MARKWEST HYDROCARBON INC - 10-Q Quarterly Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

	For the quarterly period ended September 30, 2004

	OR

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

	For the transition period from to

Commission File Number 001-14841

MARKWEST HYDROCARBON, INC.

(Exact name of registrant as specified in its charter)

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

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

(Address of principal executive offices)

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

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

Yes ý No o

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

Yes o No ý

The registrant had 9,769,289 shares of common stock, $.01 per share par value, outstanding as of October 31, 2004.

PART I—FINANCIAL INFORMATION

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

Glossary of Terms

Bbl/d	barrels of oil per day
Btu	British thermal units, an energy measurement
Gal/d	gallons per day
Gross margin	revenues less purchased product costs
Mcf	thousand cubic feet of natural gas
Mcf/d	thousand cubic feet of natural gas per day
MMBtu	million British thermal units, an energy measurement
MMcf	million cubic feet of natural gas
MMcf/d	million cubic feet of natural gas per day
NGL	natural gas liquids, such as propane, butanes and natural gasoline

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

MARKWEST HYDROCARBON, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

(in thousands, except share and per share data)

	September 30, 2004			December 31, 2003
ASSETS
Current assets:
Cash and cash equivalents	$	22,258		$	42,144
Restricted cash	3,050			2,500
Marketable securities	12,062			—
Receivables, net (including related party receivables of $87 and $40, respectively, and allowance for doubtful accounts of $250 and $120, respectively)	44,162			30,750
Inventories	12,450			4,815
Prepaid replacement natural gas	13,173			5,940
Deferred income taxes	968			603
Other current assets	3,645			503
Total current assets	111,768			87,255

Property, plant and equipment	324,144			232,257
Less: accumulated depreciation, depletion, amortization and impairment	(55,629		)	(44,134		)
Total property, plant and equipment, net	268,515			188,123

Other assets:
Intangible assets, net	165,857			—
Deferred financing costs, net	7,184			3,831
Deferred offering costs	—			1,037
Investment in and advances to equity investee	200			250
Notes receivable from officers	207			217
Other assets	42			—
Total other assets	173,490			5,335

Total assets	$	553,773		$	280,713

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable (including related party payables of $32 and $51, respectively)	$	45,044		$	24,052
Accrued liabilities	20,962			16,751
Risk management liability	2,747			1,769
Total current liabilities	68,753			42,572

Long-term debt	197,500			126,200
Deferred income taxes	8,434			6,346
Risk management liability	—			125
Other long-term liabilities	502			504
Non-controlling interest in consolidated subsidiary	231,558			52,782
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, 9,834,515 and 9,637,977 shares issued, respectively	98			96
Additional paid-in capital	52,409			50,715
Accumulated earnings (deficit)	(3,457		)	3,676
Accumulated other comprehensive loss, net of tax	(1,585		)	(1,793		)
Treasury stock, 65,999 and 75,930 shares, respectively	(439		)	(510		)
Total stockholders’ equity	47,026			52,184

Total liabilities and stockholders’ equity	$	553,773		$	280,713

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003

Revenues	$	122,938		$	48,228		$	304,422		$	146,767

Operating expenses:
Purchased product costs	95,128			44,521			245,715			134,881
Facility expenses	8,281			5,204			20,147			13,983
Selling, general and administrative expenses	5,966			3,549			14,712			9,462
Depreciation and amortization	5,975			2,220			13,385			5,791
Loss on sale of terminals	—			55			—			55
Total operating expenses	115,350			55,549			293,959			164,172

Income (loss) from operations	7,588			(7,321		)	10,463			(17,405		)

Other income (expense):
Interest expense, net	(7,002		)	(1,115		)	(9,452		)	(4,176		)
Gain on sale to related party	—			—			—			188
Non-controlling interest in net income of consolidated subsidiary	(210		)	(1,607		)	(4,452		)	(3,342		)
Other income	553			31			585			15

Income (loss) from continuing operations before income taxes	929			(10,012		)	(2,856		)	(24,720		)

Provision (benefit) for income taxes:
Current	(2,744		)	—			(2,744		)	—
Deferred	3,104			(3,701		)	1,733			(9,058		)
Provision (benefit) for income taxes	360			(3,701		)	(1,011		)	(9,058		)

Income (loss) from continuing operations	569			(6,311		)	(1,845		)	(15,662		)

Discontinued operations:
Income (loss) from discontinued exploration and production operations (net of income taxes of $0, $196, $0, and $720, respectively)	—			(1,260		)	—			2,788
Gain from disposal of discontinued exploration and production operations (less applicable income taxes of $0, $6,182, $0 and $8,173, respectively)	—			593			—			14,862
Income (loss) from discontinued operations	—			(667		)	—			17,650

Income (loss) before cumulative effect of accounting change	569			(6,978		)	(1,845		)	1,988

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

Net income (loss)	$	569		$	(6,978	)	$	(1,845	)	$	1,959

Income (loss) from continuing operations per share:
Basic	$	0.06		$	(0.67	)	$	(0.19	)	$	(1.67	)
Diluted	$	0.06		$	(0.67	)	$	(0.19	)	$	(1.67	)
Net income (loss) per share:
Basic	$	0.06		$	(0.74	)	$	(0.19	)	$	0.21
Diluted	$	0.06		$	(0.74	)	$	(0.19	)	$	0.21
Weighted average number of outstanding shares of common stock:
Basic	9,760			9,378			9,695			9,364
Diluted	9,818			9,400			9,741			9,380
Cash dividend per common share	$	0.025		$	—		$	0.55		$	—

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

(in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003

Net income (loss)	$	569		$	(6,978	)	$	(1,845	)	$	1,959

Other comprehensive income (loss), net of tax:
Foreign currency translation	—			(265		)	—			3,796
Risk management activities	(467		)	3,666			301			3,142
Marketable securities	277			—			(93		)	—
Total other comprehensive income	(190		)	3,401			208			6,938

Comprehensive income (loss)	$	379		$	(3,577	)	$	(1,637	)	$	8,897

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)

	Nine Months Ended September 30,
	2004			2003
Cash flows from operating activities:
Net income (loss)	$	(1,845	)	$	1,959
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Cumulative effect of change in accounting	—			29
Depreciation, depletion and amortization	12,018			18,814
Amortization of deferred financing costs included in interest expense	3,836			1,270
Amortization of intangible asset	1,366			—
Loss from sale of property, plant and equipment	145			—
Non-cash compensation expense	732			554
Equity in investee losses	50			—
Non-controlling interest in net income of consolidated subsidiary	4,452			3,342
Derivative ineffectiveness and non-cash mark-to-market adjustment	732			(2,207		)
Reclassification of Enron hedges to purchased gas costs	—			(153		)
Deferred income taxes	1,732			(4,846		)
Gain on sale of San Juan Basin properties	—			(23,035		)
Cost of exiting hedges	—			(3,440		)
Other	(51		)	427
Changes in operating assets and liabilities:
(Increase) decrease in receivables	(13,122		)	15,046
Increase in inventories	(7,635		)	(2,540		)
Increase in prepaid	(7,233		)	(3,941		)
Increase in other current assets	(3,142		)	—
Increase in accounts payable and accrued liabilities	25,424			309
(Decrease) increase in other long-term liabilities	(2		)	1,565
Net cash flow provided by operating activities	17,457			3,153

Cash flows from investing activities:
Increase in restricted cash	(550		)	—
Increase in marketable securities	(11,776		)	—
East Texas System acquisition	(240,606		)	—
Hobbs Lateral acquisition	(2,275		)	—
Pinnacle acquisition, net of cash acquired	—			(38,238		)
Lubbock pipeline acquisition	—			(12,222		)
Proceeds from sale of San Juan Basin properties, net of costs to dispose	—			55,007
Capital expenditures	(13,798		)	(24,968		)
Proceeds from sales of terminals	—			2,438
Proceeds from sale of assets	206			—
Increase in other contracts	(3,250		)	—
Proceeds from sale of assets to related parties	10			212
Net cash used in investing activities	(272,039		)	(17,771		)

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

	Nine Months Ended September 30,
	2004			2003

Cash flows from financing activities:
Proceeds from long-term debt	215,600			86,835
Repayment of long-term debt	(144,300		)	(75,130		)
Debt issuance costs	(7,193		)	(811		)
Proceeds from public offerings of MarkWest Energy Partners’ common units, net	140,014			—
Proceeds from private placement of MarkWest Energy Partners’ common units, net	44,139			9,764
Distributions to MarkWest Energy Partners’ unitholders	(9,603		)	(5,173		)
Acquisitions and dispositions of MarkWest Energy GP general partnership interests and MarkWest Energy Partners subordinated units to related parties	(157		)	17
Exercise of stock options	1,413			333
Net issuance (buyback) of treasury shares	71			(158		)
Payment of dividends	(5,288		)	—
Net cash provided by financing activities	234,696			15,677
Effect of exchange rate on changes in cash	—			111
Net increase (decrease) in cash and cash equivalents	(19,886		)	1,170
Cash and cash equivalents at beginning of period	42,144			6,410
Cash and cash equivalents at end of period	$	22,258		$	7,580

Supplemental cash flow information:
Cash paid for interest	$	4,607		$	1,201

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENT OF CHANGES IN
STOCKHOLDERS’ EQUITY

(UNAUDITED)

(in thousands)

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

Balance, December 31, 2003	9,638	(76	)	$	96	$	50,715	$	3,676		$	(1,793	)	$	(510	)	$	52,184

Stock option exercises	197	—		2		1,694		—			—			—			1,696

Dividends	—	—		—		—		(5,288		)	—			—			(5,288		)

Net loss	—	—		—		—		(1,845		)	—			—			(1,845		)

Other comprehensive income	—	—		—		—		—			208			—			208

Net treasury stock reissuances	—	10		—		—		—			—			71			71

Balance, September 30, 2004	9,835	(66	)	$	98	$	52,409	$	(3,457	)	$	(1,585	)	$	(439	)	$	47,026

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

MARKWEST HYDROCARBON, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. General

MarkWest Hydrocarbon, Inc. (“we”, “us” or “our”) markets natural gas and natural gas liquids itself, and also manages MarkWest Energy Partners, L.P. (“MarkWest Energy Partners” or the “Partnership”), through our majority ownership in the general partner of the Partnership. MarkWest Energy Partners is a publicly traded master limited partnership engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids (NGLs); and the gathering and transportation of crude oil. Our employees are responsible for conducting the Partnership’s business and operating its assets, pursuant to a Services Agreement.

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

The consolidated financial statements include the accounts of MarkWest Hydrocarbon, Inc. and our subsidiaries, including MarkWest Energy Partners. Through consolidation, we have eliminated all significant intercompany accounts and transactions. We have reclassified certain prior period amounts to conform to the current year’s presentation.

We have prepared the unaudited financial statements presented herein in accordance with the instructions to Form 10-Q. The statements do not include all the information and note disclosures required by generally accepted accounting principles for complete financial statements. Please read the interim consolidated financial statements in conjunction with the Consolidated Financial Statements and attached notes for the year ended December 31, 2003, included in our Annual Report on Form 10-K, as filed with the Securities and Exchange Commission. In the opinion of management, we have made all necessary adjustments for a fair statement of the results for the unaudited interim periods. All said adjustments are of a recurring nature.

We base the effective corporate tax rate for interim periods on the estimated annual effective corporate tax rate.

2. Stock and Unit Compensation

As permitted under Statement of Financial Accounting Standards (“SFAS”) No. 123, Accounting for Stock-Based Compensation, and SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure, we have elected to continue to measure compensation costs for stock-based and unit-based employee compensation plans as prescribed by Accounting Principles Board Opinion (“APB”) No. 25, Accounting for Stock Issued to Employees. We have two fixed compensation plans and, through our consolidated subsidiary, MarkWest Energy Partners, we have a variable plan. We account for these plans using fixed and variable accounting as appropriate under APB 25.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
	(in thousands, except per share data)
Net income (loss), as reported	$	569		$	(6,978	)	$	(1,845	)	$	1,959
Add: compensation expense included in reported net income (loss)	431			72			775			343
Deduct: total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effect	(459		)	(180		)	(858		)	(636		)
Pro forma net income (loss)	$	541		$	(7,086	)	$	(1,928	)	$	1,666

Net income (loss) per share:
Basic:
As reported	$	0.06		$	(0.74	)	$	(0.19	)	$	0.21
Pro forma	$	0.06		$	(0.76	)	$	(0.20	)	$	0.18
Diluted:
As reported	$	0.06		$	(0.74	)	$	(0.19	)	$	0.21
Pro forma	$	0.06		$	(0.76	)	$	(0.20	)	$	0.18

Compensation expense for the variable plan, including restricted unit grants, is measured using the market price of MarkWest Energy Partners’ common units on the date the number of units in the grant becomes determinable and is amortized into earnings over the period of service. Our stock options are issued under a fixed plan. Accordingly, compensation expense is not recognized for stock options unless the options were granted at an exercise price lower than market on the grant date.

3. MarkWest Energy Partners’ Common Unit Offerings

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

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

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

4. Marketable Securities

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

During the first quarter of 2004, we funded a $5.0 million brokerage account to invest primarily in equity securities of other Master Limited Partnerships. As of September 30, 2004, the fair value of the invested securities was approximately $5.4 million. Of this amount $0.3 million was recorded as a net unrealized gain through an adjustment to other comprehensive income.

In addition to equity securities, we invested approximately $9.3 million in Fannie Mae, Ginnie Mae and Freddie Mac callable debt securities, with interest rates ranging from 2.75% to 4.25%, and maturities ranging from May 2006 through November 2009. These debt securities are reflected in marketable securities.

Debt and equity securities were acquired to provide both capital gains and investment income, and are classified as available-for-sale. The following is a summary of gross unrealized gains and losses:

	September 30, 2004
	(in thousands)
Gross unrealized gains	$	357
Gross unrealized losses	(54		)

Net unrealized gain	$	303

5. MarkWest Energy Partners’ Acquisitions

East Texas System Acquisition

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

Assets acquired consist of processing plants, gathering systems, a processing facility currently under construction and an NGL pipeline to be constructed in 2005.

There were a number of factors that led to the acquisition of the East Texas System assets. We believe that the East Texas System complements the Partnership’s existing businesses in several ways and provides the Partnership with a number of growth opportunities through its attractive characteristics. The majority of the East Texas System’s cash flow is generated from its natural gas gathering operations, which are tied to contracts generally ranging in length from five to 10 years. The East Texas System features natural gas pipelines with centralized receipt points connected to common suction or common discharge gathering pipelines. This configuration provides a high degree of reliability and enables MarkWest Energy Partners to offer both low- and high-pressure service to their customers. The system benefits from low fuel and operating costs because of its design, age and large, efficient, standardized compressor stations. We believe that the Carthage Field served by the East Texas System is an attractive operating area for the Partnership because it has long-lived reserves and significant development potential. The East Texas System also provides MarkWest Energy Partners with a platform on which to vertically integrate its business through construction of a natural gas processing facility and NGL pipeline. The Partnership has already obtained contractual commitments that will fill the plant’s capacity.

In conjunction with the closing of the acquisition, the Partnership completed an offering of 1,304,438 of its common units, at $34.50 per unit, which netted MarkWest Energy Partners approximately $44.9 million after transaction costs and the general partner contribution. In addition, the Partnership amended and restated its credit facility, increasing the maximum lending limit from $140.0 million to $315.0 million. The credit facility includes a $265.0 million revolving facility and a $50.0 million term loan facility. MarkWest Energy Partners used the proceeds from the offering and borrowings under the amended and restated credit facility to partially finance the East Texas System acquisition. All of the Partnership’s assets are pledged to the credit facility lenders to secure the repayment of the outstanding borrowings under the credit facility. The term loan portion of the amended and restated credit facility matures in December 2004, and the revolving portion matures in May 2005. In October 2004, the Partnership amended and restated its credit facility, decreasing the maximum lending limit from $315.0 million to $200.0 million and increasing the term of the facility to five years (See Note 9).

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

Acquisition costs:
Cash consideration	$			240,211
Direct acquisition costs	396
Total	$		240,607

Allocation of acquisition costs:
Property, plant and equipment	$		76,634
Customer contracts	163,973
Total	$	240,607

Of the total purchase price, approximately $164.0 million was allocated to amortizable intangible assets (See Note 8).

Allocation of the purchase price is preliminary because certain items such as the determination of the fair value of certain assets as of the acquisition date and the settlement of certain purchase price adjustments included in the purchase and sale agreement have not been finalized.

Hobbs Lateral Acquisition

On April 1, 2004, the Partnership acquired the Hobbs Lateral pipeline for approximately $2.3 million. The Hobbs Lateral consists of a four-mile pipeline, with a capacity of 160 million cubic feet of natural gas per day, connecting the Northern Natural Gas interstate pipeline to Southwestern Public Service’s Cunningham and Maddox power generating stations in Hobbs, New Mexico. The Hobbs Lateral is a New Mexico intrastate pipeline regulated by the Federal Energy Regulatory Commission. The pro forma results of operations of the Hobbs Lateral acquisition have not been presented as they are not significant.

Michigan Crude Pipeline

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

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

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

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

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

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

Western Oklahoma Acquisition

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

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

The purchase price of approximately $38.0 million was financed through borrowings under the Partnership line of credit, which was amended at the closing of the acquisition to increase availability under the credit facility from $75.0 million to $140.0 million.

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

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

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

Lubbock Pipeline Acquisition

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

Pinnacle Acquisition

On March 28, 2003, MarkWest Energy Partners completed the acquisition (the “Pinnacle acquisition”) of Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG Transmission Company, Inc., PNG Utility Company and Bright Star Gathering, Inc. (collectively, “Pinnacle” or the “Sellers”). Pinnacle’s results of operations have been included in the Partnership’s consolidated financial statements since that date.

The Pinnacle acquisition was accomplished through a merger under Texas law of the Sellers and four newly formed wholly owned subsidiaries of the Partnership as buyers. In the merger, most of the assets and liabilities of the Sellers were allocated to the Partnership entities, and all entities survived the merger. The assets acquired from the Sellers, primarily located in the State of Texas, with the balance located in New Mexico, Louisiana, Mississippi and Kansas, were comprised of three lateral natural gas pipelines and twenty gathering systems.

The purchase price was allocated as follows (in thousands):

Acquisition costs:
Long-term debt incurred	$	39,471
Direct acquisition costs	450
Current liabilities assumed	8,945
Total	$	48,866

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

Pro Forma Results of Operations (Unaudited)

The following table reflects the unaudited pro forma consolidated results of operations for the comparable period presented, as though the Pinnacle acquisition, the Western Oklahoma acquisition, the Michigan Crude Pipeline and the East Texas System acquisition each had occurred as of the beginning of the period presented. The unaudited pro forma results have been prepared for comparative purposes only and may not be indicative of future results. The pro forma results of operations of the Hobbs Lateral acquisition and the Lubbock Pipeline acquisition have not been presented, as they are not significant (in thousands, except per unit data).

	Three Months Ended September 30, 2004		Three Months Ended September 30, 2003			Nine Months Ended September 30, 2004			Nine Months Ended September 30, 2003
Revenue	$	126,511	$	66,949		$	325,100		$	223,042
Income (loss) from continuing operations	$	936	$	(8,003	)	$	(1,290	)	$	(26,948	)
Basic income (loss) from continuing operations per share	$	0.10	$	(0.85	)	$	(0.13	)	$	(2.88	)
Diluted income (loss) from continuing operations per share	$	0.10	$	(0.85	)	$	(0.13	)	$	(2.88	)

6. Property, Plant and Equipment

The following provides composition of our property, plant and equipment at:

	September 30, 2004			December 31, 2003
	(in thousands)
Property, plant and equipment:
Gas gathering facilities	$	147,004		$	73,424
Gas processing plants	56,277			55,888
Fractionation and storage facilities	22,496			22,160
Natural gas pipelines	38,842			38,790
Crude oil pipeline	18,522			18,352
NGL transportation facilities	4,391			4,415
Marketing assets	1,606			1,987
Oil and gas properties and equipment, full cost method	2,509			2,380
Land, buildings and other equipment	11,257			12,499
Construction in-progress	21,240			2,362
	324,144			232,257
Less: Accumulated depreciation, depletion, amortization and impairment	(55,629		)	(44,134		)
Total property, plant and equipment, net	$	268,515		$	188,123

Cobb Processing Plant

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

7. Adoption of SFAS No. 143

On January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. During the first quarter of 2003, we recorded a net-of-tax cumulative effect of change in accounting principle charge of $29,000 ($63,000 before tax), and an asset retirement obligation of $3.4 million (a net increase to long-term liabilities of $2.5 million). We also increased net properties $2.4 million in accordance with the provisions of SFAS No. 143. There was no impact on our cash flows as a result of adopting SFAS No. 143. The asset retirement obligation, which is included in our consolidated balance sheet in other long-term liabilities, was $0.5 million and $3.8 million at September 30, 2004 and 2003, respectively.

8. Intangible Assets

On July 30, 2004, the Partnership completed the acquisition of American Central East Texas’ Carthage gathering system and gas processing assets located in East Texas for approximately $240.6 million. Of the total purchase price, $164.0 million was allocated to amortizable intangible assets (i.e., customer contracts) based on the net present value of the projected cash flows. The key variables that determined the valuation of the customer contracts was the assumption of renewals, economic incentives to retain customers, historical volumes, current and

future capacity of the gathering system and pricing volatility. The Partnership is amortizing the fair value of these customer contracts on a straight-line basis over an estimated economic life of 20 years. The estimated economic life was determined by assessing the life of the assets to which the contracts relate, likelihood of renewals, competitive factors, regulatory or legal provisions, and maintenance and renewal costs.

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

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

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

	Gross		2004 Accumulated Amortization		Net
Customer contracts (20 years)	$	163,973	$	1,366	$	162,607
Other (October 1, 2004 – February 9, 2015)	3,250		—		3,250
Total intangible assets	$	167,223	$	1,366	$	165,857

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

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

Year ending December 31:
2004	$	2,122
2005	8,487
2006	8,487
2007	8,487
2008	8,487
2009	8,487
Thereafter	121,300

9. Debt

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

The interest rate on the credit facility is determined using a variable interest rate based on one of two indices that include either (i) LIBOR plus 3.5% to LIBOR plus 4.5% or (ii) Base Rate (“BR”) (as defined for any day, a fluctuating rate per annum equal to the higher of (a) the Federal Funds Rate plus ½ of 1% and (b) the rate of interest in effect for such day as publicly announced from time to time by the Administrative Agent of the debt as its “prime rate”) plus 2.5% to BR plus 3.5%, depending on our maintenance of certain financial leverage ratios. The Partnership is also required to pay a commitment fee equal to the applicable rate (as defined in the credit agreement) times the actual daily amount by which the aggregate revolver commitments exceed the sum of (i) the outstanding

amount of revolver loans plus (ii) the outstanding amount of letters of credit obligations. The commitment fee is due and payable quarterly in arrears on the last business day of each March, June, September and December. For the nine months ended September 30, 2004, the weighted average interest rate was 5.4%.

Subsequent event

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

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

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

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

10. Recovery of Receivable

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

11. Segment Reporting

Our operations are classified into two reportable segments:

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

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

During 2003, we discontinued our exploration and production business segment. Our continuing operations are conducted solely in the United States.

The table below presents information about operating income (loss) for the reported segments for the three and nine months ended September 30, 2004 and 2003. Segment operating income (loss) includes total revenues less purchased product costs, facility expenses and depreciation and amortization. Items excluded from segment operating income (loss) are reflected in the reconciliation of total segment operating income (loss) to income (loss) from continuing operations before taxes.

	Marketing			MarkWest Energy Partners		Eliminating Entries			Total
	(in thousands)
Three Months Ended September 30, 2004:
Revenues from external customers	$	61,105		$	61,833	$	—		$	122,938
Intersegment revenues	$	121		$	15,250	$	(15,371	)	$	—
Segment operating income	$	2,158		$	11,396	$	—		$	13,554
Total segment assets	$	94,626		$	478,574	$	(19,427	)	$	553,773

Three Months Ended September 30, 2003:
Revenues from external customers	$	29,340		$	18,888	$	—		$	48,228
Intersegment revenues	$	313		$	12,524	$	(12,837	)	$	—
Segment operating income (loss)	$	(9,197	)	$	5,480	$	—		$	(3,717	)
Total segment assets	$	159,630		$	142,290	$	(14,176	)	$	287,744

	Marketing			MarkWest Energy Partners		Eliminating Entries			Total
	(in thousands)
Nine Months Ended September 30, 2004:
Revenues from external customers	$	142,445		$	161,977	$	—		$			304,422
Intersegment revenues	$	459		$	43,350	$	(43,809	)	$			—
Segment operating income (loss)	$	(313	)	$	25,488	$	—		$		25,175
Total segment assets	$	94,626		$	478,574	$	(19,427	)	$		553,773

Nine Months Ended September 30, 2003:
Revenues from external customers	$	104,026		$	42,741	$	—		$		146,767
Intersegment revenues	$	758		$	36,000	$	(36,758	)	$		—
Segment operating income (loss)	$	(21,173	)	$	13,285	$	—		$		(7,888		)
Total segment assets	$	159,630		$	142,290	$	(14,176	)	$	287,744

A reconciliation of total segment operating income (loss) to loss from continuing operations before taxes is as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
	(in thousands)
Segment operating income (loss)	$	13,554		$	(3,717	)	$	25,175		$	(7,888	)
Selling, general and administrative expenses	(5,966		)	(3,549		)	(14,712		)	(9,462		)
Loss on sale of terminals	—			(55		)	—			(55		)
Interest expense, net	(7,002		)	(1,115		)	(9,452		)	(4,176		)
Gain on sale to related party	—			—			—			188
Non-controlling interest in net income of consolidated subsidiary	(210		)	(1,607		)	(4,452		)	(3,342		)
Other income	553			31			585			15
Income (loss) from continuing operations before income taxes	$	929		$	(10,012	)	$	(2,856	)	$	(24,720	)

12. Related Party Transactions

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

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

13. Commitments and Contingencies

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

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

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

14. Recent Accounting Pronouncements

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

15. Subsequent Event

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

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

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, 2004

We reported net income for the three months ended September 30, 2004 of $0.6 million, or $0.06 per diluted share, compared to a net loss of $7.0 million, or $0.74 per diluted share, for the third quarter of 2003. For the nine months ended September 30, 2004, we reported a net loss of $1.8 million, or $0.19 per diluted share, compared to net income of $2.0 million, or $0.21 per diluted share, for the nine months ended September 30, 2003.

We reported net income from continuing operations of $0.6 million, or $0.06 per diluted share, for the three months ended September 30, 2004, compared to a net loss from continuing operations of $6.3 million, or $0.67 per diluted share, for the third quarter of 2003. For the nine months ended September 30, 2004, we reported a net loss from continuing operations of $1.8 million, or $0.19 per diluted share, compared to a net loss from continuing operations of $15.7 million, or $1.67 per diluted share, for the corresponding nine months of 2003.

The improved results for the third quarter of 2004 as compared to the corresponding quarter of 2003 was attributed to the impact of better NGL product margins, the non-recurrence of approximately $3.9 million of crude oil hedging losses and higher NGL product sales volumes. Other matters benefiting third quarter results included an approximate $0.8 million in other income from the sale of the rights to a former Enron receivable that had been previously written-off.

The improved net income from continuing operations for the first nine months of 2004 as compared to the corresponding period of 2003 was also attributed to the factors impacting the third quarter comparisons. Approximately $10.9 million of the change was attributable to a reduction in our crude oil hedging losses. The remainder of the change was primarily due to better NGL product margins and due to acquisitions made by MarkWest Energy Partners, late in 2003 and in the third quarter of 2004.

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

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

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

Our Business

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

We are an energy company primarily focused 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 through our processing contracts and wholesale marketing business. We discontinued our exploration and production activities during 2003.

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

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

• A 90% ownership interest in MarkWest Energy GP, L.L.C., the general partner of the Partnership, which owns a 2% general partner interest and all of the incentive distribution rights in the Partnership.

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

• The nature of our relationship with MarkWest Energy Partners;

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

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

Our Relationship with MarkWest Energy Partners

We spun off the majority of our then-existing natural gas gathering and processing and NGL transportation, fractionation and storage assets into MarkWest Energy Partners in May 2002, just before the Partnership completed its initial public offering. At the time of its formation and initial public offering, we entered into four contracts with MarkWest Energy Partners whereby MarkWest Energy Partners provides midstream services to us in Appalachia in exchange for fees. These fees are accounted for as facility expenses. 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. We retain a 70% net profits interest in the gathering and processing income earned on quarterly pipeline throughput in excess of 10 MMcf/d.

In accordance with generally accepted accounting principles, MarkWest Energy Partners’ financial results are included in our consolidated financial statements. All intercompany accounts and transactions are eliminated during consolidation. You should read Note 11 to our Consolidated Financial Statements appearing earlier in this Form 10-Q for further information regarding our two business segments: managing the business operations of MarkWest Energy Partners and marketing.

As a result of our contracts with MarkWest Energy Partners mentioned above, we are the Partnership’s largest customer, accounting for 20% and 21% of its revenues for the three and nine months ended September 30, 2004, respectively, and 24% and 31% of its gross margin for the three and nine months ended September 30, 2003, respectively. We expect to account for less of MarkWest Energy Partners’ business in the future as MarkWest Energy Partners expands its existing operations, continues to acquire assets and increases its customer and business diversification.

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

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

Our Contracts

Excluding the revenues and gross margin derived by MarkWest Energy Partners, the majority of our revenues and gross margin are generated from providing processing services, and from our marketing of NGLs and, to a lesser extent, natural gas. As compensation for providing processing services to Appalachian producers (we have outsourced these services to MarkWest Energy Partners as discussed above), we earn a fee and receive title to the NGLs produced. In return, we are required to replace, in dry natural gas, the Btu value of the NGLs extracted.

This Btu replacement obligation is referred to in the industry as a “keep-whole” arrangement. In keep-whole arrangements, our principal cost is the replacement of the Btus extracted from the gas stream in the form of NGLs or consumed as fuel during processing with dry gas of an equivalent Btu content. The spread between the NGL product sales price and the purchase price of natural gas with an equivalent Btu content is called the “frac spread.” In the event natural gas and the cost of processing becomes more expensive, on a Btu equivalent basis, when compared to NGL products, the cost of keeping the producer “whole”, in conjunction with our operating costs, results in operating losses.

Our keep-whole contracts expose us to commodity price risk, both on the sales side (of NGLs) and on the purchase side (of natural gas), which may increase the volatility of our marketing results and cash flows. However, in September, we entered into several new and amended agreements with one of the largest Appalachia producers, which allow us to significantly reduce our exposure to commodity price risk for approximately 25% of our keep-whole gas volumes. We also attempt to mitigate our commodity price risk through our hedging program. Under a hedging strategy implemented approximately two years ago that was based on our then-existing natural gas production and historical pricing data through that point in time, we incurred significant hedging losses. For the nine months ended September 30, 2004 and 2003, we lost approximately $2.7 million and $13.6 million, respectively, as a result of that hedging strategy. The last transactions associated with this hedging strategy settled in April 2004. You should read Item 3, “Quantitative and Qualitative Disclosures About Market Risk” for further details about our commodity price risk management program, which is incorporated herein by reference.

MarkWest Energy Partners’ Contracts

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

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

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

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

• Keep-whole contracts. Under keep-whole contracts, the Partnership gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices. Because the extraction

of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, the Partnership must either purchase natural gas at market prices for return to producers or make cash payment to the producers equal to the value of this natural gas. Accordingly, under these arrangements, the Partnership’s revenues and gross margins increase as the price of NGLs increase relative to the price of natural gas, and its revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs.

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

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

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

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

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

At September 30, 2004, the Partnership’s primary exposure to keep-whole contracts was limited to its Arapaho (OK) processing plant and its East Texas (“Carthage”) processing contract with a third party. At the Arapaho (OK) plant inlet, the Btu content of the natural gas meets the downstream pipeline specifications; however, MarkWest Energy Partners has the option of extracting NGLs when the processing margin environment is favorable. In addition, approximately half, as measured in volumes, of the related gas gathering contracts include additional fees to cover plant operating costs, fuel costs and shrinkage costs in a low processing margin environment. Because of the Partnership’s ability to operate the plant in several recovery modes, including turning it off, coupled with the additional fees provided for in the gas gathering contracts, the Partnership’s overall keep-whole contract exposure is limited to a portion of the operating costs of the plant.

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

Recent MarkWest Energy Partners Acquisition Activity

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

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

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

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

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

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

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

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

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

Results of Operations

Operating Data

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

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

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

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

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

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

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

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

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

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

	Marketing			MarkWest Energy Partners		Eliminating Entries			Total
	(in thousands)
Three Months Ended September 30, 2004:
Revenues	$	61,226		$	77,083	$	(15,371	)	$	122,938

Purchased product costs	52,564			51,635		(9,071		)	95,128
Facility expenses	6,201			8,380		(6,300		)	8,281
Depreciation and amortization	303			5,672		—			5,975
Total segment operating expenses	59,068			65,687		(15,371		)	109,384

Segment operating income	$	2,158		$	11,396	$	—		$	13,554

Three Months Ended September 30, 2003:
Revenues	$	29,653		$	31,412	$	(12,837	)	$	48,228

Purchased product costs	32,294			18,510		(6,283		)	44,521
Facility expenses	6,362			5,396		(6,554		)	5,204
Depreciation and amortization	194			2,026		—			2,220
Total segment operating expenses	38,850			25,932		(12,837		)	51,945

Segment operating income (loss)	$	(9,197	)	$	5,480	$	—		$	(3,717	)

	Three Months Ended September 30,
	2004			2003
	(in thousands)
Segment operating income (loss)	$	13,554		$	(3,717	)
Selling, general and administrative	(5,966		)	(3,549		)
Loss on sale of terminals	—			(55		)
Interest expense, net	(7,002		)	(1,115		)
Non-controlling interest in net income of consolidated subsidiary	(210		)	(1,607		)
Other income	553			31

Income (loss) from continuing operations before income taxes	$	929		$	(10,012	)

Marketing. Our marketing segment operating income was $2.2 million for the three months ended September 30, 2004, compared to a loss of $9.2 million for the three months ended September 30, 2003, a change of $7.0 million. The increase is primarily due to higher NGL product sales prices and volumes. In addition, approximately $3.9 million of the change was attributable to a reduction in our hedging losses.

MarkWest Energy Partners. Segment operating income from MarkWest Energy Partners was $11.4 million for the three months ended September 30, 2004, compared to $5.5 million for the three months ended September 30, 2003, an increase of $5.9 million, or 107%. The increase is primarily attributable to the Partnership’s late 2003 and 2004 acquisitions, which contributed $6.6 million to operating income. This was offset by an increase of $0.7 million in depreciation expense primarily as a result of accelerating the depreciation of our Michigan gathering pipeline and processing plant by reducing the estimated useful lives of the related assets from twenty years to fifteen years to more closely match expected lives of reserves behind our facilities.

Selling, general and administrative expenses. Selling, general and administrative expenses were $6.0 million for the three months ended September 30, 2004, compared to $3.5 million for the three months ended September 30, 2003, an increase of $2.5 million, or 71%. The increase is attributable to several factors, including additional administrative costs associated with the growth of MarkWest Energy Partners, through its 2003 and 2004 acquisitions,

Sarbanes Oxley compliance expenses, bonus and profit sharing (bonus was not accrued during the three months ended September 30, 2003) and increases in franchise taxes and insurance.

Interest expense, net. Interest expense, net was $7.0 million for the three months ended September 30, 2004, compared to $1.1 million for the three months ended September 30, 2003, an increase of $5.9 million, or 536%. The increase was principally attributable to amortization and write off of deferred financing costs from the amendment and restatement of our credit facility in July 2004. In addition, interest expense increased due to greater debt levels resulting from the financing of our late 2003 and 2004 acquisitions and an increase in our average interest rate.

Loss from discontinued operations. Loss from discontinued operations was $0 for the three months ended September 30, 2004, compared to $0.7 million for the three months ended September 30, 2003, a decrease of $0.7 million. The decrease was a result of the sale of substantially all of our U.S. exploration and production business near the end of the second quarter of 2003.

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

	Marketing			MarkWest Energy Partners		Eliminating Entries			Total
	(in thousands)
Nine Months Ended September 30, 2004:
Revenues	$	142,904		$	205,327	$	(43,809	)	$	304,422

Purchased product costs	124,036			146,695		(25,016		)	245,715
Facility expenses	18,139			20,801		(18,793		)	20,147
Depreciation and amortization	1,042			12,343		—			13,385
Total segment operating expenses	143,217			179,839		(43,809		)	279,247

Segment operating income (loss)	$	(313	)	$	25,488	$	—		$	25,175

Nine Months Ended September 30, 2003:
Revenues	$	104,784		$	78,741	$	(36,758	)	$	146,767

Purchased product costs	108,089			45,325		(18,533		)	134,881
Facility expenses	17,308			14,900		(18,225		)	13,983
Depreciation and amortization	560			5,231		—			5,791
Total segment operating expenses	125,957			65,456		(36,758		)	154,655

Segment operating income (loss)	$	(21,173	)	$	13,285	$	—		$	(7,888	)

	Nine Months Ended September 30,
	2004			2003
	(in thousands)
Segment operating income (loss)	$	25,175		$	(7,888	)
Selling, general and administrative	(14,712		)	(9,462		)
Loss on sale of terminals	—			(55		)
Interest expense, net	(9,452		)	(4,176		)
Gain on sale to related party	—			188
Non-controlling interest in net income of consolidated subsidiary	(4,452		)	(3,342		)
Other income	585			15

Loss from continuing operations before income taxes	$	(2,856	)	$	(24,720	)

Marketing. Our marketing segment operating loss was $0.3 million for the nine months ended September 30, 2004, compared to a loss of $21.2 million for the nine months ended September 30, 2003, a decrease of $20.9 million, or 99%. Approximately $10.9 million of the change was attributable to a reduction in our hedging losses. The remainder of the change is primarily attributable to higher NGL product sales prices and volumes.

MarkWest Energy Partners. Segment operating income from MarkWest Energy Partners was $25.5 million for the nine months ended September 30, 2004, compared to $13.3 million for the nine months ended September 30, 2003, an increase of $12.2 million, or 92%. The increase is primarily attributable to the Partnership’s late 2003 and 2004 acquisitions, which contributed $13.2 million to operating income. This was offset by an increase in depreciation expense primarily as a result of accelerating the depreciation of our Michigan gathering pipeline and processing plant by reducing the estimated useful lives of the related assets from twenty years to fifteen years to more closely match expected lives of reserves behind our facilities.

Selling, general and administrative expenses. Selling, general and administrative expenses were $14.7 million for the nine months ended September 30, 2004, compared to $9.5 million for the nine months ended September 30, 2003, an increase of $5.2 million, or 55%. The increase is attributable to several factors, including additional administrative costs associated with the growth of MarkWest Energy Partners, through its 2003 and 2004 acquisitions, Sarbanes Oxley compliance expenses, bonus and profit sharing (bonus was not accrued during the nine months ended September 30, 2003) and increases in franchise taxes and insurance.

Interest expense, net. Interest expense, net was $9.5 million for the nine months ended September 30, 2004, compared to $4.2 million for the nine months ended September 30, 2003, an increase of $5.3 million, or 126%. The increase was primarily attributable to amortization and write off of deferred financing costs from the amendment and restatement of our credit facility in July 2004. In addition interest expense increased due to heightened debt levels resulting from the financing of our late 2003 and 2004 acquisitions and an increase in our average interest rate.

Income from discontinued operations. Income from discontinued operations was $0 for the nine months ended September 30, 2004, compared to $17.7 million, net of tax, for the nine months ended September 30, 2003, a decrease of $17.7 million. The decrease was a result of the sale of substantially all of our U.S. exploration and production business near the end the second quarter of 2003.

Liquidity and Capital Resources

During 2003, we discontinued our exploration and production activities and sold all of our related Canadian oil and gas properties and substantially all of our U.S. oil and gas properties. The sales netted us $106.7 million in cash. The proceeds were primarily used to pay off and terminate our then existing credit facility in its entirety in December 2003. We also had $33.4 million in unrestricted cash on hand at December 31, 2003, exclusive of MarkWest Energy Partners’ $8.7 million cash on hand. As a result, exclusive of MarkWest Energy Partners’ debt, we had no debt as of September 30, 2004 and December 31, 2003. In February 2004, we disbursed approximately $4.8 million to pay a special one-time dividend of $0.50 per share to our common stockholders. In May 2004, we disbursed approximately $0.2 million to pay the first quarterly dividend of $0.025 per common share to our common shareholders. On August 19, 2004, we disbursed approximately $0.2 million to pay the second quarterly dividend of $0.025 per share to our common stockholders. On October 28, 2004, our board of directors declared a stock dividend of one share of our common stock for each ten shares of common stock held by our common stockholders. The stock dividend is to be paid on November 19, 2004, to the stockholders of record as of the close of business on November 9, 2004. On the same date, our board of directors also announced that it declared a quarterly cash dividend of $0.05 per share of our common stock. This represented a $0.025 per share increase over the previous quarter’s dividend. The indicated annual rate is $0.20 per share. Our Board has declared that the dividend is to be paid on December 6, 2004, to the stockholders of record as of the close of business on November 24, 2004.

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

We own 90% of the general partner of MarkWest Energy Partners. The general partner of MarkWest Energy Partners owns a 2% general partner interest and all of the incentive distribution rights in MarkWest Energy Partners. The incentive distribution rights entitle us to receive, through the general partner, an increasing percentage of cash distributed by the Partnership upon attainment of target distribution levels. Specifically, incentive distribution rights entitle us to receive 13% of the incremental cash distributed in a quarter greater than $0.55 per unit and up to and including $0.625 per unit for that quarter; 23% of the incremental cash distributed in a quarter greater than $0.625 per unit and up to and including $0.75 per unit for that quarter; and 48% of the incremental cash distributed in a quarter above $0.75 per unit for that quarter. For the nine months ended September 30, 2004, we received $5.2 million in distributions for our subordinated units, and the general partner received $0.9 million, including $0.7 million representing payments on incentive distribution rights. As the Partnership continues to grow and increase its quarterly distributions per limited partner unit, we expect corresponding increases in our distributions.

Cash flows generated from providing processing services and our marketing operations are subject to volatility primarily in NGLs and natural gas prices. Our cash flows are enhanced in periods when the prices received for NGLs exceed the prices paid for natural gas we purchase to satisfy our “keep-whole” contractual arrangements in Appalachia, and are reduced in periods when the prices received for NGLs are low relative to the price of natural gas we purchase to satisfy such contractual arrangements. Under “keep-whole” contracts, we retain and sell the NGLs produced in our processing operations for third-party producers, and then reimburse or “keep whole” the producers for the Btu content of the NGLs removed through the re-delivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas. Generally, the frac spread and, consequently, the operating margins, are favorable. Periodically, when natural gas becomes more expensive, on a Btu equivalent basis, compared to NGL products, the cost of keeping the producer “whole”, in conjunction with our operating costs, can result in operating losses. As noted previously, we entered into several new and amended agreements in September with one of the largest Appalachia producers that allow us to significantly reduce our exposure to commodity price risk for approximately 25% of our keep-whole gas volumes. We, however, cannot predict with any certainty what the pricing environment will be in the future.

On October 25, 2004, we entered into a $25.0 million senior credit facility with a term of one year. The $25.0 million revolving facility has a variable interest rate based on the base rate, which is equal to the higher of a) the Federal Funds Rate plus ½ of 1%, and b) the rate of interest in effect for such day as publicly announced from time to time by the Administrative Agent as its prime rate, plus the applicable rate, which is based on a utilization percentage. The amount available to be drawn under the credit facility is based upon the amount of our eligible accounts receivable and inventory balance. In addition, we are required to pay a commitment fee equal to the applicable rate times the actual daily amount by which the aggregate commitment exceeds the sum of (i) the outstanding amount of loans plus (ii) the outstanding amount of our letter of credit obligations. Substantially all of our assets and our subsidiaries (other than excluded MarkWest Energy Partners entities) are pledged to the lender to secure the repayment of the outstanding borrowings under the credit facility. The proceeds from this borrowing will be used to finance inventory and accounts receivable, issue letters of credit and pay fees, costs and expenses related to this agreement. As of October 31, 2004, we had no outstanding borrowings.

We believe that cash on hand, cash received from quarterly distributions (including the incentive distribution rights) from MarkWest Energy Partners, and cash generated from our processing services and marketing operations will be sufficient to meet our working capital requirements and fund our required capital expenditures, if any, for the foreseeable future. Most of our future capital expenditures are discretionary and minimal in nature. During 2004, we have budgeted $1.0 million for our capital contribution to MarkWest Energy Partners for our share of the costs to replace the Cobb plant and an additional $0.1 million for other miscellaneous projects. As of September 30, 2004 we had contributed $1.3 million for the Cobb plant, including amounts contributed in 2003, resulting in $0.4 million to be contributed during the fourth quarter of fiscal 2004. Cash generated from our processing services and marketing operations will depend on our operating performance, which will be affected by prevailing commodity prices and other factors, some of which are beyond our control.

In an effort to increase our liquidity, we may renegotiate certain keep-whole contracts in order to reduce our commodity price risk.

MarkWest Energy Partners

Partnership Equity Offerings

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

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

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

Partnership Debt

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

In October 2004, the Partnership’s credit facility was amended and restated, decreasing the maximum lending limit from $315.0 million to $200.0 million and increasing the term of the facility to five years. The credit facility includes a revolving facility of $200.0 million with the potential to increase the maximum lending limit to $300.0 million. The credit facility is guaranteed by the Partnership and all of its present and future subsidiaries and is collateralized by substantially all of its existing and future assets and those of its subsidiaries, including stock and other equity interests. The borrowing under the credit facility will bear interest at a variable interest rate based on one of two indices that include either (i) LIBOR plus an applicable margin, which is fixed at a rate of 2.75% for the first two quarters following the closing of the credit facility or (ii) Base Rate (as defined for any day, a fluctuating rate per annum equal to the higher of (a) the Federal Funds Rate plus ¹/₂ of 1% and (b) the rate of interest in effect for such day as publicly announced from time to time by the Administrative Agent of the debt as its “prime rate”) plus an applicable margin, which shall be fixed at a rate of 2.00% for the first two quarters following the closing of the credit facility. After that period, the applicable margin will be adjusted quarterly based on the Partnership’s ratio of funded debt to EBITDA (as defined in the credit agreement). The Partnership is also required to pay a commitment fee equal to the applicable rate (as defined in the credit agreement) times the actual daily amount by which the aggregate revolver commitments exceed the sum of (i) the outstanding amount of revolver loans plus (ii) the outstanding amount of letters of credit obligations. The commitment fee is due and payable quarterly in arrears on the last business day of each March, June, September and December.

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

requirement. Failure to comply with the provisions of any of these covenants could result in acceleration of the debt and other financial obligations.

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

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

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

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

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

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

Total Contractual cash obligations

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

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

Cash Flows

	Nine Months Ended September 30,
	2004			2003
	(in thousands)
Net cash provided by operating activities	$	17,457		$	3,153
Net cash used in investing activities	$	(272,039	)	$	(17,771	)
Net cash provided by financing activities	$	234,696		$	15,677

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

Net cash used in investing activities for the nine months ended September 30, 2004, increased relative to the same period in the prior year primarily due to the Partnership’s acquisition of the East Texas System in July 2004 for $240.6 million. Additionally, we invested $11.8 million in marketable securities.

Net cash provided by financing activities for the nine months ended September 30, 2004, was primarily attributable to equity financings and borrowings under our Partnership’s credit facility. In January 2004, the Partnership completed a secondary public offering generating net proceeds of $44.9 million in 2004. The proceeds were used to pay down the outstanding debt. The Partnership also amended and restated its credit facility in July 2004 to increase its total borrowing capacity to $315.0 million. MarkWest Energy Partners borrowed $200.8 million under this credit facility to partially finance its East Texas System acquisition. In July 2004, the Partnership completed a private placement of 1,304,438 of common units to a group of institutional investors, generating total net proceeds of $44.9 million. These funds were also used to partially finance the East Texas System acquisition. In addition, the Partnership raised net proceeds of $97.8 million through a public offering of 2,323,609 common units in September 2004. Proceeds from this offering were used to reduce our outstanding indebtedness. Additionally, we paid dividends of $5.3 million and MarkWest Energy Partners paid distributions to its unitholders of $9.6 million.

Recent Accounting Pronouncements

Forward-Looking Information

Statements included in this Management’s Discussion and Analysis that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. We use words such as “may,” “believe,” “estimate,” “expect,” “plan,” “intend,” “project,” “anticipate,” and similar expressions to identify forward-looking statements.

These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements as a result of certain factors as more fully discussed under the heading “Risk Factors” contained in our annual report on Form 10-K filed on March 15, 2004 with the Securities and Exchange Commission (File No. 001-31239) for our fiscal year ended December 31, 2003. Forward-looking statements include statements relating to, among other things:

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

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

• Our ability to amend certain producer contracts.

• Our ability to increase fee-based contract volumes.

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

• Our ability to manage our commodity price risk.

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

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

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

• The availability and prices of NGL and competing commodities.

• The availability and prices of raw natural gas supply.

• Our ability to negotiate favorable marketing agreements.

• The risks that third party natural gas exploration and production activities will not occur or be successful.

• Our dependence on certain significant customers, producers, gatherers, treaters, and transporters of natural gas.

• Competition from other NGL processors, including major energy companies.

• Our ability to identify and consummate grass-roots projects or acquisitions complementary to our business.

• Winter weather conditions.

Forward-looking statements involve many uncertainties that are beyond our ability to control. In many cases, we cannot predict what factors would cause actual results to differ materially from those indicated by the forward-looking statements.

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

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

regulation could adversely affect our profitability.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

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

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

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

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

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

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

NGL Price Risk

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

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

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

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

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

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

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

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

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

MarkWest Energy Partners

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

	Year Ending December 31,
	2004		2005

MMBtu	30,500		182,500
$/MMBtu	$	4.57	$	4.26

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

	Year Ending December 31,
	2004		2005

MMBtu	61,000		—
Strike price ($/MMBtu)	$	4.00	$	—

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

	Year Ending December 31,
	2004			2005

MMBtu	951,000			900,000
($/MMBtu)	$	(0.035	)	$	(0.035	)

Interest Rate Risk

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

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

Item 4. Controls and Procedures

Attached as exhibits 31.1, 31.2 and 31.3 to this Quarterly Report are certifications of our principal executive and accounting officers (who we refer to in this periodic report as our Certifying Officers) as required in accordance with Section 302 of the Sarbanes-Oxley Act of 2002 (the “Section 302 Certifications”). This portion of our Quarterly Report on Form 10-Q discloses the results of our evaluation of our disclosure controls and procedures as of September 30, 2004, referred to in paragraphs (4) and (5) of the Section 302 Certifications and should be read in conjunction with the Section 302 Certifications for a more complete understanding of the topics presented.

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms, and that information is accumulated and communicated to our management, including our Certifying Officers, as appropriate to allow timely decisions regarding required disclosure. Our management evaluated, with the participation of our Certifying Officers, the effectiveness of our disclosure controls and procedures as of September 30, 2004, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, our Certifying Officers concluded that as of September 30, 2004, our disclosure controls and procedures were effective.

Nevertheless, we are continuing to conduct an internal review under the supervision and with the participation of our management and our Certifying Officers of the effectiveness of the design and operation of our disclosure controls and procedures. The purpose of such review is to identify and establish enhancements to our disclosure controls and procedures that can help prevent any potential misstatements or omissions in our consolidated financial statements. Such enhancements are also focused on assisting our management in evaluating the effectiveness of our internal controls over financial reporting as required by Section 404 of the Sarbanes-Oxley Act of 2002 commencing with our fiscal year ending December 31, 2004.

In performance of the audit for the fiscal year ended December 31, 2003, the Partnership’s independent auditors at that time, PricewaterhouseCoopers LLP (“PwC”), identified to management and the Audit Committee certain deficiencies in our internal accounting controls which, considered collectively, could have constituted a material weakness in our internal controls when evaluated against the compliance standards under Section 404 of the Sarbanes-Oxley Act of 2002, had it been applicable and in effect at that time. Specific deficiencies identified by PwC included a possible insufficiency in the personnel resources available to adequately maintain our financial reporting obligation as a public company; inadequate implementation of uniform controls over certain acquired entities and operations; inadequate control over classification of certain fixed asset balances and processes for accrual of certain accounts payable; and the potential need for separation of certain duties between payroll and other accounting personnel.

Management has assigned a high priority to both the short-term and long-term improvement and remediation actions to address and correct any potential weaknesses in the deficiencies noted by PwC. Under the supervision and with the participation of our management and Certifying Officers regarding the effectiveness of the design and operation of our disclosure controls and processes, we have documented and implemented numerous internal control improvements throughout the organization to address the deficiencies noted by PwC, as well as others identified by employees and management during the course of our internal review procedures.

Management believes it will be able to complete all internal control documentation and control design assessment procedures by the end of the fourth quarter 2004. However, the frequency of the operation of key controls implemented or modified during the fourth quarter 2004 may limit management’s ability to complete its tests of operating effectiveness of key internal controls. As our control systems are tested, we will continue to implement changes to our policies, procedures, systems and personnel as necessary to endeavor to comply with the control standards established under Section 404 of the Sarbanes-Oxley Act of 2002.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

Reference is made to Note 13 of our Consolidated Financial Statements in Part I Item 1 of this Form 10-Q, which is incorporated herein by reference.

Item 6. Exhibits

2.1(1)		Asset Purchase and Sale Agreement and addendum, thereto, dated as of July 1, 2004 by and between American Central Eastern Texas Gas Company Limited Partnership, ACGC Gathering Company, L.L.C. and MarkWest Energy East Texas Gas Company’s L.P.

4.1(1)		Unit Purchase Agreement dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and MarkWest Energy GP, L.L.C. and each of Kayne Anderson Energy Fund II, L.P., Kayne Anderson Capital Income Partners, L.P., Kayne Anderson MLP Fund, L.P., Kayne Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR RV Performance Master Trust, Tortoise Energy Infrastructure Corporation and Energy Income and Growth Fund, as Purchasers.

4.2(1)		Registration Rights Agreement dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and each of Kayne Anderson Energy Fund II, L.P., Kayne Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR RV Performance Master Trust, Tortoise Energy Infrastructure Corporation and Energy Income and Growth Fund.

31.1		Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.3		Certification of the Chief Accounting Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

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

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

99.1(1)		Second Amended and Restated Credit Agreement dated as of July 30, 2004 among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe Generale, as Documentation Agent to the $315,000,000 Senior Credit Facility.

99.2(1)		First Amendment to the Second Amended and Restated Credit Agreement dated as of August 20, 2004, among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe Generale, as Documentation Agent.


99.3(2)		Firm Gas Processing Agreement (Dwale) entered into on September 23, 2004 between Equitable Production Company and MarkWest Hydrocarbon, Inc.

99.4(2)		Sale and Purchase of Natural Gas Agreement entered into on September 23, 2004 between Equitable Production Company and MarkWest Hydrocarbon, Inc.

99.5(2)		Netting, Financial Responsibility and Security Agreement entered into on September 23, 2004 between Equitable Production Company and MarkWest Hydrocarbon, Inc.

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

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

SIGNATURE

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

		MarkWest Hydrocarbon, Inc.
		(Registrant)

Date: November 22, 2004	/s/ James G. Ivey
	James G. Ivey
	Chief Financial Officer

Exhibit Number		Exhibit Index

2.1(1)		Asset Purchase and Sale Agreement and addendum, thereto, dated as of July 1, 2004 by and between American Central Eastern Texas Gas Company Limited Partnership, ACGC Gathering Company, L.L.C. and MarkWest Energy East Texas Gas Company’s L.P.

4.1(1)		Unit Purchase Agreement dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and MarkWest Energy GP, L.L.C. and each of Kayne Anderson Energy Fund II, L.P., Kayne Anderson Capital Income Partners, L.P., Kayne Anderson MLP Fund, L.P., Kayne Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR RV Performance Master Trust, Tortoise Energy Infrastructure Corporation and Energy Income and Growth Fund, as Purchasers.

4.2(1)		Registration Rights Agreement dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and each of Kayne Anderson Energy Fund II, L.P., Kayne Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR RV Performance Master Trust, Tortoise Energy Infrastructure Corporation and Energy Income and Growth Fund.

31.1		Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.3		Certification of the Chief Accounting Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

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

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

99.1(1)		Second Amended and Restated Credit Agreement dated as of July 30, 2004 among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe Generale, as Documentation Agent to the $315,000,000 Senior Credit Facility.

99.2(1)		First Amendment to the Second Amended and Restated Credit Agreement dated as of August 20, 2004, among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe Generale, as Documentation Agent.

99.3(2)		Firm Gas Processing Agreement (Dwale) entered into on September 23, 2004 between Equitable Production Company and MarkWest Hydrocarbon, Inc.

99.4(2)		Sale and Purchase of Natural Gas Agreement entered into on September 23, 2004 between Equitable Production Company and MarkWest Hydrocarbon, Inc.

99.5(2)

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

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

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