$	283,193

The Company capitalized interest on construction in-progress, including amortization of deferred financing costs, of $0.5 million and $0.3 million for the three months ended September 30, 2005 and 2004, respectively, and $1.4 million and $0.3 million for the nine months ended September 30, 2005 and 2004, respectively.

	MarkWest Hydrocarbon Standalone			MarkWest Energy Partners			Eliminating Entries			Total
	(in thousands)
Three Months Ended September 30, 2005:
Revenues	$	56,078		$	130,568		$	(16,021	)	$	170,625
Purchased product costs	57,789			98,874			(10,787		)	145,876
Facility expenses	4,802			12,514			(5,234		)	12,082
Selling, general and administrative expenses	2,591			5,322			—			7,913
Depreciation	254			4,771			—			5,025
Amortization of intangible assets	—			2,098			—			2,098
Accretion of asset retirement and lease obligations	(1		)	117			—			116
Income (loss) from operations	(9,357		)	6,872			—			(2,485		)

Loss from unconsolidated subsidiary	—			(999		)	—			(999		)
Interest income	191			80			—			271
Interest expense	(30		)	(4,950		)	—			(4,980		)
Amortization of deferred financing costs (a component of interest expense)	(61		)	(496		)	—			(557		)
Dividend income	101			—			—			101
Other income	47			18			—			65
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	$	(9,109	)	$	525		$	—		$	(8,584	)

September 30, 2005:
Cash, cash equivalents and restricted cash	$	7,113		$	10,045		$	—		$	17,158
Marketable securities	15,307			—			—			15,307
Current assets	84,983			65,822			—			150,805
Current liabilities	42,014			63,440			—			105,454
Total assets	89,878			595,598			—			685,476
Total debt	—			310,500			—			310,500

	MarkWest Hydrocarbon Standalone			MarkWest Energy Partners			Eliminating Entries			Total
	(in thousands)
Three Months Ended September 30, 2004:
Revenues	$	59,040		$	77,842		$	(15,371	)	$	121,511
Purchased product costs	52,564			51,716			(9,071		)	95,209
Facility expenses	6,201			8,497			(6,300		)	8,398
Selling, general and administrative expenses	2,929			4,323			—			7,252
Depreciation	303			4,207			—			4,510
Amortization of intangible assets	—			1,400			—			1,400
Accretion of asset retirement and lease obligations	—			13			—			13
Income (loss) from operations	(2,957		)	7,686			—			4,729

Loss from unconsolidated subsidiary	—			(32		)	—			(32		)
Interest income	167			13			—			180
Interest expense	(24		)	(3,715		)	—			(3,739		)
Amortization of deferred financing cost (a component of interest expense)	(64		)	(3,056		)	—			(3,120		)
Dividend income	86			—			—			86
Other income (expense)	766			(181		)	—			585
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	$	(2,026	)	$	715		$	—		$	(1,311	)

September 30, 2004:
Cash, cash equivalents and restricted cash	$	11,721		$	13,587		$	—		$	25,308
Marketable securities	12,205			—			—			12,205
Current assets	73,452			38,342			—			111,794
Current liabilities	40,510			31,831			—			72,341
Total assets	79,709			474,048			—			553,757
Total debt	—			197,500			—			197,500

	MarkWest Hydrocarbon Standalone			MarkWest Energy Partners			Eliminating Entries			Total
	(in thousands)
Nine Months Ended September 30, 2005:
Revenues	$	173,386		$	323,165		$	(46,533	)	$	450,018
Purchased product costs	159,340			233,521			(29,932		)	362,929
Facility expenses	15,723			33,205			(16,601		)	32,327
Selling, general and administrative expenses	8,653			16,487			—			25,140
Depreciation	1,088			13,673			—			14,761
Amortization of intangible assets	—			6,288			—			6,288
Accretion of asset retirement and lease obligations	1			136			—			137
Income (loss) from operations	(11,419		)	19,855			—			8,436

Loss from unconsolidated subsidiary	—			(9		)	—			(9		)
Interest income	631			210			—			841
Interest expense	(91		)	(13,182		)	—			(13,273		)
Amortization of deferred financing costs (a component of interest expense)	(183		)	(1,468		)	—			(1,651		)
Dividend income	289			—			—			289
Other income	244			56			—			300
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	$	(10,529	)	$	5,462		$	—		$	(5,067	)

Nine Months Ended September 30, 2004:
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
Selling, general and administrative expenses	8,291			9,346			—			17,637
Depreciation	1,042			10,653			—			11,695
Amortization of intangible assets	—			1,468			—			1,468
Accretion of asset retirement and lease obligations	—			13			—			13
Income (loss) from operations	(10,790		)	15,793			—			5,003

Loss from unconsolidated subsidiary	—			(49		)	—			(49		)
Interest income	502			34			—			536
Interest expense	(33		)	(5,759		)	—			(5,792		)
Amortization of deferred financing cost (a component of interest expense)	(55		)	(3,679		)	—			(3,734		)
Dividend income	169			—			—			169
Other income (expense)	798			(202		)	—			596
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	$	(9,409	)	$	6,138		$	—		$	(3,271	)

13. Commitments and Contingencies

Legal

The Company and several of its affiliates were served earlier in 2005 with two lawsuits presently under the jurisdiction of the U.S. District Court for the Eastern District of Kentucky, Pikeville Division. In early November 2005,

we were served with an additional lawsuit filed in Floyd County Circuit Court, Kentucky, adding five new claimants, but essentially alleging the same facts and claims as the earlier two suits. These suits are for third-party claims of property and personal injury damages sustained as a consequence of a NGL pipeline leak and an ensuing explosion and fire that occurred on November 8, 2004 from a natural gas pipeline, owned by an unrelated business entity, and leased and operated by the Partnership’s subsidiary, MarkWest Energy Appalachia, LLC. The pipeline transports NGLs from the Maytown gas processing plant to the Partnership’s Siloam fractionator. An ignition and fire from the leaked vapors resulted in property damage to five homes and injuries to some of the residents. The cause of the pipeline split, leak, and resulting explosion and fire is being investigated by the pipeline owner, the U.S. Department of Transportation, Office of Pipeline Safety (“OPS”) and the Partnership.

The Company and the Partnership have timely notified their general liability insurance carriers of the incident and of the filed Kentucky actions and is coordinating the defense of these third-party lawsuits with the insurers. At this time, the Company and the Partnership believe that they have adequate general liability insurance coverage for third-party property damage and personal injury liability resulting from the incident. To date, the Company and the Partnership have settled with several of the claimants for third-party property damage claims (damage to residences and personal property) related to this incident, in addition to reaching settlement for some of the personal injury claims related to the pipeline explosion and fire. These settlements have been paid for or reimbursed under the Partnership’s general liability insurance. As a result, the Company has not provided for a loss contingency.

Pursuant to OPS regulation mandates and to a Corrective Action Order issued by the OPS immediately after the incident, pipeline and valve integrity evaluation, testing and repair efforts were required and conducted on the affected pipeline segment before service could be resumed. Partial return to service of the affected pipeline began in October 2005. The Company and the Partnership have filed an independent action against their All-Risk Property and Business Interruption insurance carriers as a result of their refusal to honor their insurance coverage obligation for providing the Company and the Partnership insurance payments for certain expenses. These expenses related to the Partnership’s internal expenses and costs incurred for damage to, and loss of use of, the pipeline, equipment, products, the extra transportation costs incurred for transporting the liquids while the pipeline was out of service, the reduced volumes of liquids that could be processed, and the costs of complying with the OPS Corrective Action Order (hydrostatic testing, repair/replacement and other pipeline integrity assurance measures). These expenses and costs have been expensed as incurred and any potential recovery from the All-Risks Property and Business Interruption insurance carriers will be treated as “other income” if they are received. The Partnership has not provided for a receivable related to these claims because of the uncertainty as to whether and how much the Company and the Partnership will ultimately recover under the All-Risks Property and Business Interruption insurance policies. In addition to the property and business losses and interruption costs, through September 30, 2005, the Partnership has incurred pipeline testing, refurbishment and replacements costs of approximately $5.1 million, of which $1.3 million has been capitalized. The Partnership’s current estimate is that the full cost of pipeline testing, repair and improvements will be approximately $7.0 million, of which approximately $1.7 million will be capitalized. The Company and the Partnership have also asserted that the costs associated with such testing, replacement and repair are subject to an equal sharing arrangement with the owner of the pipeline, pursuant to the terms of the pipeline lease agreement.

The Company has also been involved in a lawsuit captioned Ross Bros. Construction v. MarkWest Hydrocarbon, Inc., (U.S. District Court Eastern District of Kentucky, Ashland Division, Civ. Action No. 01-CV-205). This lawsuit involved the construction of the Siloam Kentucky plant and a dispute as to the monetary value of additional work beyond the contract’s lump sum price performed by the contractor. This lawsuit involved a claim of approximately $0.7 million in extra costs. The Company was recently granted Summary Judgment on its defense asserting accord and satisfaction. In August 2005, Plaintiffs filed an appeal of the Summary Judgment to the U.S. Court of Appeals for the 6th Circuit. The Company believes that, while it is not able to predict the outcome of this matter, based on the judge’s discussion on the grant of the summary judgment and denial of Ross Brothers’ motion for reconsideration, it is probable that the Company will prevail in the appeal. As a result, the Company has not provided for a loss contingency.

Denver, Colorado, 2005. Claimants filed an arbitration proceeding against the Company seeking further payments out of a dispute and settlement over interests in certain wells in Colorado. The Company had transferred, via a purchase and sale agreement, any liability for any payments out of the settlement it had reached with claimants to a third party in the sale of certain of the Company’s oil and gas property interests. The Company has been in communication with the third-party purchaser and the third-party purchaser has admitted it has those liabilities under the purchase and sale agreement, and the Company believes the earlier settlement with the claimants precludes any of their claims. The Company does not believe there are material liabilities associated with this claim. As a result, the Company has not provided for a loss contingency.

In September 2005, a lawsuit captioned C.F. Qualia Operating, Inc. v. MarkWest Pinnacle, L.P., (District Court of Midland, Texas, 385th Judicial District, Case No. CV-45188), was served on the Partnership’s subsidiary, MarkWest Pinnacle, L.P., alleging breach of contract, fraud and breach of implied duty of good faith with respect to a dispute on volumes of gas purchased by the Partnership under a gas purchase agreement. Under the gas purchase agreement, MarkWest Energy Partners paid the Plaintiff based on volumes of gas measured at the wellhead (delivery point). Plaintiff claims that it is entitled to a prorated portion of any system gain, i.e., that it is to be paid for more gas than it actually sold and delivered to the Partnership. MarkWest Energy Partners has filed an Answer to the Complaint denying Plaintiff’s allegations and has asserted a counter-claim for declaratory judgment on the contract terms as being clear and unambiguous as to payment being limited to those volumes measured at the wellhead, that Plaintiff’s claims are without merit, and that the Partnership also may have overpaid Plaintiff based on, among other things, the wet versus dry Btu measurements. Discovery has not yet begun, and at this time, the Partnership is not able to predict the outcome of this matter. As a result, the Partnership has not provided for a loss contingency.

In the ordinary course of business, the Company is a party to various other legal actions. In the opinion of management, none of these actions, either individually or in the aggregate, will have a material adverse effect on the Company’s financial condition, liquidity or results of operations.

Lease Obligations

The Company has various non-cancelable operating lease agreements for equipment and office space expiring at various times through fiscal 2015. The Company’s minimum future lease payments under these operating leases as of September 30, 2005, are as follows (in thousands):

2005	$	1,588
2006	5,526
2007	2,643
2008	1,922
2009	1,511
2010 and thereafter	736
Total	$	13,926

The Company also has a commitment to purchase equipment of $0.7 million at September 30, 2005.

14. Subsequent Event – Javelina

On November 1, 2005, MarkWest Energy Partners completed the acquisition of 100% of the interests in the Javelina gas processing and fractionation facility, and related pipeline facilities located in Corpus Christi, Texas, from El Paso Corporation, Kerr-McGee Corporation, and Valero Energy Corporation for approximately $355.0 million (the “Javelina Acquisition”), plus $35.9 million for net working capital.

The gas processing facility was constructed in 1989 to process off-gas from six refineries in the Corpus Christi area, recovering up to 28,000 barrels per day of natural gas liquids, as well as hydrogen. The Javelina facility currently processes 125 to 130 MMcf/d of inlet gas.

MarkWest Energy Partners financed the Javelina acquisition through borrowing under its amended and restated credit agreement. The fourth amended and restated credit agreement provided for a $100.0 million revolving credit facility and a $400.0 million term loan. In addition to financing the acquisition, proceeds were used to retire the outstanding debt and provide for future liquidity requirements of the Partnership. The Partnership refinanced the debt incurred to complete the Javelina acquisition as more throughly discussed in Note 15 below. Permanent capital will be issued in amounts designed to bring the Partnership’s capital structure in line with its stated goal of less than 50% debt.

On November 9, 2005, the Partnership completed a private placement of 1,644,065 common units. The units were issued at a purchase price of $44.21 each, raising approximately $74.0 million, including the general partner’s contribution. On December 27, 2005, the Partnership completed a private placement of 574,714 common units. The units were issued at a purchase price of $43.50 each, raising approximately $25.0 million, including the general partner’s contribution. Proceeds from the equity placements were used to reduce borrowing under the revolver and to reduce the size of the term loan.

15. Subsequent Event –Debt

In October 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. In October, November, and December 2005, the Company entered into the first, second and third amendment to the credit agreement. The first amendment extended the term of the original agreement to November 15, 2005. The second amendments reduced the lending amount from $25.0 million to $16.0 million, of which $6.0 million of availability is committed to a letter of credit, leaving $10.0 million available for revolving loans. The second amendment also extended the term of the revolving credit to December 30, 2005. The third amendment extended the term of the revolving credit to January 31, 2006 and reduced the lending amount from $16.0 million to $13.5 million, of which $6.0 million of availability is committed to a letter of credit, leaving $7.5 million available for revolving loans. If the revolving credit is converted into a term loan, the term will be extended to December 29, 2006.

In connection with the credit facility, the Company 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; make acquisitions; engage in other businesses; enter into operating leases; enter into certain swap contracts; engage in transactions with affiliates; make dispositions; make restricted payments, distributions and redemptions and other usual and customary covenants. As of September 30, 2005, the Company had no outstanding borrowings from the credit facility. At December 31, 2005, the Company had no borrowing capacity. The credit facility also contains covenants requiring the Company to maintain a minimum net worth of $40.0 million plus 50% of proceeds of equity issued subsequent to October 25, 2004.

MarkWest Energy Partners

On November 1, 2005, the Partnership entered into the fourth amended and restated credit agreement, which provided for a maximum lending limit of $500.0 million for a term of one year. The credit facility included a revolving facility of $100.0 million and a $400.0 million term loan. On December 29, 2005, the Partnership entered into the fifth amended and restated credit agreement (“Partnership Credit Facility”), which provides for a maximum lending limit of $615.0 million for a five-year term. The credit facility includes a revolving facility of $250.0 million and a $365.0 million term loan. The credit facility is guaranteed by the Partnership and all of the Partnership’s subsidiaries and is collateralized by substantially all of the Partnership’s assets and those of its subsidiaries. The borrowings under the credit facility bear interest at a variable interest rate plus basis points that correspond to the ratio of the Partnership’s Consolidated Senior Debt (as defined in the Partnership Credit Facility) to Consolidated EBITDA (as defined in the Partnership Credit Facility), ranging from 0.50% to 1.50% for Base Rate loans, and 1.50% to 2.50% for Eurodollar Rate loans. The basis points will increase by 0.50% during any period (not to exceed 270 days) where the Partnership makes an acquisition for a purchase price in excess of $50.0 million (“Acquisition Adjustment Period”). Borrowings under the Partnership Credit Facility were used to finance, in part, the Javelina acquisition discussed in Note 14 above.

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

Management Overview of the Three and Nine Months Ended September 30, 2005

MarkWest Hydrocarbon reported a net loss of $5.7 million, or $(0.53) per diluted share, for the three months ended September 30, 2005, compared to a net loss of $2.0 million, or $(0.18) per diluted share, for the corresponding quarter of 2004. The Company also reported a net loss of $5.8 million, or $(0.53) per diluted share, for the nine months ended September 30, 2005, compared to a net loss of $7.6 million, or $(0.71) per diluted share, for the corresponding period of 2004.

MarkWest Hydrocarbon Standalone Results

For the three months ended September 30, 2005, the loss before non-controlling interest in net income of consolidated subsidiary and income taxes was $9.1 million, compared to a loss before non-controlling interest in net income of consolidated subsidiary and income taxes of $2.0 million for the corresponding quarter of 2004, an increase to the loss of $7.1 million, or (350%). The increase to the loss of $7.1 million was primarily attributable to an unfavorable mark-to-market adjustment of $7.8 million to replacement gas that resulted from a sharp increase to natural gas prices, offset by the favorable fuel reimbursement of $0.5 million at our Kenova, Cobb and Boldman facilities.

For the nine months ended September 30, 2005, the loss before non-controlling interest in net income of consolidated subsidiary and income taxes was $10.5 million, compared to a loss before non-controlling interest in net income of consolidated subsidiary and income taxes of $9.4 million for the corresponding nine months of 2004, an increase to the loss of $1.1 million, or (12%). The increase to the loss of $1.1 million was primarily attributable to an unfavorable mark-to-market adjustment of $8.5 million to replacement gas that resulted from a sharp increase to natural gas prices, offset by the favorable impact from an increase to NGL revenues, that benefited from an increase to prices despite a decline in volumes, in excess of associated purchased product costs of $6.9 million and a decrease to selling, general and administrative expenses of $0.3 million.

MarkWest Hydrocarbon Standalone’s primary source of growth is from the marketing of natural gas and NGLs, as well as quarterly distributions received from MarkWest Energy Partners. The Company owns 89% of the general partner of MarkWest Energy Partners. The general partner of MarkWest Energy Partners owns the 2% general partner interest and all of the incentive distribution rights. The incentive distribution rights entitle the Company to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. For the nine months ended September 30, 2005, the Company received $5.9 million in distributions for its subordinated units, and the general partner received $3.5 million, including $2.9 million representing payments on incentive distribution rights. For the nine months ended September 30, 2004, the Company received $5.2 million in distributions for its subordinated units, and the general partner received $0.9 million, including $0.7 million representing payments on incentive distribution rights.

MarkWest Energy Partners Results

For the three months ended September 30, 2005, the Partnership reported income before non-controlling interest in net income of consolidated subsidiary and income taxes of $0.5 million compared to $0.7 million for the corresponding quarter of 2004, a decrease of $0.2 million or (29%). The decrease is primarily due to increased facility and purchased product costs of $1.8 million related to the Partnership’s testing and repair program on the Appalachian Liquids Pipeline System (ALPS) as well as additional trucking costs for moving product while the line is out of service, a decrease in net operating margin (a non-GAAP financial measure) of $1.8 million in Appalachia from reduced volumes, and increased selling, general and administrative expenses of $1.0 million related to ongoing audit and compliance requirements and non-cash compensation expense. These items were partially offset by the addition of the Partnership’s East Texas System, which added $3.2 million and an increase of $1.0 million from improved gathering volumes on the Partnership’s Appleby system.

For the nine months ended September 30, 2005, the Partnership reported income before non-controlling interest in net income of consolidated subsidiary and income taxes of $5.5 million compared to $6.1 million for the

corresponding nine months of 2004. The decrease is primarily due to increased selling, general and administrative expenses of $7.1 million related to ongoing audit and compliance requirements and non-cash compensation expense, increased facility and purchased product costs of $5.8 million related to the Partnership’s testing and repair program on ALPS as well as additional trucking costs for moving product while the line is out of service, higher interest expense and deferred financings costs of $5.2 million to fund the Partnership’s 2004 and 2005 acquisitions, a decrease of $1.6 in net operating margin (a non-GAAP financial measure) generated from reduced volumes on the Partnership’s systems in Appalachia, and a decrease of $1.3 million in net operating margin (a non-GAAP financial measure) generated from reduced through put volumes on the Partnership’s systems in Michigan. These items were partially offset by the addition of the Partnership’s East Texas System, which added $15.4 million, an increase of $4.5 million from improved gathering volumes on the Partnership’s Appleby and Western Oklahoma systems and an increase in miscellaneous income and interest income of $0.4 million.

Testing and repair of the Appalachia pipeline commenced in the first quarter of 2005 and was completed during the fourth quarter of 2005. Through September 30, 2005, the Partnership has incurred pipeline testing, refurbishment and replacement costs of approximately $5.1 million, of which $1.3 million has been capitalized. Transportation costs have been approximately $0.7 million per quarter. The Partnership is seeking recovery under its business interruption insurance and has asserted that the costs associated with such testing, repairs and improvements are subject to a sharing arrangement with the owner of the pipeline pursuant to the terms of the pipeline lease agreement. These expenses and costs have been expensed as incurred and any potential recovery from the All-Risks Property and Business Interruption insurance carriers will be treated as “other income” if they are received.

On March 31, 2005, MarkWest Energy Partners acquired a 50% non-operating membership interest in Starfish Pipeline Company, LLC, from an affiliate of Enterprise Products Partners, L.P. for $41.7 million. Starfish owns the FERC-regulated Stingray natural gas pipeline, and the unregulated Triton natural gas gathering system and West Cameron dehydration facility, all located in the Gulf of Mexico and Southwestern Louisiana. The acquisition was financed through the Partnership’s existing credit facility.

Cash Dividend

On October 27, 2005, the Board of Directors of MarkWest Hydrocarbon declared a cash dividend of $0.125 per share of its common stock. The dividend was paid on November 22, 2005, to the stockholders of record as of the close of business on November 15, 2005. The ex-dividend date was November 11, 2005. Declaration of future dividends will be dependent upon the financial performance of the Company.

Our Business

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

We are an energy company primarily focused on increasing shareholder value by growing 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; and the gathering and transportation of crude oil. We also market natural gas and natural gas liquids (NGLs). We discontinued our exploration and production activities in 2003.

Our assets consist primarily of partnership interests in MarkWest Energy Partners. As of September 30, 2005, our partnership interests consisted of the following:

• 2,469,496 subordinated units, representing a 23% limited partner interest in the Partnership; and

• An 89% 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. This ownership interest excludes interest held by employees and directors but deemed owned by the Company through the Participation Plan.

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 lack of comparability within our results of operations across periods because of MarkWest Energy Partners’ significant and recent acquisition activity.

Our Relationship with MarkWest Energy Partners

We spun off the majority of our then-existing natural gas gathering and processing and NGL transportation, fractionation and storage assets into MarkWest Energy Partners in May 2002, just before the Partnership completed its initial public offering. At the time of its formation and initial public offering, we entered into four contracts with MarkWest Energy Partners whereby MarkWest Energy Partners provides midstream services in Appalachia for a fee. Additionally, MarkWest Energy Partners receives 100% of all fee and percent-of-proceeds consideration for the first 10 MMcf/d that it gathers and processes in Michigan. MarkWest Hydrocarbon retains a 70% net profits interest in the gathering and processing income earned on quarterly pipeline throughput in excess of 10 MMcf/d. In accordance with generally accepted accounting principles, MarkWest Energy Partners’ financial results are included in our condensed consolidated financial statements. All intercompany accounts and transactions are eliminated during consolidation. You should read Note 12 to our Condensed Consolidated Financial Statements, appearing earlier in this Form 10-Q, for further information regarding our two business segments: (i) MarkWest Energy Partners and (ii) MarkWest Hydrocarbon Standalone.

As a result of our contracts with MarkWest Energy Partners mentioned above, we accounted for 12% and 14% of the Partnership’s revenues, and 17% and 21% of its net operating margin (a non-GAAP financial measure) for the three and nine months ended September 30, 2005, respectively. This represents a decrease from the year ended December 31, 2004, during which MarkWest Hydrocarbon accounted for 20% of the Partnership’s revenues and 33% of its net operating margin (a non-GAAP financial measure). We expect to account for less of MarkWest Energy Partners’ business in the future as it continues to acquire assets and increase its customer and business diversification.

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

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

Our Contracts

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

financial measure) are positive under these contracts. In the event natural gas becomes more expensive on a Btu equivalent basis than NGL products, the cost of keeping the producer “whole” results in operating losses.

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

Our keep-whole contracts expose us to commodity price risk, both on the sales side (of NGLs) and on the purchase side (of natural gas), which in turn may increase the volatility of our marketing results and cash flows. We attempt to mitigate our commodity price risk through our hedging program. You should read Item 3, “Quantitative and Qualitative Disclosures about Market Risk” for further details about our commodity price risk management program.

MarkWest Energy Partners’ Contracts

The Partnership generates the majority of its revenues and net operating margin 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 the following 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 MarkWest Energy Partners earns from these contracts generally 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 Partnership’s contracts provide for minimum annual payments. If a sustained decline in commodity prices results in a decline in volumes, however, the Partnership’s revenues from these contracts would be reduced.

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

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

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

and its revenues and net operating margins (a non-GAAP financial measure) decrease as the price of natural gas increases relative to the price of NGLs.

• Other Gathering Arrangements. In these contracts, the Partnerships gather volumes under contracts with fee arrangements, which are unique to each 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 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 gathering system is operated more efficiently than specified per contract allowance, the Partnership is entitled to retain the difference for its own account.

• Condensate sales. During the gathering process, thermodynamic forces contribute to physical changes in 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 Partnership sells 100% of the condensate collected in the system at a monthly crude-oil index-based price and it retains the proceeds.

In its current areas of operations, MarkWest Energy Partners utilizes a combination of contract types. 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 Partnership’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. The Partnership’s contract mix and, accordingly, our 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 changes in mix will influence our financial results.

At September 30, 2005, MarkWest Energy Partners’ primary exposure to keep-whole contracts was limited to its Arapaho (Oklahoma) processing plant and its East Texas processing contracts. At the Arapaho plant inlet, the Btu content of the natural gas meets the downstream pipeline specification; however, the Partnership has the option of extracting NGLs when the processing margin environment is favorable. In addition, approximately half, as measured in volume, 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. 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, means the Partnership’s overall keep-whole contract exposure is limited to a portion of the operating costs of the plant.

Management evaluates contract performance on the basis of net operating margin (a non-GAAP financial measure), which is defined as income (loss) from operations, excluding facility cost, selling, general and administrative expense, depreciation, amortization, impairments and accretion of asset retirement and lease obligations. These charges have been excluded for the purpose of enhancing the understanding by both management and investors of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance for purposes of planning and forecasting future periods. Net operating margin (a non-GAAP financial measure) does not have any standardized definition and therefore is unlikely to be comparable to similar measures presented by other reporting companies. Net operating margin (a non-GAAP financial measure) results should not be evaluated in isolation of, or as a substitute for, our financial results prepared in accordance with United States GAAP. Our usage of net operating margin (a non-GAAP financial measure), and the underlying methodology in excluding certain charges, is not necessarily an indication of the results of operations that may be expected in the future, or that we will not, in fact, incur such charges in future periods.

For the nine months ended September 30, 2005 and 2004, the Partnership generated the following percentages of its revenues and net operating margin (a non-GAAP financial measure) from the following types of contracts:

	Fee-Based		Percent-of- Proceeds (1)		Percent-of- Index (2)		Keep-Whole (3)		Total
Nine Months Ended September 30, 2005:
Revenues	15	%	10	%	35	%	40	%	100	%
Net operating margin (a non-GAAP financial measure)	54	%	4	%	34	%	8	%	100	%

Nine Months Ended September 30, 2004:
Revenues	17	%	15	%	22	%	46	%	100	%
Net operating margin (a non-GAAP financial measure)	60	%	10	%	12	%	18	%	100	%

(1) Includes other types of contracts tied to NGL prices.

(2) Includes other types of contracts tied to natural gas prices.

(3) Includes other types of contracts tied to both NGL and natural gas prices.

Internal management uses the term “net operating margin” (a non-GAAP financial measure) as a unit of performance measurement. We calculate net operating margin (a non-GAAP financial measure) as the sum of income from operations, facility costs, selling, general and administrative costs, depreciation, amortization of intangible assets, impairments and accretion of asset retirement and lease obligations. The following is a reconciliation to the most comparable GAAP financial measure of this non-GAAP financial measure for the Company (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2005			2004		2005		2004
Revenues	$	170,625		$	121,511	$	450,018	$	304,235

Purchased product costs	145,876			95,209		362,929		247,960

Net operating margin (a non-GAAP financial measure)	24,749			26,302		87,089		56,275

Facility expenses	12,082			8,398		32,327		20,459
Selling, general and administrative expenses	7,913			7,252		25,140		17,637
Depreciation	5,025			4,510		14,761		11,695
Amortization of intangible assets	2,098			1,400		6,288		1,468
Accretion of asset retirement and lease obligations	116			13		137		13
Income (loss) from operations	$	(2,485	)	$	4,729	$	8,436	$	5,003

Items Affecting Comparability of Financial Results

Recent MarkWest Energy Partners Acquisition Activity

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

Results of Operations

Operating Data

	Three Months Ended September 30,		Nine Months Ended September 30,
	2005	2004	2005	2004

Marketing
NGL product sales (gallons)	33,003,000	42,904,000	116,484,000	130,132,000

Wholesale (1)
NGL product sales (gallons)	14,815,000	10,984,000	41,574,000	15,931,000

MarkWest Energy Partners
*Southwest:*
East Texas (2)
Gathering system throughput (Mcf/d)	330,000	246,600	313,000	246,600
NGL product sales (gallons)	38,362,000	12,268,000	88,958,000	12,268,000
Oklahoma
Foss Lake gathering system throughput (Mcf/d)	81,000	63,300	73,000	60,700
Arapaho NGL product sales (gallons)	14,506,000	12,174,000	46,180,000	28,686,000
Other
Appleby gathering systems throughput (Mcf/d)	38,000	24,500	33,000	23,300
Other gathering systems throughput (Mcf/d)	16,000	15,500	16,000	17,700
Lateral throughput volumes (Mcf/d) (3)	126,000	97,200	90,000	83,100

*Appalachia:*
Natural gas processed for a fee (Mcf/d) (4)	188,000	196,000	197,000	201,000
NGLs fractionated for a fee (Gal/d)	396,000	489,000	426,000	474,000
NGL product sales (gallons)	10,132,000	10,710,000	31,051,000	32,638,000

*Michigan:*
Natural gas volumes transported (Mcf/d)	6,500	12,300	6,700	12,800
NGL product sales (gallons)	1,391,000	2,453,000	4,447,000	7,557,000
Crude oil transported (Bbl/d)	14,100	15,100	14,100	14,800

NA – Not applicable.

(1)	Represents sales from our wholesale business. Volumes are for the period since the Company started the line of business in February 2004.
(2)	We acquired our East Texas System in late July 2004. Volumes are for the periods of time since we acquired the facility in 2004.
(3)	We acquired our Lubbock pipeline (a/k/a the PowerTex Lateral Pipeline) in September 2003 and our Hobbs lateral pipeline in April 2004. The Lubbock and Hobbs 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 lateral pipelines is excluded from this statistic.
*(4)*	*Includes throughput from our Kenova, Cobb, and Boldman processing plants.*

Three Months Ended September 30, 2005 Compared to the Three Months Ended September 30, 2004

	MarkWest Hydrocarbon Standalone			MarkWest Energy Partners			Eliminating Entries			Total
	(in thousands)
Three Months Ended September 30, 2005:
Revenues	$	56,078		$	130,568		$	(16,021	)	$	170,625
Purchased product costs	57,789			98,874			(10,787		)	145,876
Facility expenses	4,802			12,514			(5,234		)	12,082
Selling, general and administrative expenses	2,591			5,322			—			7,913
Depreciation	254			4,771			—			5,025
Amortization of intangible assets	—			2,098			—			2,098
Accretion of asset retirement and lease obligations	(1		)	117			—			116
Income (loss) from operations	(9,357		)	6,872			—			(2,485		)
Loss from unconsolidated subsidiary	—			(999		)	—			(999		)
Interest income	191			80			—			271
Interest expense	(30		)	(4,950		)	—			(4,980		)
Amortization of deferred financing costs (a component of interest expense)	(61		)	(496		)	—			(557		)
Dividend income	101			—			—			101
Other income	47			18			—			65
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	$	(9,109	)	$	525		$	—		$	(8,584	)
Three Months Ended September 30, 2004:
Revenues	$	59,040		$	77,842		$	(15,371	)	$	121,511
Purchased product costs	52,564			51,716			(9,071		)	95,209
Facility expenses	6,201			8,497			(6,300		)	8,398
Selling, general and administrative expenses	2,929			4,323			—			7,252
Depreciation	303			4,207			—			4,510
Amortization of intangible assets	—			1,400			—			1,400
Accretion of asset retirement and lease obligations	—			13						13
Income (loss) from operations	(2,957		)	7,686			—			4,729
Loss from unconsolidated subsidiary	—			(32		)	—			(32		)
Interest income	167			13			—			180
Interest expense	(24		)	(3,715		)	—			(3,739		)
Amortization of deferred financing cost (a component of interest expense)	(64		)	(3,056		)	—			(3,120		)
Dividend income	86			—			—			86
Other income (expense)	766			(181		)	—			585
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	$	(2,026	)	$	715		$	—		$	(1,311	)

	Three Months Ended September 30,
	2005			2004
	(in thousands)
Loss before non-controlling interest in net income of consolidated subsidiary and income taxes	$	(8,584	)	$	(1,311	)
Provision (benefit) for income taxes	(2,868		)	151
Non-controlling interest in net income of consolidated subsidiary	28			(504		)
Net loss	$	(5,688	)	$	(1,966	)

MarkWest Hydrocarbon Standalone

Revenues. Revenues decreased $3.0 million, or 5%, for the three months ended September 30, 2005 compared to the corresponding quarter of 2004. This was due primarily to an unfavorable mark-to market adjustment of $7.8 million offset by an increase in our wholesale propane marketing business revenue of $4.8 million.

Purchased Product Costs. Purchased product costs increased $5.2 million, or 10%, for the three months ended September 30, 2005 compared to the corresponding quarter of 2004 primarily due to $4.8 million of increased activity in our wholesale propane marketing business, that was introduced in February 2004. The remaining increase is attributable to an increase in price and volumetric activity.

Facility Expenses. Facility expenses decreased by approximately $1.4 million, or 23%, during the three months ended September 30, 2005 compared to corresponding quarter of 2004 primarily as a result of favorable fuel reimbursement at our Kenova, Cobb and Boldman facilities.

Selling, General and Administrative Expenses. Selling, general and administrative expenses decreased by $0.3 million, or 12%, during the three months ended September 30, 2005 compared to the corresponding quarter of 2004 as a result of a $0.2 million decrease in compensation expense attributed to the 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan and an increase to allocations of selling, general and administrative expenses to the Partnership.

Depreciation. The decrease in depreciation expense of less than $0.1 million, or 16%, during the three months ended September 30, 2005 compared to the corresponding quarter of 2004 was principally due to the full depreciation of a pipeline in Michigan in June 2005.

Interest Income. Interest income increased by less than $0.1 million, or 14%, during three months ended September 30, 2005 compared to the corresponding quarter of 2004 primarily due to an increase in interest earned on cash equivalents.

Interest Expense. Interest expense increased by less than $0.1 million during the three months ended September 30, 2005 compared to the corresponding quarter of 2004 primarily due to commitment fees related to the October 2004 credit facility.

Amortization of Deferred Financing Costs (a component of interest expense). The Company amortized approximately $0.1 million of deferred financing costs during the three months ended September 30, 2005 related to debt issuance costs incurred from the October 2004 credit facility. The increase in 2005 relative to the corresponding period in 2004 is attributable to debt refinancing completed in the last quarter of 2004. Deferred financing costs are being amortized over the terms of the related obligations, which approximates the effective interest method.

Dividend Income. Dividend income increased by less than $0.1 million, or 17%, during the three months ended September 30, 2005, compared to the corresponding quarter of 2004 as a result of the increase in investments in master limited partnerships.

Other Income. Other income decreased by $0.7 million, or 94%, during the three months ended September 30, 2005, compared to the corresponding quarter of 2004. During the fourth quarter of 2001, Enron Corporation and its subsidiaries (“Enron”) filed for bankruptcy protection. In response to this filing, we terminated all derivative contracts

MarkWest Energy Partners

Revenues. Revenues for the three months ended September 30, 2005 were higher by $52.7 million, or 68%, compared to the corresponding quarter of 2004 primarily due to the Partnership’s East Texas System acquisition, which added $17.6 million to the Partnership’s 2005 revenue. Revenue also increased during the three months ended September 30, 2005 relative to the corresponding quarter of 2004 due to increased well volumes contracted to the gathering system, higher crude oil prices enhancing condensate sales and higher processing margins in western Oklahoma of $21.1 million. In addition, Other Southwest revenues increased $14.2 million due to a 55% increase in natural gas volumes and natural gas prices, primarily on the Appleby gathering system. These items were partially offset by reductions in natural gas liquids sales volumes in Michigan from reduced throughput volumes on the natural gas wells on the systems.

Purchased Product Costs. Purchased product costs were higher during the three months ended September 30, 2005 by $47.2 million, or 91%, compared to the corresponding quarter of 2004. The increase was primarily as a result of an increase in purchased volumes and price increases in western Oklahoma and Other Southwest, primarily on the Appleby gathering system that produced incremental costs of $20.8 million and $12.8 million, respectively. The remainder of the increase was due to the Partnership’s late 2004 acquisition of the East Texas System, which increased its purchased product costs by $11.7 million. East Texas costs were impacted by the April 2005 consummation of gas purchase agreements to process product previously subject to service contracts. In addition, East Texas operations reflected three months of activity in 2005 compared to two months of activity in 2004 since the date of acquisition. A $0.19 per gallon increase to purchase prices and a $0.7 million increase to costs to transport product from our Maytown and Boldman plants to our Siloam fractionator, as a result of the November 2004 pipeline failure, partially offset by a 5.4% reduction to volumes, contributed to a $2.2 million increase in purchased product costs. These items were partially offset by a $0.3 million decrease in costs in Michigan due to a reduction in volumes available for natural gas liquids processing from production shortfalls.

Facility Expenses. Facility expenses increased approximately $4.0 million, or 47%, during the three months ended September 30, 2005 relative to the corresponding quarter of 2004 primarily due to the Partnership’s 2004 acquisition of the East Texas System, which added $1.2 million. The remainder of the increase is due to increased pipeline repair and maintenance costs in Appalachia of approximately $1.1 million, and increased fuel costs of approximately $1.2 million. The remainder of the increase is attributed to additional maintenance and rent expense due to additional compressors on our Oklahoma and Appleby systems.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased by $1.0 million, or 23%, during the three months ended September 30, 2005, compared to the corresponding quarter of 2004 primarily as a result of an increase in outside legal and finance of $0.3 million and audit and Sarbanes Oxley related costs of $0.2 million. Compensation expense from the Participation Plan increased by $0.1 million, from $0.4 million in 2004 to $0.5 million in 2005. In addition, insurance expense increased by $0.2 million.

Depreciation. Depreciation expense increased $0.6 million, or 13%, during the three months ended September 30, 2005, compared to the corresponding quarter of 2004 primarily due to the Partnership’s July 2004 East Texas System acquisition.

Amortization of Intangible Assets. Amortization expense increased $0.7 million during the three months ended September 30, 2005, compared to the corresponding quarter of 2004 primarily due to the East Texas System acquisition in July 2004. 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 $240.7 million. Of the total purchase price, $165.4 million was allocated to customer contracts, of which $2.1 million and $1.4 million were amortized during the three months ended September 30, 2005 and 2004, respectively.

Accretion of Asset Retirement and Lease Obligations. Accretion of asset retirement and lease obligations increased by $0.1 million, and is the result of recording an asset retirement obligation in the third quarter of 2005 of $0.5 million for new land leases in East Texas, Oklahoma, Appalachia and Other Southwest that require the Partnership to return the land to its original condition upon the termination of the lease.

Loss from Unconsolidated Subsidiary. Loss from unconsolidated subsidiary increased $1.0

Nine Months Ended September 30, 2005 Compared to the Nine Months Ended September 30, 2004

	MarkWest Hydrocarbon Standalone			MarkWest Energy Partners			Eliminating Entries			Total
	(in thousands)
Nine Months Ended September 30, 2005:
Revenues	$	173,386		$	323,165		$	(46,533	)	$	450,018
Purchased product costs	159,340			233,521			(29,932		)	362,929
Facility expenses	15,723			33,205			(16,601		)	32,327
Selling, general and administrative expenses	8,653			16,487			—			25,140
Depreciation	1,088			13,673			—			14,761
Amortization of intangible assets	—			6,288			—			6,288
Accretion of asset retirement and lease obligations	1			136			—			137
Income (loss) from operations	(11,419		)	19,855			—			8,436
Loss from unconsolidated subsidiary	—			(9		)	—			(9		)
Interest income	631			210			—			841
Interest expense	(91		)	(13,182		)	—			(13,273		)
Amortization of deferred financing costs (a component of interest expense)	(183		)	(1,468		)	—			(1,651		)
Dividend income	289			—			—			289
Other income	244			56			—			300
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	$	(10,529	)	$	5,462		$	—		$	(5,067	)
Nine Months Ended September 30, 2004:
Revenues	$	140,718		$	207,326		$	(28,438	)	$	304,235
Purchased product costs	124,036			148,940			(15,945		)	247,960
Facility expenses	18,139			21,113			(12,493		)	20,459
Selling, general and administrative expenses	8,291			9,346			—			17,637
Depreciation	1,042			10,653			—			11,695
Amortization of intangible assets	—			1,468			—			1,468
Accretion of asset retirement and lease obligations	—			13			—			13
Income (loss) from operations	(10,790		)	15,793			—			5,003
Loss from unconsolidated subsidiary	—			(49		)	—			(49		)
Interest income	502			34			—			536
Interest expense	(33		)	(5,759		)	—			(5,792		)
Amortization of deferred financing cost (a component of interest expense)	(55		)	(3,679		)	—			(3,734		)
Dividend income	169			—			—			169
Other income (expense)	798			(202		)	—			596
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes	$	(9,409	)	$	6,138		$	—		$	(3,271	)

MarkWest Hydrocarbon Standalone

Revenues. Revenues increased $32.7 million, or 23%, for the nine months ended September 30, 2005 compared to the corresponding period of 2004 primarily due to an increase in our wholesale propane marketing business revenue of $22.5 million. The wholesale propane marketing business began at the end of the first quarter of 2004. Revenues also increased due to an increase in NGL product sale prices, in excess of the impact that resulted from a decline in volumes, in Appalachia of $14.3 million. In addition, gas-marketing revenues increased $5.2 million due to an increase in price. Increases to revenues were offset by an $8.5 million unfavorable mark-to-market adjustment to replacement gas that resulted from a fulminant increase to natural gas prices, and a $0.8 decrease in Michigan operations that resulted primarily from a reduction to volumes.

Purchased Product Costs. Purchased product costs increased $35.3 million, or 28%, for the nine months ended September 30, 2005 compared to the corresponding period of 2004. The increase was primarily due to costs from our wholesale propane marketing business, introduced in February 2004, which added $22.5 million, and an increase in our Appalachian natural gas liquids business of $7.6 million, which resulted from of an increase in prices that was partially offset by a decrease in volumes. Purchased product costs also increased by $5.0 million as a result of an increase in gas marketing purchases due to an increase in prices that was partially offset by a decrease in volumes.

Facility Expenses. Facility expenses decreased by approximately $2.4 million, or 13%, during the nine months ended September 30, 2005 compared to corresponding period of 2004. The decrease was the result of a $1.1 million favorable fuel reimbursement at our Kenova, Cobb and Boldman facilities, a reduction to inventory losses at the Appalachia Liquids Pipeline System (ALPS) of $0.6 million, a net reduction to Siloam fractionation fees and Kenova and Boldman processing fees of $1.0 million, offset by an increase to inventory losses at Siloam of $0.3 million.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased by $0.4 million, or 4%, during the nine months ended September 30, 2005 compared to the corresponding period of 2004 as a result of the increase in compensation expense attributed to the Participation Plan and the 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan, partially offset by an increase to allocations of selling, general and administrative expenses to the Partnership.

Depreciation. The increase in depreciation expense of less than $0.1 million, or 4%, during the nine months ended September 30, 2005 compared to the corresponding period of 2004 was principally due to the increase in software and hardware additions associated with the upgrade of our information technology infrastructure; and the acceleration of depreciation of our facilities in Michigan to more closely match our declining reserves.

Interest Income. Interest income increased by $0.1 million, or 26%, during the nine months ended September 30, 2005 compared to the corresponding period of 2004 primarily due to an increase in interest earned on cash equivalents.

Interest Expense. Interest expense increased by $0.1 million during the nine months ended September 30, 2005 compared to the corresponding period of 2004 primarily due to commitment fees related to the October 2004 credit facility.

Amortization of Deferred Financing Costs (a component of interest expense). The Company amortized approximately $0.2 million of deferred financing costs during the nine months ended September 30, 2005 related to debt issuance costs incurred from the October 2004 credit facility. The increase in 2005 relative to the corresponding period of 2004 is attributable to debt refinancing completed in the last quarter of 2004. Deferred financing costs are being amortized over the terms of the related obligations, which approximates the effective interest method.

Dividend Income. Dividend income increased by approximately $0.1 million, or 71%, during the nine months ended September 30, 2005 compared to the corresponding period of 2004 as a result of the increase in investments in master limited partnerships. We began receiving distributions on the master limited partnerships in the second quarter of 2004.

MarkWest Energy Partners

Revenues. Revenues for the nine months ended September 30, 2005 were higher by $115.8 million, or 56%, compared to the corresponding period of 2004. The increase was primarily due to the Partnership’s July 30, 2004 East Texas System acquisition, that added $51.3 million to the Partnership’s 2005 revenue in excess of 2004. Revenues reflected nine months of activity during 2005 compared to two months of activity during 2004. Revenue also increased in western Oklahoma during the nine months ended September 30, 2005 relative to the corresponding period of 2004 due to increased well volumes contracted to the gathering system, higher crude oil prices enhancing condensate sales and higher liquids revenue that resulted from ethane recovery during 2005 versus ethane rejection during 2004 that contributed to incremental revenue of $42.0 million. In addition, Other Southwest revenues increased $21.3 million due to a 27% increase in natural gas volumes, primarily on the Appleby and Edwards gathering systems.

Purchased Product Costs. Purchased product costs were higher during the nine months ended September 30, 2005 by $84.6 million, or 57%, compared to the corresponding period of 2004 primarily. The combination of an increase in purchased volumes and price contributed to increases in western Oklahoma and Other Southwest, primarily Appleby and Edwards, of $36.7 million and $20.4 million, respectively. In addition, the increase was due to the Partnership’s July 30, 2004 East Texas System acquisition, which increased purchased product costs by $21.8 million. Purchased product costs in east Texas reflected nine months of activity during 2005 compared to two months of activity during 2004. Purchased product costs also increased $5.6 million in Appalachia as a result of a $0.17 per gallon increase to product costs associated with the Maytown percent-of-proceeds contract.

Facility Expenses. Facility expenses increased approximately $12.1 million, or 57%, during the nine months ended September 30, 2005 relative to the corresponding period of 2004 primarily due to the Partnership’s July 30, 2004 East Texas System acquisition, which added $6.3 million. Facility expenses reflected nine months of activity during 2005 compared to two months of activity during 2004. In addition, Appalachia facility expenses increased $4.8 million as a result of pipeline repair and maintenance costs of $3.8 million, and increased salary and utility expenses. A $0.8 million increase to western Oklahoma facility expenses was the result of additional utility and maintenance expenses associated with system expansion.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased by $7.1 million, or 76%, during the nine months ended September 30, 2005 compared to the corresponding period of 2004 as a result of the increase in incentive compensation expense of $2.6 million, and audit and Sarbanes-Oxley related costs of $1.6 million. In addition, the allocation of compensation expense from the Participation Plan increased by $1.6 million, outside legal and financial consulting services increased by $0.5 million, and insurance adjustment charges increased by $0.8 million.

Depreciation. Depreciation expense increased $3.0 million, or 28%, during the nine months ended September 30, 2005 compared to the corresponding period of 2004 primarily due to the Partnership’s July 30, 2004 East Texas System acquisition, which added $2.9 million. The remaining increase is the result of additions of compressors to the Butler Compressor Station and additional well connections to the system.

Amortization of Intangible Assets. Amortization expense increased $4.8 million during the nine months ended September 30, 2005 compared to the corresponding period of 2004 primarily due to the East Texas System acquisition in July 2004. 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 $240.7 million. Of the total purchase price, $165.4 million was allocated to customer contracts, of which $6.3 million and $1.5 million were amortized during the nine months ended September 30, 2005 and 2004, respectively.

Loss from Unconsolidated Subsidiary. Loss from unconsolidated subsidiary decreased by less than $0.1 million during the nine months ended September 30, 2005 compared to the corresponding period of 2004.

The losses were primarily attributable to the March 31, 2005 Starfish acquisition. The equity in earnings for the second quarter of 2005 of $1.0 million were offset by losses of approximately $1.0 million during the third quarter of 2005 that were the consequence of the adverse events that resulted from Hurricane Rita.

Interest Income. Interest income increased by $0.2 million during the nine months ended September 30, 2005 compared to the corresponding period of 2004 primarily due to an increase in interest earned on cash equivalents.

Interest Expense. Interest expense increased by $7.4 million, or 129%, during the nine months ended September 30, 2005 compared to the corresponding period of 2004. The increase was principally attributable to MarkWest Energy Partners’ increased outstanding debt from financing its July 30, 2004 East Texas System acquisition and associated capital expenditures to construct a new plant and its March 31, 2005, Starfish acquisition. In October 2004, the Partnership issued $225.0 million in senior notes and have borrowed $85.5 million under the Partnership’s credit facility during 2005.

Amortization of Deferred Financing Costs (a component of interest expense). Amortization of deferred financing costs decreased by $2.2 million, or 60%, during the nine months ended September 30, 2005 compared to the corresponding period of 2004. The decrease in the amortization of deferred financing costs is attributable to the write off of deferred financings costs associated with the Partnership’s debt refinancing completed in the third quarter of 2004 as well as a shorter amortization term in 2004 due to the then current nature of the Partnership’s debt. Deferred financing costs are being amortized over the terms of the related obligations, which approximates the effective interest method.

Other

Income Tax Provision (Benefit). The income tax benefit increased $3.3 million for the nine months ended September 30, 2005 compared to the corresponding period of 2004, due primarily to the decrease in net income before taxes. The Company bases the effective corporate tax rate for interim periods on the estimated annual effective corporate tax rate. The benefit for income taxes was $2.9 million and the provision for income taxes was $0.6 million for the nine months ended September 30, 2005 and 2004, respectively, resulting in effective income tax rates of 33.5% and (8.4)%, respectively.

Non-controlling Interest in Net Income of Consolidated Subsidiary. Non-controlling interest in net income of consolidated subsidiary for the nine months ended September 30, 2005 decreased by $0.2 million, or 4%, compared to the corresponding period of 2004 as a result of the decrease in earnings of MarkWest Energy Partners and an increase in ownership of non-controlling interests commensurate with private placements and public offerings to finance acquisitions.

Liquidity and Capital Resources

MarkWest Hydrocarbon

Our primary source of liquidity to meet operating expenses and fund capital expenditures is cash flow from operations, principally from the marketing of natural gas and NGLs, and quarterly distributions received from MarkWest Energy Partners. Based on current volume, price and expense assumptions, we expect cash flow from operations and distributions from the Partnership to fund our operations and capital expenditures in 2005. Most of our future capital expenditures are discretionary. During 2005, we have budgeted $0.8 million for capital expenditures, consisting principally of computer hardware and software.

As of September 30, 2005, we had an aggregate of $7.4 million of unrestricted cash and marketable securities, and restricted cash of $15.0 million (the restriction was subsequently removed on November 15, 2005), exclusive of MarkWest Energy Partner’s $10.0 million cash on hand. Exclusive of MarkWest Energy Partners, we had no outstanding debt through September 30, 2005. On January 21, 2005, our Board of Directors declared a quarterly cash dividend of $0.075 per share of our common stock. The dividend was paid on February 21, 2005, to the stockholders of record as of the close of business on February 9, 2005. We disbursed $0.8 million to pay this

dividend. On April 28, 2005, our Board of Directors declared a quarterly cash dividend of $0.10 per share of our common stock. The dividend was paid on May 23, 2005, to the stockholders of record as of the close of business on May 16, 2005. We disbursed $1.1 million to pay this dividend. On July 22, 2005, our Board of Directors declared a quarterly cash dividend of $0.10 per share of our common stock. The dividend was paid on August 22, 2005, to the stockholders of record as of the close of business on August 15, 2005. We disbursed $1.1 million to pay this dividend. On October 27, 2005, our Board of Directors announced that it declared a quarterly cash dividend of $0.125 per share of our common stock. The dividend was paid on November 22, 2005, to the stockholders of record as of the close of business on November 15, 2005. We disbursed approximately $1.4 million to pay this dividend.

We own 89% of the general partner of MarkWest Energy Partners, excluding interest held by certain employees and directors but deemed owned by the Company through the Participation Plan. The general partner of MarkWest Energy Partners owns the 2% general partner interest and all of the incentive distribution rights. The incentive distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they entitle us to receive 13% of all cash distributed in a quarter after each unit has received $0.55 for that quarter; 23% of all cash distributed after each unit has received $0.625 for that quarter; and 48% of all cash distributed after each unit has received $0.75 for that quarter. For the nine months ended September 30, 2005, we received $5.9 million in distributions from our subordinated units and $3.1 million from our general partner interest, of which $2.9 million represented payments on incentive distribution rights. For the year ending December 31, 2005, we expect to receive $7.9 million in distributions for our subordinated and common units (that will result from converting a portion of our subordinated units), and we expect the general partner to receive $4.9 million, or an aggregate of $12.8 million.

Cash flows generated from our marketing operations are subject to volatility in energy prices, especially prices for NGLs and natural gas. Our cash flows are enhanced in periods when the prices received for NGLs are high relative to the price of natural gas we purchase to satisfy our “keep-whole” contractual arrangements in Appalachia. Conversely, they 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 energy content of the NGLs removed through the re-delivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas. Generally, the value of the NGLs extracted is greater than the cost of replacing those Btus with dry gas, resulting in positive operating margins under these contracts. Periodically, natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, and the cost of keeping the producer “whole” can result in operating losses. We entered into several new and amended agreements in September 2004 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. Under these agreements, the Company is limited on the costs it would have to pay to the producer should natural gas becomes more expensive than the NGL product sales price, thereby mitigating the risk of incurring operating losses. In connection with these agreements, we paid $3.3 million of consideration to the producer that is being amortized as additional cost of the gas purchased over the term of the contracts, October 1, 2004, through February 9, 2015.

Debt

In October 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. In October, November, and December 2005, the Company entered into the first, second and third amendment to the credit agreement. The first amendment extended the term of the original agreement to November 15, 2005. The second amendment reduced the lending amount from $25.0 million to $16.0 million, of which $6.0 million of availability is committed to a letter of credit, leaving $10.0 million available for revolving loans. The second amendment also extended the term of the revolving credit to December 30, 2005. The third amendment extended the term of the revolving credit to January 31, 2006 and reduced the lending amount from $16.0 million to $13.5 million, of which $6.0 million of availability is committed to a letter of credit, leaving $7.5 million available for revolving loans. If the revolving credit is converted into a term loan, the term will be extended to December 29, 2006.

In connection with the credit facility, the Company is subject to a number of limitations on its business, including restrictions on its ability to grant liens on assets; merge, consolidate or sell assets; incur indebtedness; make acquisitions; engage in other businesses; enter into operating leases; enter into certain swap contracts; engage in transactions with affiliates; make disposition; make restricted payments, distributions and redemptions and other usual and customary covenants. As of September 30, 2005, the Company had no outstanding borrowings. At December 31, 2005, the Company had no borrowing capacity. The credit facility also contains covenants requiring the Company to maintain a minimum net worth of $40.0 million plus 50% of proceeds of equity issued subsequent to October 25, 2004.

Liquidity Requirements

We have spent $0.3 million for capital expenditures through September 30, 2005. We have budgeted $0.2 million for the fourth quarter of 2005, consisting principally of computer hardware and software. We believe that cash on hand, cash received from quarterly distributions (including the incentive distribution rights) from MarkWest Energy Partners, and projected cash generated from our marketing operations will be sufficient to meet our working capital requirements and fund our required capital expenditures, if any, for the next twelve months. Cash generated from our marketing operations will depend on our operating performance, which will be affected by prevailing commodity prices and other factors, some of which are beyond our control.

MarkWest Energy Partners

Overview

The Partnership’s primary source of liquidity to meet operating expenses and fund capital expenditures (other than for larger acquisitions) is cash flow generated by operations. The public and institutional markets have been the Partnership’s principal source of capital to finance a significant amount of its growth (including acquisitions). During the first quarter of 2005 the Partnership borrowed $40.0 million from its credit facility to finance the acquisition of a 50% non-operating membership interest in Starfish Pipeline Co. LLC. Starfish owns the FERC-regulated Stingray natural gas pipeline, and the unregulated Triton natural gas gathering system and West Cameron dehydration facility, all located in the Gulf of Mexico and southwestern Louisiana. During the nine months ended September 30, 2005, we spent $50.2 million on capital expenditures, primarily for the construction of a new processing plant and gathering systems in East Texas to handle future contractual commitments. On November 1, 2005, we acquired a 100% interest in the Javelina gas processing and fractionation facility in Corpus Christi, Texas, for approximately $355.0 million. We borrowed approximately $500.0 million: $355.0 million to finance Javelina, $45.0 million for working capital adjustments and $100.0 million to retire long-term debt from the predecessor revolving credit facility. On November 1, 2005, the available borrowing capacity under the Partnership Credit Facility was $43.0 million.

As of September 30, 2005, the Partnership spent $50.2 million on capital expenditures exclusive of any acquisitions. As of September 30, 2005, the Partnership has budgeted $23.2 million for capital expenditures for the remainder of 2005, exclusive of any acquisitions, consisting of $22.6 million for expansion capital and $0.6 million for sustaining capital. Expansion capital includes expenditures made to expand or increase the efficiency of the existing operating capacity of the Partnership’s assets, or facilitate an increase in volumes within operations, whether through construction or acquisition. Sustaining capital includes expenditures to replace partially or fully depreciated assets in order to extend their useful lives.

Equity

On November 9, 2005, the Partnership completed a private placement of 1,644,065 common units. The units were issued at a purchase price of $44.21 each, raising approximately $74.0 million, including the general partner’s contribution. On December 27, 2005, the Partnership completed a private placement of 574,714 common units. The units were issued at a purchase price of $43.50 each, raising approximately $25.0 million, including the general partner’s contribution. The permanent capital was issued to bring the Partnership’s capital structure in line with the Partnership’s stated goal of less than 50% debt.

The inability of the Partnership to file its Annual Report on Form 10-K for the year ended December 31, 2004, and its quarterly report on Form 10-Q for the quarterly period ending March 31, 2005, may influence the timing of the Partnership’s efforts to raise equity in the future. The Partnership no longer has the ability to incorporate by reference information from its filings into a new registration statement for one year following the date the Partnership became current with its filings, or October 11, 2005, if the Partnership seeks to raise capital through a public offering of registered debt or equity securities. The Partnership intends to raise additional capital through public debt or equity offerings. As a result, the Partnership will be required to file a Form S-1, which is a long form type of registration statement. The requirement to file a Form S-1 may affect the Partnership’s ability to access the capital markets on a timely basis and may increase the costs of doing so.

The Partnership has the ability to issue an unlimited number of units to fund immediately accretive acquisitions. Under the provisions of the Partnership Agreement, an immediately accretive acquisition is one that in the general partner’s good faith determination would have, if acquired by the Partnership as of the date that is one year prior to the first day of the quarter in which such acquisition is consummated, resulted in an increase to the amount of operating surplus generated by the Partnership on a per-unit basis (for all outstanding units) with respect to each of the four most recently completed quarters (on a pro forma basis) as compared to the actual amount of operating surplus generated by the Partnership on a per-unit basis (for all outstanding units), excluding operating surplus generated by the Partnership on a per-unit basis (for all outstanding units), excluding operating surplus attributable to the acquisition with respect to each of such four most recently completed quarters. For acquisitions that are not immediately accretive, the Partnership has the ability to issue up to 1,207,500 common units without unitholder approval.

Debt

The Partnership’s $200.0 million credit facility was established to fund capital expenditures and acquisitions, working capital requirements (including letters of credit) and distributions to unitholders. Advances to fund distributions to unitholders may not exceed $0.50 per outstanding unit in any 12-consecutive-month period. To date there have been no such advances. At September 30, 2005, the Partnership had borrowed $85.5 million, $40.0 million to finance its investment in Starfish in March 2005 and $45.5 million to fund capital expenditures. In November 2005 we amended and restated the Partnership’s credit facility, decreasing the maximum lending limit from $200.0 million to $100.0 million and decreasing the term of the facility to one year, due October 31, 2006. We also entered into a $400.0 million term loan due October 31, 2006. On December 29, 2005, the Partnership entered into the fifth amended and restated credit agreement, which provides for a maximum lending limit of $615.0 million for a five-year term. The credit facility includes a revolving facility of $250.0 million and a $365.0 million term loan. The term loan portion of the facility is paid in quarterly installments of 1% a year on the last business day of March, June, September and December with the remaining balance payable on December 29, 2010. The revolver portion of the facility matures on December 29, 2010.

Conditions of the Partnership’s credit facility mean we are subject to a number of restrictions on our business. These include restrictions on our ability to grant liens on assets; make or own certain investments; enter into any swap contracts other than in the ordinary course of business; merge, consolidate or sell assets; incur indebtedness (other than subordinated indebtedness); make acquisitions; engage in other business; enter into capital or operating leases; engage in transactions with affiliates; make distributions on equity interests; declare or make, directly or indirectly any restricted payment and other usual and customary covenants.

The Partnership and its subsidiary, MarkWest Energy Finance Corporation, also have $225.0 million in senior notes at a fixed rate of 6.875% outstanding at September 30, 2005. The notes mature on November 2, 2014. Subject to compliance with certain covenants, we may issue additional notes from time to time under the indenture pursuant to Rule 144A and Regulation S under the Securities Act of 1933. The proceeds from these notes were used to pay down the outstanding debt under the Partnership’s credit facility in October 2004.

The indenture governing the senior notes limits the activity of the Partnership and its restricted subsidiaries. The provisions of such indenture places limits on the ability of the Partnership and its restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions or redeem, repurchase or retire equity interests or subordinated indebtedness; make investment; incur liens; create any consensual limitation on the ability of the Partnership’s restricted subsidiaries to pay dividends, make loans or transfer property to the Partnership; engage in transactions with the Partnership’s affiliates; sell assets, including equity interest of the Partnership’s subsidiaries; make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and

consolidate, merge or transfer assets.

The Partnership has agreed to file an exchange offer registration statement; or, under certain circumstances, a shelf registration statement, pursuant to a registration rights agreement relating to the 2004 senior notes. The Partnership failed to complete the exchange offer in the time provided for in the subscription agreements (April 26, 2005) and, as a consequence, is incurring an interest rate penalty of 0.5%, increasing 0.25% every 90 days thereafter up to 1%, until such time as the exchange offer is completed. The Partnership is currently being charged an interest rate penalty of 1%.

Liquidity Requirements

The Partnership has budgeted $23.2 million for capital expenditures for the fourth quarter of 2005, exclusive of any acquisitions, consisting of $22.6 million for expansion capital and $0.6 million for sustaining capital. Expansion capital includes expenditures made to expand or increase the efficiency of the exiting operating capacity of the Partnership’s assets, or facilitate an increase in volumes within operations, whether through construction or acquisition. Sustaining capital includes expenditures to replace partially or fully depreciated assets in order to extend their useful lives.

We believe that the Partnership’s available cash provided by operating activities and funds available under the Partnership’s credit facility will be sufficient to fund the Partnership’s operating, interest and general and administrative expenses; the Partnership’s capital expenditures budget; short-term contractual obligations; and distribution payments at current levels for the foreseeable future. However, the Partnership’s ability to finance additional acquisitions will likely require the issuance of additional common units, the expansion of the credit facility, additional debt financing or a combination thereof. In the event that the Partnership desires or needs to raise additional capital, we cannot guarantee that additional funds will be available at times or on terms favorable to the Partnership, if at all.

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

Cash Flows

	Nine Months Ended September 30,
	2005			2004
	(in thousands)

Net cash provided by operating activities	$	23,282		$	15,521
Net cash used in investing activities	$	(91,997	)	$	(270,930	)
Net cash provided by financing activities	$	58,029		$	243,912

Net cash provided by operating activities was higher during the nine months ended September 30, 2005, than during the corresponding period of 2004, primarily due to increased activities as a result of the Partnership’s East Texas System acquisition. The increase is also attributable to higher processing margins and volumes from the Partnership’s Oklahoma segment.

Net cash used in investing activities during the nine months ended September 30, 2005, consisted primarily of the $41.7 million Starfish acquisition, capital expenditures of $50.4 million for existing facilities and $8.7 million for investments in marketable securities, net of $8.5 million from sales of marketable securities. Net cash used in investing activities during the nine months ended September 30, 2004 was primarily due to the $240.1 million East Texas System acquisition and the $2.3 million Hobbs acquisition, capital expenditures of $12.7 million for existing facilities, $3.3 million for a contract to reduce exposure to commodity price risk and $11.9 million for investment in marketable securities.

Net cash provided by financing activities during the nine months ended September 30, 2005, consisted

primarily of proceeds from long-term debt in excess of repayments of $85.5 million, payments of debt issuance costs of $5.1 million, distributions by Markwest Energy Partners of $19.4 million to unitholders other than MarkWest Hydrocarbon and the general partner, and cash dividends paid to shareholders of $3.0 million. Net cash used in financing activities during the nine months ended September 30, 2004, consisted primarily of proceeds from long-term debt in excess of repayments of $71.3 million; payments of debt issuance costs of $7.2 million; proceeds from MarkWest Energy Partners’ secondary public offerings of $140.0 million and private placements of $44.1 million, distributions by Markwest Energy Partners of $9.4 million to unitholders other than MarkWest Hydrocarbon and the general partner; proceeds from stock option exercises of $1.4 million and cash dividends paid to shareholders of $5.3 million.

Total Contractual Cash Obligations

A summary of our total contractual cash obligations as of September 30, 2005, is as follows, in thousands:

	Payment Due by Period
Type of obligation	Total obligation		Due in 2005		Due in 2006-2007		Due in 2008-2009		Thereafter

Long-term debt (1)	$	472,327	$	5,180	$	41,437	$	125,944	$	299,766
Operating leases	13,926		1,588		8,169		3,433		736
Purchase obligations	663		663		—		—		—
Total contractual cash obligations	$	486,916	$	7,431	$	49,606	$	129,377	$	300,502

(1)	Includes interest on the Partnership’s 6.875% senior notes through 2014 of $140.5 million and interest on the Partnership’s 6.14% credit facility through 2009 of $21.3 million.

Matters Impacting Future Results

The Company and several of its affiliates were served earlier this year with two lawsuits presently under the jurisdiction of the U.S. District Court for the Eastern District of Kentucky, Pikeville Division. In early November 2005, we were served with an additional lawsuit filed in Floyd County Circuit Court, Kentucky, adding five new claimants, but essentially alleging the same facts and claims as the earlier two suits. These suits are for third-party claims of property and personal injury damages sustained as a consequence of a NGL pipeline leak and an ensuing explosion and fire that occurred on November 8, 2004 from a natural gas pipeline, owned by an unrelated business entity, and leased and operated by the Partnership’s subsidiary, MarkWest Energy Appalachia, LLC. The pipeline transports NGLs from the Maytown gas processing plant to the Partnership’s Siloam fractionator. An ignition and fire from the leaked vapors resulted in property damage to five homes and injuries to some of the residents. The cause of the pipeline split, leak, and resulting explosion and fire is being investigated by the pipeline owner, the U.S. Department of Transportation, Office of Pipeline Safety (“OPS”), and the Partnership.

the Partnership’s internal expenses and costs incurred for damage to, and loss of use of, the pipeline, equipment, products, the extra transportation costs incurred for transporting the liquids while the pipeline was out of service, the reduced volumes of liquids that could be processed, and the costs of complying with the OPS Corrective Action Order (hydrostatic testing, repair/replacement and other pipeline integrity assurance measures). These expenses and costs have been expensed as incurred and any potential recovery from the All-Risks Property and Business Interruption insurance carriers will be treated as “other income” if they are received. The Partnership has not provided for a receivable related to these claims because of the uncertainty as to whether and how much the Company and the Partnership will ultimately recover under the All-Risks Property and Business Interruption insurance policies. In addition to the property and business losses and interruption costs, through September 30, 2005, the Partnership has incurred pipeline testing, refurbishment and replacements costs of approximately $5.1 million, of which $1.3 million has been capitalized. The Partnership’s current estimate is that the full cost of pipeline testing, repair and improvements will be approximately $7.0 million, of which approximately $1.7 million will be captialized. The Company and the Partnership have also asserted that the costs associated with such testing, replacement and repair are subject to an equal sharing arrangement with the owner of the pipeline, pursuant to the terms of the pipeline lease agreement.

The Company has also been involved in an arbitration proceeding captioned Kevin Stowe and Scott Daves v. MarkWest Hydrocarbon, Inc., American Arbitration Association arbitration, Case No. 77 168 Y 0052 05 BEAH, Denver, Colorado, 2005. Claimants filed an arbitration proceeding against the Company seeking further payments out of a dispute and settlement over interests in certain wells in Colorado. The Company had transferred, via a purchase and sale agreement, any liability for any payments out of the settlement it had reached with claimants to a third party in the sale of certain of the Company’s oil and gas property interests. The Company has been in communication with the third-party purchaser and the third-party purchaser has admitted it has those liabilities under the purchase and sale agreement, and the Company believes the earlier settlement with the claimants precludes any of their claims. The Company does not believe there are material liabilities associated with this claim. As a result, the Company has not provided for a loss contingency.

In response to a shipper inquiry to the Federal Energy Regulatory Commission (“FERC”) regarding the Partnership’s Michigan Crude Pipeline, and following unsuccessful FERC-requested rate structure discussions with the shippers, FERC recently requested that we file a tariff. The Partnership filed a tariff with FERC establishing a cost of service rate structure to be effective starting January 1, 2006. Two shippers and a producer filed a joint protest to the FERC filing with the Commission, and the Partnership filed a response to this joint protest vigorously

defending its filing and opposing the protest. The Commission issued an order on December 29, 2005, rejecting the protestor’s request for interim rates and accepting the Partnership’s filing, and the new rates and rate structure become effective January 1, 2006. The Commission established hearing procedures for the tariff filing, but held them in abeyance pending the outcome of FERC sponsored settlement discussions, which the parties have been referred to under the FERC procedures. However, the Partnership cannot predict whether the FERC tariff protest or any settlement will adversely affect its Michigan Crude Pipeline results of operations.

The Partnership has a 50% non-operating ownership interest in Starfish Pipeline Company (“Starfish”). In connection with the impact of Hurricane Rita on the Starfish operations, based on our continuing discussions with the operator and other 50% owner of Starfish, Enbridge Offshore (Gas Transmission) L.L.C. (“Enbridge), the Partnership has been informed that initial onsite and aerial inspections indicated no material damage to the offshore platform facilities and that pipe integrity was not compromised. Sonar inspection of underwater pipe to assess sediment support and cover is pending. Some structural damage occurred at the onshore Starfish dehydration and compressor facilities, although it appears to be limited. However, due to damage from the hurricane, the electrical systems, control equipment and office buildings at the onshore facilities do require significant repair, which will continue through the first quart of 2006. Starfish operations have been substantially curtailed since shortly before the hurricane hit the Gulf Coast in September 2005, and until such repairs are completed Starfish is not able to return to normal operations and this will have a continuing impact operating income. Based on this preliminary information and without further update on the situation from Enbridge, we are unable to further estimate the ultimate impact of Hurricane Rita to 2005 net income, but we expect that the effect will be material. Our evaluation is subject to a number of factors including ongoing assessments, disclosures by operators of interconnecting production and processing facilities, and discussions with insurance carriers for insurance recovery for damages and business interruption.

Under the terms of certain gathering contracts in the Partnership’s East Texas systems, the Partnership is required to buy gas based on a specific index price. The Partnership’s typical process has been to sell its best estimate of the production at the same index price near the end of the prior month. Due to unexpected volatility and a corresponding lack of liquidity in the gas trading market at the end of October 2005, the Partnership was unable to sell all of its requirements at the same index price. As a result, the Partnership was not able to sell approximately 16,000 MMBtu/day of gas from its Appleby and East Texas assets for November 2005. During the month of November, the Partnership sold the gas at a different index price, which was lower than the index purchase price for the month. The Partnership cannot currently predict the exact financial impact, but based on its current estimate of volume and price, the Partnership expects a negative impact to operating income from operations of approximately $2.5 million from the Appleby and East Texas operations. The Partnership has implemented additional controls and procedures to mitigate a similar exposure going forward. The Partnership has sold 90% of its forecasted volumes through March 2006 at index price. The Partnership has also established firm guidelines to sell the remainder of forecast volumes earlier in the preceding month to reduce the risk of encountering unexpected market conditions that preclude these types of index sales.

Under the terms of the keep-whole agreements in the Partnership’s western Oklahoma System, the Partnership purchases gas to replace the shrink and fuel requirements under those arrangements. The Partnership then sells the natural gas liquids processed at the Foss Lake plant. The continued strong pricing environment for natural gas liquids, coupled with the decline in mid-continent natural gas prices in November, has resulted in higher- than-expected margins in the Partnership’s western Oklahoma System of approximately $1.0 million.

Recent Accounting Pronouncements

In December 2004 the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS No. 123(R)”). This statement addresses the accounting for share-based payment transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the enterprise, or (b) liabilities that are based on the fair value of the enterprise’s equity instruments or that may be settled by the issuance of such equity instruments. SFAS No. 123(R) requires an entity to recognize the grant-date fair-value of stock options and other equity-based compensation issued to employees in the income statement. The revised Statement generally requires that an entity account for those transactions using the fair-value-based method, and eliminates the intrinsic value method of accounting in APB Opinion No. 25, Accounting for Stock Issues to Employees, which was permitted under SFAS

Costless Collars:	Period	Floor		Cap
Crude Oil — 500 Bbl/d	2006	$	57.00	$	67.00
Crude Oil — 250 Bbl/d	2006	$	57.00	$	67.00
Crude Oil — 205 Bbl/d	2006	$	57.00	$	65.10

Propane — 10,000 Gal/d	2006	$	0.97	$	1.15
Propane — 20,000 Gal/d	2006	$	0.90	$	0.99
Propane — 12,750 Gal/d	Jan - June 2006	$	0.90	$	1.01

Ethane — 22,950 Gal/d	2006	$	0.65	$	0.80

Natural Gas — 1,575 Mmbtu/d	Jan - Mar 2006	$	9.00	$	11.40
Natural Gas — 1,575 Mmbtu/d	April - Oct 2006	$	8.50	$	10.05
Natural Gas — 1,575 Mmbtu/d	Nov - Mar 2007	$	9.00	$	12.50
Natural Gas — 645 Mmbtu/d	Jan - Mar 2006	$	8.86	$	15.21
Natural Gas — 645 Mmbtu/d	April - June 2006	$	6.71	$	12.46

Swaps		Fixed Price
Crude Oil — 250 Bbl/d	2006	$	62.00
Crude Oil — 185 Bbl/d	2006	$	61.00
Crude Oil — 250 Bbl/d	2007	$	65.30

While we expect these hedges to provide economic stability against the impact of changing commodity prices on our physical positions, for accounting purposes we will not designate these derivatives as cash flow hedges and will not apply hedge accounting. We will expand our disclosure around the resulting mark-to-market impacts.

Interest Rate Risk

MarkWest Energy Partners is exposed to changes in variable interest rates payable on $85.5 million of borrowings under its credit facility as of September 30, 2005, primarily as a result of its floating interest rates under this facility. For the nine months ended September 30, 2005, the weighted average interest rate on the credit facility was 6.14%. The carrying value of the credit facility approximates fair value because the facility bears interest at current market rates. As of September 30, 2005, floating-rate debt comprised 28% of total outstanding debt. The Partnership may make use of interest rate swap agreements in the future to adjust the ratio of fixed and floating rates in the debt portfolio. The Partnership also has fixed-rate senior notes payable of $225.0 million. At September 30, 2005, the fair value of the senior notes payable was approximately $222.8 million based on quoted market prices.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

In connection with the preparation of this quarterly report on Form 10-Q, 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, 2005, pursuant to Rule 13a-15 under the Securities Exchange Act of 1934. Based upon that evaluation, our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded that as of September 30, 2005, as a result of the material weaknesses in our internal control over financial reporting discussed below, our disclosure controls and procedures were ineffective to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 (the “Act”), is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms; and to ensure that information required to be disclosed by us in the reports that we file under the Act is accumulated and communicated to management, including our certifying officers, as appropriate to allow timely decisions regarding required disclosures.

Through the date of the filing of this Form 10-Q, we have adopted remedial measures to address the deficiencies in our internal controls that existed on September 30, 2005. In addition, we have applied compensating procedures and processes as necessary to ensure the reliability of our financial reporting. Such additional procedures include detailed management review of account reconciliations for all accounts in all business units, multiple-level management review of accounting treatment for significant non-routine transactions, and additional review at the Southwest Business Unit by Corporate personnel. Accordingly, management believes, based on its knowledge, that (i) this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstance under which they were made, not misleading with respect to the period covered by this report, and (ii) the financial statements, and other financial information included in this report, fairly present in all material respects our financial condition, results of operations and cash flows as of, and for, the periods presented in this report.

Changes in Internal Control over Financial Reporting

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

Material Weaknesses in Internal Control Over Financial Reporting

As of December 31, 2004, senior management concluded that we did not maintain effective internal control over financial reporting due to a number of material weaknesses. All of the material weaknesses discussed below were originally identified in management’s assessment of internal control that was conducted as of December 31, 2004.

Based on our evaluation, senior management has concluded that, as of September 30, 2005, we did not maintain effective internal control over financial reporting due to the following material weaknesses:

Ineffective Control Environment – Our control environment did not sufficiently promote effective internal control over financial reporting throughout our management structure, and this material weakness was a contributing factor in the development of other material weaknesses described below. Principal contributing factors included the lack of adequate personnel with sufficient expertise to perform accounting functions necessary to ensure preparation of financial statements in accordance with generally accepted accounting principles, and a lack of adequate policies and procedures to enable the timely preparation of reliable financial statements, as described more fully below.

To date, we have taken the following steps to remediate this material weakness:

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


PART I—FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (unaudited)
Condensed Consolidated Balance Sheets at September 30, 2005 and December 31, 2004
Condensed Consolidated Statements of Operations for the Quarters Ended September 30, 2005 and 2004
Condensed Consolidated Statements of Operations for the Nine Months Ended September 30, 2005 and 2004
Condensed Consolidated Statements of Comprehensive Loss for the Quarters and Nine Months Ended September 30, 2005 and 2004
Condensed Consolidated Statement of Changes in Stockholders’ Equity for the Nine Months Ended September 30, 2005
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2005 and 2004
Notes to the Condensed Consolidated Financial Statements

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Item 4. Controls and Procedures

PART II—OTHER INFORMATION

Item 1. Legal Proceedings
Item 6. Exhibits

SIGNATURE

Natural gas swaps:
Natural gas MMBtu	46,000
Natural gas sales price per MMBtu	$	4.26

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 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.

31.3		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.

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

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

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

		MarkWest Hydrocarbon, Inc.
			(Registrant)

Date: January 10, 2006	/s/ Nancy K. Masten
	Nancy K. Masten
	Chief Accounting Officer

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

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

Bbl/d		barrels of oil per day
Btu		British thermal units, an energy measurement
Gal/d		gallons per day
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
Net operating margin (a non-GAAP financial measure)		revenues less purchased product costs
NGL		natural gas liquids, such as propane, butanes and natural gasoline

Exhibit Number		Exhibit Index

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 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.

31.3		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.

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

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

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

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

Management Overview of the Three and Nine Months Ended September 30, 2005

MarkWest Energy Partners’ Contracts

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Interest Rate Risk

Item 4. Controls and Procedures

Item 1. Legal Proceedings