MARKWEST ENERGY PARTNERS, L.P.

(UNAUDITED)

(in thousands)

	September 30, 2004			December 31, 2003
ASSETS
Current assets:
Cash and cash equivalents	$	13,037		$	8,753
Restricted cash	550			—
Receivables, net	22,419			11,942
Receivables from affiliates	6,601			2,417
Inventories	171			353
Other assets	90			223
Total current assets	42,868			23,688

Property, plant and equipment	316,823			224,534
Less: Accumulated depreciation	(51,107		)	(40,320		)
Total property, plant and equipment, net	265,716			184,214

Intangible assets, net	162,607			—
Deferred financing costs, net	7,183			3,831
Deferred offering costs	—			995
Risk management receivable	—			—
Investment in and advances to equity investee	200			250
Total assets	$	478,574		$	212,978

LIABILITIES AND CAPITAL

Current liabilities:
Accounts payable	$	21,396		$	14,064
Payables to affiliates	4,528			1,524
Accrued liabilities	9,873			5,163
Risk management liability	561			373
Total current liabilities	36,358			21,124

Long-term debt	197,500			126,200
Risk management liability	—			125
Other liabilities	478			478
Commitments and contingencies

Capital:
Partners’ capital	244,799			65,549
Accumulated other comprehensive loss	(561		)	(498		)
Total capital	244,238			65,051
Total liabilities and capital	$	478,574		$	212,978

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

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except per unit amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Revenues:
Sales to unaffiliated parties	$	61,833		$	18,888		$	161,978		$	42,741
Sales to affiliate	15,250			12,524			43,349			36,000
Total revenues	77,083			31,412			205,327			78,741

Operating expenses:
Purchased product costs	51,635			18,510			146,695			45,325
Facility expenses	8,380			5,396			20,801			14,900
Selling, general and administrative expenses	3,887			1,883			8,611			4,814
Depreciation and amortization	5,672			2,026			12,343			5,231
Total operating expenses	69,574			27,815			188,450			70,270

Income from operations	7,509			3,597			16,877			8,471

Other income (expense):
Interest expense, net	(7,089		)	(847		)	(9,891		)	(2,592		)
Miscellaneous income (expense)	(213		)	17			(214		)	51

Net income	$	207		$	2,767		$	6,772		$	5,930

Interest in net income:
General partner	$	330		$	86		$	858		$	178
Limited partners	$	(123	)	$	2,681		$	5,914		$	5,752

Net income per limited partner unit:
Basic	$	(0.02	)	$	0.46		$	0.81		$	1.04
Diluted	$	(0.02	)	$	0.46		$	0.81		$	1.03

Weighted average units outstanding:
Basic	8,163			5,783			7,315			5,543
Diluted	8,183			5,833			7,340			5,593

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

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME

(UNAUDITED)

(in thousands)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2004		2003		2004			2003
Net income	$	207	$	2,767	$	6,772		$	5,930

Other comprehensive income (loss):
Risk management activities	584		439		(63		)	240

Comprehensive income	$	791	$	3,206	$	6,709		$	6,170

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

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)

	Nine Months Ended September 30,
	2004			2003
Cash flows from operating activities:
Net income	$	6,772		$	5,930
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	10,976			5,231
Loss from sale of property, plant and equipment	180			—
Amortization of deferred financing costs included in interest expense	3,781			702
Amortization of deferred cost of gas contracts	1,367			—
Non-cash compensation expense	732			554
Other	54			20
Changes in operating assets and liabilities:
(Increase) decrease in receivables	(14,661		)	3,369
Decrease in inventories	182			16
Decrease in other current assets	133			285
Increase in accounts payable and accrued liabilities	15,292			333
Net cash provided by operating activities	24,808			16,440

Cash flows from investing activities:
Increase in restricted cash	(550		)	—
East Texas System acquisition	(240,607		)	—
Hobbs Lateral acquisition	(2,275		)	—
Capital expenditures	(13,843		)	(1,934		)
Pinnacle acquisition, net of cash acquired	—			(38,238		)
Lubbock pipeline acquisition	—			(12,222		)
Proceeds from sale of assets	148			3
Net cash used in investing activities	(257,127		)	(52,391		)

Cash flows from financing activities:
Payments for debt issuance costs	—			(760		)
Proceeds from debt	215,600			67,600
Repayment of debt	(144,300		)	(27,700		)
Increase in deferred financing costs	(7,192		)	—
Proceeds from secondary offerings, net	139,761			—
Proceeds from private placement of common units, net	44,156			9,764
Capital contribution from general partner	3,737			201
Contribution by Markwest Hydrocarbon	567			—
Distributions to unitholders	(15,726		)	(9,557		)
Net cash provided by financing activities	236,603			39,548

Net increase in cash	4,284			3,597
Cash and cash equivalents at beginning of period	8,753			2,776
Cash and cash equivalents at end of period	$	13,037		$	6,373

Supplemental cash flow information:
Cash paid for interest	$	4,607		$	1,021

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

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENT OF CHANGES IN CAPITAL

(UNAUDITED)

(in thousands)

														Accumulated
	PARTNERS’ CAPITAL													Other
	Limited Partners								General					Comprehensive
	Common				Subordinated				Partner			Other		Loss
	Units	$			Units	$			$			$		$			Total
Balance, December 31, 2003	2,814	$	51,043		3,000	$	13,369		$	442		$	695	$	(498	)	$	65,051

Proceeds from secondary offerings, net	3,497	138,766			—	—			2,826			—		—			141,592

Proceeds from private placement, net	1,304	44,156			—	—			901			—		—			45,057

Phantom unit vest	23	977			—	—			10			—		—			987

Contribution by Markwest Hydrocarbon	—	—			—	—			—			567		—			567

Net income	—	3,197			—	2,716			859			—		—			6,772

Distributions to partners	—	(8,388		)	—	(6,300		)	(1,038		)	—		—			(15,726		)

Other comprehensive loss	—	—			—	—			—			—		(63		)	(63		)

Balance, September 30, 2004	7,638	$	229,751		3,000	$	9,786		$	4,000		$	1,262	$	(561	)	$	244,238

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

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. Organization

MarkWest Energy Partners, L.P. (“MarkWest Energy Partners”, the “Partnership”, “we” or “us”), a Delaware limited partnership, was formed in January 2002 to own and operate substantially all of the assets, liabilities and operations of MarkWest Hydrocarbon, Inc.’s (“MarkWest Hydrocarbon”) midstream business. Through its majority ownership of our general partner, MarkWest Energy, GP, L.L.C. (the “general partner”), MarkWest Hydrocarbon operates our business. We are engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of NGL products; and the gathering and transportation of crude oil. We are not a taxable entity because of our partnership structure.

2. Basis of Presentation

The accompanying unaudited consolidated financial statements include the accounts of MarkWest Energy Partners and its wholly and majority owned subsidiaries. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States for interim financial reporting. The year-end consolidated balance sheet data was derived from audited financial statements. Preparation of these financial statements involves the use of estimates and judgments where appropriate. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s results of operations, financial position and cash flows for the periods shown have been made. All such adjustments are of a normal recurring nature. You should read these consolidated financial statements and notes thereto along with the audited financial statements and notes thereto included in our December 31, 2003 Annual Report on Form 10-K, as amended. Results for the three and nine months ended September 30, 2004, are not necessarily indicative of results for the full year 2004 or any other future period.

3. Cash Restrictions

Restricted cash is comprised of $0.6 million and is a deposit to secure our current and future swap positions with a bank.

4. Equity Offerings

During January 2004, the Partnership completed a secondary public 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. Total gross proceeds of $47.8 million less associated offering costs of $3.8 million, of which $0.1 million related to the general partner’s share, resulted in net proceeds from the secondary public offering of $43.9 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 $44.9 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 our 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, we completed a secondary public offering of 2,323,609 of our 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 by us, 323,609 common units were sold pursuant to the underwriters’ over-allotment option. We did not receive any proceeds from the common units sold by the selling unitholders. Our total net proceeds from the offering, after deducting transaction costs of $5.2 million and including our general partner’s 2% capital contribution of $2.1 million, were $97.8 million and were used to repay a portion of the

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

outstanding indebtedness under our amended and restated credit facility.

5. Acquisitions

East Texas System Acquisition

On July 30, 2004, we 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. The Partnership’s consolidated financial statements include American Central East Texas’ 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 our existing businesses in several ways and provides us 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 us to offer both low- and high-pressure service to our 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 us because it has long-lived reserves and significant development potential. The East Texas System also provides us with a platform on which to vertically integrate our business through construction of a natural gas processing facility and NGL pipeline. We have already obtained contractual commitments that will fill the plant’s capacity.

In conjunction with the closing of the acquisition, we completed an offering of 1,304,438 of our common units, at $34.50 per unit, which netted us approximately $44.9 million after transaction costs and the general partner contribution. In addition, we amended and restated our credit facility, increasing our 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. We used the proceeds from the offering and borrowings under our 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, we amended and restated our credit facility, decreasing our maximum lending limit from $315.0 million to $200.0 million and increasing the term of the facility to five years (See note 8).

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 7).

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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, we 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, we 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

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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, we completed the acquisition (the “Lubbock Pipeline acquisition”) of a 68-mile intrastate gas transmission pipeline near Lubbock, Texas from a subsidiary of ConocoPhillips for approximately $12.2 million. The transaction was financed through borrowings under our 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, we 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.

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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	$	80,656	$	50,133	$	226,005	$	155,016
Net income (loss)	$	574	$	1,075	$	7,327	$	(5,356	)
Basic net income (loss) per limited partner unit	$	0.03	$	0.11	$	0.78	$	(0.68	)
Diluted net income (loss) per limited partner unit	$	0.03	$	0.11	$	0.77	$	(0.68	)

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

6. Property, Plant and Equipment

The following provides composition of the Partnership’s 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
Land, building and other equipment	8,216			9,664
Construction in-progress	21,075			1,841
	316,823			224,534
Less: Accumulated depreciation	(51,107		)	(40,320		)
Total property, plant and equipment, net	$	265,716		$	184,214

7. Intangible Assets subject to Amortization

On July 30, 2004, we 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 were the assumption of renewals, economic incentives to retain customers, historical volumes, current and future capacity of the gathering system, and pricing volatility. The Partnership is amortizing the fair value of these customer contracts on a straight-line basis over an estimated economic life of 20 years. The estimated economic life was determined by assessing the life of the assets to which the contracts relate, likelihood of renewals, competitive factors, regulatory or legal provisions, and maintenance and renewal costs. The 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 at September 30, 2004, are composed of (in thousands):

	Gross		2004 Accumulated Amortization		Net
Customer contracts (20 years)	$	163,973	$	1,366	$	162,607

Amortization expense related to purchased intangible assets was $1.4 million for the nine months ended September 30, 2004.

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

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Year ending December 31,:
2004	$	2,050
2005	8,199
2006	8,199
2007	8,199
2008	8,199
2009	8,199
Thereafter	119,562

8. Debt

In July 2004 and August 2004, we amended and restated our credit facility, increasing our 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. We used the proceeds from the offering and borrowings under our 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. We are 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, we amended and restated our credit facility, decreasing our 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 our present and future subsidiaries and is collateralized by substantially all of our existing and future assets and those of our subsidiaries, including stock and other equity interests. The borrowing under our 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 our ratio of funded debt to EBITDA (as defined in the credit agreement). Consequently, as of September 30, 2004, we have classified our debt balance as non-current.

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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, we are subject to certain financial maintenance covenants, including our 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 our debt and other financial obligations.

In October 2004, we 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, we may issue additional notes from time to time under the indenture. Interest on the notes accrues at the rate of 6.875% per year and is payable semi-annually in arrears on May 1 and November 1, commencing on May 1, 2005. We 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 we 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, we 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 we sell certain assets and do not reinvest the proceeds or repay senior indebtedness, or if we experience specific kinds of changes in control, we must offer to repurchase notes at a specified price. Each of our existing subsidiaries, other than MarkWest Energy Finance Corporation, has guaranteed the notes initially and so long as such subsidiary guarantees any of our other debt. Not all of our future subsidiaries will have to become guarantors. The notes are senior unsecured obligations equal in right of payment with all of our existing and future senior debt. These notes are senior in right of payment to all of our future subordinated debt but effectively junior in right of payment to our secured debt to the extent of the assets securing the debt, including our obligations in respect of our bank credit facility. The proceeds from these notes were used to pay down our outstanding debt under our credit facility.

9. Distribution to Unitholders

On April 21, 2004, the board of directors of the general partner of the Partnership declared a cash distribution of $0.69 per unit on its outstanding common and subordinated units for the quarter ended March 31, 2004. The approximate $5.2 million distribution, including $0.3 million distributed to the general partner, was paid on May 14, 2004, to unitholders of record as of the close of business on April 30, 2004.

On July 21, 2004, the board of directors of the general partner of the Partnership declared a cash distribution of $0.74 per common and subordinated unit for the quarter ended June 30, 2004. The approximate $10.5 million distribut ion, including $1.0 million distributed to the general partner, was paid on August 13, 2004, to unitholders of record as of July 30, 2004.

Subsequent Event

On October 25, 2004, the board of directors of the general partner of the Partnership declared a cash distribution of $0.76 per common unit for the quarter ended September 30, 2004. The distribution will be paid on November 12, 2004, to unitholders of record on November 3, 2004.

10. Net Income Per Limited Partner Unit

Basic net income per unit is determined by dividing net income, after deducting the general partner’s 2% interest (including any incentive distribution rights), by the weighted average number of outstanding common units and subordinated units. Diluted net income per unit is a similar calculation, increased to include the dilutive effect of outstanding restricted units.

11. Unit Compensation

As permitted under 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 unit-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. We apply variable accounting for our plan. 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. Accelerated vesting, at the discretion of the general partner of the Partnership, results in an immediate charge to operations.

In the first quarter and third quarter of 2004, the Partnership achieved a specified annualized distribution objective, thereby accelerating the vesting of approximately 10,800, 10,171 and 2,250 restricted units as of February 23, 2004, August 23, 2004 and September 1, 2004, respectively. The board of directors of our general partner had approved the accelerated vesting of restricted unit grants upon the achievement of specified performance goals in October 2003. The fair market value on February 23, 2004 was $39.32 per common unit resulting in a $0.4 million increase to common units. The fair market value on August 23, 2004 was $44.73 per common unit resulting in a $0.5 million increase to common units. The fair market value on September 1, 2004 was $43.71 per common unit resulting in a $0.1 million increase to common units.

In addition, for the three months ended September 30, 2004 and 2003, we recorded compensation expense of $0.5 million and $0.1 million, respectively, related to our variable plan. For the nine months ended September 30, 2004 and 2003, we recorded compensation expense of $0.8 million and $0.6 million, respectively. These charges are included in selling, general and administrative expenses. Assuming the compensation cost for our unit-based employee compensation plans had been determined based on the fair-value methodology of SFAS No. 123, the compensation expense recognized for the three and nine months ended September 30, 2004 and 2003, would have been the same.

12. Adoption of SFAS No. 143

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

The Partnership’s assets subject to asset retirement obligations are primarily certain gas gathering pipelines and processing facilities, a crude oil pipeline and other related pipeline assets.

In connection with the adoption of SFAS No. 143, we reviewed current laws and regulations governing obligations for asset retirements as well as our leases. Based on that review, certain of our properties did not have any legal obligations associated with the retirement of our tangible long-lived assets.

The Partnership has identified certain of its assets as having an indeterminate life in accordance with SFAS No. 143, which does not trigger a requirement to establish a fair value for future retirement obligations associated with such assets. These assets include certain pipelines and processing plants. A liability for these asset retirement obligations will be recorded if and when a future retirement obligation is identified.

The asset retirement obligation associated with the remaining facilities was immaterial and not recognized in the financial statements.

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	Appalachia		Michigan		Southwest		Total
	(in thousands)
Three Months Ended September 30, 2004:
Revenues:
Unaffiliated parties	$	435	$	3,998	$	57,400	$	61,833
Affiliate	15,250		—		—		15,250
Depreciation and amortization	977		1,313		3,382		5,672
Segment operating income	3,381		229		7,786		11,396
Capital expenditures	495		697		5,645		6,837
Total segment assets	48,608		55,930		374,036		478,574

Three Months Ended September 30, 2003:
Revenues:
Unaffiliated parties	$	434	$	3,124	$	15,330	$	18,888
Affiliate	12,524		—		—		12,524
Depreciation	718		588		720		2,026
Segment operating income	3,759		147		1,574		5,480
Capital expenditures	195		20		575		790
Total segment assets	48,563		35,282		58,445		142,290

The following is a reconciliation of segment operating income, as stated above, to the consolidated statements of operations, as selling, general and administrative expenses are not allocated to our Appalachia, Michigan and Southwest operations, and a reconciliation to net income:

	Three Months Ended September 30,
	2004			2003
	(in thousands)
Segment operating income	$	11,396		$	5,480
Selling, general and administrative expenses	3,887			1,883

Income from operations	7,509			3,597

Interest expense, net	(7,089		)	(847		)
Miscellaneous income (expense)	(213		)	17
Net income	$	207		$	2,767

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	Appalachia		Michigan		Southwest		Total
	(in thousands)
Nine Months Ended September 30, 2004:
Revenues:
Unaffiliated parties	$	1,256	$	11,548	$	149,174	$	161,978
Affiliate	43,349		—		—		43,349
Depreciation and amortization	2,765		3,432		6,146		12,343
Segment operating income	10,236		1,206		14,046		25,488
Capital expenditures	1,794		1,555		10,493		13,842
Total segment assets	48,608		55,930		374,036		478,574

Nine Months Ended September 30, 2003:
Revenues:
Unaffiliated parties	$	898	$	9,007	$	32,836	$	42,741
Affiliate	36,000		—		—		36,000
Depreciation	2,149		1,762		1,320		5,231
Segment operating income	9,761		460		3,064		13,285
Capital expenditures	647		21		1,266		1,934
Total segment assets	48,563		35,282		58,445		142,290

	Nine Months Ended September 30,
	2004			2003
	(in thousands)
Segment operating income	$	25,488		$	13,285
Selling, general and administrative expenses	8,611			4,814

Income from operations	16,877			8,471

Interest expense, net	(9,891		)	(2,592		)
Miscellaneous income (expense)	(214		)	51

Net income	$	6,772		$	5,930

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.

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 $0.2 million, or negative $0.02 per diluted limited partner unit, compared to net income of $2.8 million, or $0.46 per diluted limited partner unit, for the third quarter of 2003. Interest expense increased significantly for the quarter, driven by our late 2003 acquisitions and our recent acquisition of the East Texas System. For the nine months ended September 30, 2004, the Partnership reported net income of $6.8 million, or $0.81 per diluted limited partner unit, compared to net income of $5.9 million or $1.03 per diluted limited partner unit, for the nine months ended September 30, 2003.

Income from operations for the third quarter more than doubled, increasing by $3.9 million relative to the same time period last year. Interest expense increased by $6.2 million, of which $2.9 million was due to write-off and amortization of deferred financing costs relating to the amended and restated credit facility entered into on July 30, 2004. The balance of the increase in interest expense is attributable to greater debt levels compared to 2003 and higher interest rates.

Year-to-date net income increased by $0.8 million over the comparable prior period, driven by the same combination of factors impacting the third quarter comparisons. Income from operations also nearly doubled, increasing by $8.4 million. Year-to-date net income increased over the comparable prior period primarily due to the strong contributions of our 2003 and 2004 acquisitions.

On October 25, 2004, the board of directors of the general partner of MarkWest Energy Partners, L.P., declared the Partnership’s quarterly cash distribution of $0.76 per common and subordinated unit for the third quarter of 2004. This distribution represents an increase of $0.02 per unit over the previous quarter’s distribution. The indicated annual rate is $3.04 per unit. The third quarter distribution is payable November 12, 2004, to unitholders of record on November 3, 2004.

Our Business

We are a Delaware limited partnership that was formed by MarkWest Hydrocarbon on January 25, 2002, to acquire most of the assets, liabilities and operations of the MarkWest Hydrocarbon midstream energy business. Since our initial public offering in May of 2002, we have significantly expanded our operations through a series of acquisitions. We are engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of NGL products; and the gathering and transportation of crude oil.

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 the contracts from which we derive our revenues;

• The difficulty in comparing our results of operations across periods because of our significant and recent acquisition activity; and

• The nature of our relationship with MarkWest Hydrocarbon, Inc.

Our Contracts

We generate the majority of our 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. In our current areas of operations, we have a combination of contract types. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described below. While all of these services constitute midstream energy operations, we provide services under the following five types of contracts.

• Fee-based contracts. Under fee-based contracts, we receive 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 we earn from these contracts is directly related to the volume of natural gas, NGLs or crude oil that flows through our systems and facilities and is not directly dependent on commodity prices. In certain cases, our contracts provide for minimum annual payments. To the extent a sustained decline in commodity prices results in a decline in volumes, however, our revenues from these contracts would be reduced.

• Percent-of-proceeds contracts. Under percent-of-proceeds contracts, we generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGLs at market prices and remit 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, we deliver an agreed upon percentage of the residue gas and NGLs to the producer and sell the volumes we keep to third parties at market prices. Under these types of contracts, our revenues and gross margins increase as natural gas prices and NGL prices increase, and our revenues and gross margins decrease as natural gas prices and NGL prices decrease.

• Percent-of-index contracts. Under percent-of-index contracts, we generally purchase 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. We then gather and deliver the natural gas to pipelines where we resell the natural gas at the index price. With respect to (1) and (3) above, the gross margins we realize 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, we gather natural gas from the producer, process the natural gas and sell 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, we 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, our revenues and gross margins increase as the price of NGLs increase relative to the price of natural gas, and our revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs.

• East Texas System gathering arrangements. We gather 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 our East Texas System gathering arrangements specify that we are 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, we are entitled to retain the difference for our 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, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix and, accordingly, our exposure to natural gas and NGL prices, may change as a result of changes in producer preferences, our expansion in regions where some types of contracts are more common and other market factors. Any change in our contract mix may impact our financial results.

At September 30, 2004, our primary exposure to keep-whole contracts was limited to our Arapaho (OK) processing plant and our 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, we have 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 our 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, our overall keep-whole contract exposure is limited to a portion of the operating costs of the plant.

In regards to our exposure to keep-whole contracts in Carthage, we have a third party processing agreement to offer percent of liquids (“POL”) processing services to area customers and to process gas for our 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, our exposure is limited by our ability to reject or recover ethane to help manage the keep-whole processing volumes.

For the nine months ended September 30, 2004, we generated the following percentages of our revenues and gross margin from the following types of contracts:

	Fee-Based		Percent-of- Proceeds(1)		Percent-of- Index(2)		Keep- Whole(3)		Total
Revenues	17	%	15	%	22	%	46	%	100	%
Gross Margin	61	%	10	%	10	%	19	%	100	%

(1) Includes other contracts tied to NGL prices.

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

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

Comparability of Financial Results

Recent Acquisition Activity

In reading the discussion of our historical results of operations, you should be aware of our significant and recent acquisitions, which fundamentally impact the comparability of our results of operations over the periods discussed.

Since our initial public offering, we have completed six acquisitions for an aggregate amount of approximately $354.3 million of assets. These six acquisitions include:

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

Results of Operations

Operating Data

	Three Months Ended September 30,		Nine Months Ended September 30,
	2004	2003	2004	2003
Appalachia:
Natural gas processed for a fee (Mcf/d)(1)	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)(2)	15,100	—	14,800	—
Southwest:
Gathering systems throughput (Mcf/d):
East Texas System(3)	246,600	—	246,600	—
Foss Lake (OK)(4)	63,300	—	60,700	—
Appleby(5)	24,500	25,200	23,300	24,300
Other gathering systems(5)	15,500	21,300	17,700	21,100
Lateral throughput volumes (Mcf/d)(6)	97,200	43,600	83,100	43,600
NGL product sales (gallons):
Arapaho (OK)(7)	12,174,000	—	28,686,000	—
East Texas System(3)	12,268,000	—	12,268,000	—

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

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

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

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

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

(6) 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 lateral pipelines is excluded from this statistic.

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

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

	Three Months Ended September 30,						Change
	2004			2003			$			%
	(dollars in thousands)
Revenues:
Sales to unaffiliated parties	$	61,833		$	18,888		$	42,945		227	%
Sales to affiliate	15,250			12,524			2,726			22	%
Total revenues	77,083			31,412			45,671			145	%

Operating expenses:
Purchased product costs	51,635			18,510			33,125			179	%
Facility expenses	8,380			5,396			2,984			55	%
Selling, general and administrative	3,887			1,883			2,004			106	%
Depreciation and amortization	5,672			2,026			3,646			180	%
Total operating expenses	69,574			27,815			41,759			150	%

Income from operations	7,509			3,597			3,912			109	%

Other income (expense):
Interest expense, net	(7,089		)	(847		)	(6,242		)	737	%
Other income (expense)	(213		)	17			(230		)	(1,353	)%

Net income	$	207		$	2,767		$	(2,560	)	(93	)%

Revenues. Revenues increased during the three months ended September 30, 2004, relative to the same time period in 2003 primarily due to our 2003 and 2004 acquisitions.

Purchased Product Costs. Purchased product costs increased during the three months ended September 30, 2004, relative to the same time period in 2003 primarily due to our 2003 and 2004 acquisitions, which increased purchased product costs approximately $30.6 million. The remainder of the increase is principally attributable to price and volume increases for our Appalachia NGL product sales.

Facility Expenses. Facility expenses increased during the three months ended September 30, 2004, relative to the same time period in 2003 primarily due to our 2003 and 2004 acquisitions.

Selling, General and Administrative Expenses. Selling, general and administrative expenses (“SG&A”) increased during the three months ended September 30, 2004, relative to the same time period in 2003 primarily because of increased professional services costs, increased administrative costs associated with our acquisitions and Sarbanes-Oxley compliance expenses.

Depreciation and Amortization. Depreciation and amortization increased during the three months ended September 30, 2004, relative to the same time period in 2003 primarily due to our 2003 and 2004 acquisitions, which increased depreciation and amortization by approximately $3.0 million for the quarter. Additionally, commencing January 1, 2004, we accelerated 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.

Interest Expense. Interest expense increased during the three months ended September 30, 2004, relative to the same time period in 2003 primarily due to increased debt levels resulting from the financing of our late 2003 and

2004 acquisitions. Additionally, we incurred approximately $1.0 million in accelerated amortization of deferred financing costs due to the refinancing of our credit facility in July 2004.

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

	Nine Months Ended September 30,						Change
	2004			2003			$			%
	(dollars in thousands)
Sales to unaffiliated parties	$	161,978		$	42,741		$	119,237		279	%
Sales to affiliate	43,349			36,000			7,349			20	%
Total revenues	205,327			78,741			126,586			161	%

Operating expenses:
Purchased product costs	146,695			45,325			101,370			224	%
Facility expenses	20,801			14,900			5,901			40	%
Selling, general and administrative	8,611			4,814			3,797			79	%
Depreciation and amortization	12,343			5,231			7,112			136	%
Total operating expenses	188,450			70,270			118,180			168	%

Income from operations	16,877			8,471			8,406			99	%

Other income (expense):
Interest expense, net	(9,891		)	(2,592		)	(7,299		)	282	%
Other income (expense)	(214		)	51			(265		)	(520	)%

Net income	$	6,772		$	5,930		$	842		14	%

Revenues. Revenues increased during the first nine months of 2004 relative to the same time period in 2003 primarily due to our 2003 and 2004 acquisitions.

Purchased Product Costs. Purchased product costs increased during the first nine months of 2004 relative to the same time period in 2003 primarily due to our 2003 and 2004 acquisitions, which increased purchased product costs approximately $94.1 million. The remainder of the increase is primarily attributable to price and volume increases for our Appalachia NGL product sales.

Facility Expenses. Facility expenses increased approximately $6.4 million during the first nine months of 2004 relative to the same time period in 2003 primarily due to our 2003 and 2004 acquisitions. Reductions in expenses of approximately $0.5 million at our historical Michigan operations due to reduced throughput and general reductions in operating and maintenance expense partially offset the increase from our late 2003 and 2004 acquisitions.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased during the first nine months of 2004 relative to the same time period in 2003 primarily because MarkWest Hydrocarbon was contractually limited in the amount it could charge us to $4.9 million annually, or approximately $1.2 million per quarter, from May 24, 2002, the date of our initial public offering, through May 23, 2003. The contractual limit was in place during the first quarter of 2003 but has since lapsed. In addition, selling, general and administrative expenses have increased due to increased professional services costs, increased administrative costs associated with our acquisitions and Sarbanes-Oxley compliance expenses.

Depreciation and Amortization. Depreciation and amortization increased during the first nine months of 2004 relative to the same time period in 2003 primarily due to our 2003 and 2004 acquisitions, which increased depreciation and amortization approximately $4.9 million. Additionally, commencing January 1, 2004, we

accelerated 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.

Interest Expense. Interest expense increased during the first nine months of 2004 relative to the same time period in 2003 primarily due to increased debt levels resulting from the financing of our 2003 and 2004 acquisitions. Additionally, we incurred approximately $1.0 million in accelerated amortization of deferred financing costs due to the refinancing of our credit facility in July 2004.

Liquidity and Capital Resources

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

During July 2004, we completed a private placement of 1,304,438 of our common units, at $34.50 per unit, which netted us approximately $44.9 million after transaction costs and the general partner contribution. In addition, we amended and restated our credit facility in July 2004, increasing our maximum lending limit from $140.0 million to $315.0 million. We used the proceeds from the offering and borrowings under our credit facility to finance the East Texas System acquisition.

The credit facility includes a $265.0 million revolving facility and a $50.0 million term-loan facility. The term-loan portion of the amended and restated credit facility matures in December 2004 and the revolving-portion matures in May 2005. Under the term loan, to the extent that a portion or all of the term loan is paid, then those amounts so paid 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 under the Partnership credit facility. We paid off the term loan portion from the proceeds of our September 2004 public equity offering. In October 2004, we amended and restated our credit facility, decreasing our maximum lending limit from $315.0 million to $200.0 million and increasing the term of the facility to five years.

On September 21, 2004, we completed a public offering of 2,323,609 of our 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 by us, 323,609 common units were sold pursuant to the underwriter’s over-allotment option. We did not receive any proceeds from the common units sold by the selling unitholders. Our total net proceeds from the offering, after deducting transaction costs of $5.2 million and including our 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 our amended and restated credit facility.

Cash generated from operations, borrowings under our credit facility and funds from our private and public equity offerings are our primary sources of liquidity. We believe that funds from these sources will be sufficient to meet both our short-term and long-term working capital requirements and anticipated capital expenditures. Our ability to fund additional acquisitions will likely require the issuance of additional common units, the expansion of our credit facility, additional debt financing or a combination of all three. In the event that we desire or need to raise additional capital, we cannot guarantee that additional funds will be available at times or on terms favorable to us. Our desire to raise additional funds could also directly and adversely affect our unitholders’ investment in our common units. When a partnership raises funds by issuing common units through additional public offerings, the percentage ownership of the existing unitholders of that partnership is reduced or diluted. If we raise funds in the future by issuing additional common units, unitholders may experience dilution in the value of their units.

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

Our largest customer is MarkWest Hydrocarbon. Consequently, matters affecting the business and financial

condition of MarkWest Hydrocarbon—including its operations, management, customers, vendors, and the like—have the potential to impact, both positively and negatively, our liquidity.

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

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 our 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 our present and future subsidiaries and is collateralized by substantially all of our existing and future assets and those of our subsidiaries, including stock and other equity interests. The borrowing under our 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 our ratio of funded debt to EBITDA (as defined in the credit agreement). We are 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, we are subject to a number of restrictions on our business, including restrictions on our 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, we are subject to certain financial maintenance covenants, including our 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 our debt and other financial obligations.

Concurrent with the amendment of our credit facility, in October 2004, we 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, we 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. We 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 we 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, we 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 we sell certain assets and do not reinvest the proceeds or repay senior indebtedness, or if we experience specific kinds of changes in control, we must offer to repurchase notes at a specified price. Each of

our existing subsidiaries, other than MarkWest Energy Finance Corporation, has guaranteed the notes initially and so long as such subsidiary guarantees any of our other debt. Not all of our future subsidiaries will have to become guarantors. The notes are senior unsecured obligations with equal in right of payment with all of our existing and future senior debt. These notes are senior in right of payment to all of our future subordinated debt but effectively junior in right of payment to our secured debt to the extent of the assets securing the debt, including our obligations in respect of our bank credit facility. Borrowings under these notes were used to pay down our outstanding debt under our 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 has $225.0 million of senior Indebtedness outstanding, comprised of $225.0 million unsecured senior notes at a fixed rate of 6.875%. The goal remains for us to maintain a debt-to-total capital ratio of less than 50 percent in keeping with our long-term balance sheet objectives.

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	$	7,295	$	4,269	$	2,285	$	741
Debt	197,500		—		—		197,500
Total	$	204,795	$	4,269	$	2,285	$	198,241

Cash Flows

	Nine Months Ended September 30,
	2004			2003
	(in thousands)
Net cash provided by operating activities	$	24,808		$	16,440
Net cash used in investing activities	$	(257,127	)	$	(52,391	)
Net cash provided by financing activities	$	236,603		$	39,548

Net cash provided by operating activities for the nine months ended September 30, 2004, increased relative to the same period from the prior year primarily due to an increase in working capital from our 2003 and 2004 acquisitions. The increase is also attributable to an increase in our net income.

Net cash used in investing activities for the nine months ended September 30, 2004, increased relative to the same period from the prior year primarily due to the acquisition of our East Texas System in July 2004 for $240.6 million. In addition, the Partnership used cash of $13.8 million for capital expenditures.

Net cash provided by financing activities during the nine months ended September 30, 2004, was primarily a result of our equity financings and borrowings under our credit facility. In January 2004, the Partnership completed a secondary public offering generating net proceeds of $44.9 million in 2004. We primarily used the proceeds to pay down our outstanding debt. We also amended and restated our credit facility in July 2004 to increase our total borrowing capacity to $315.0 million. We borrowed $200.8 million under this credit facility to partially finance our 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. We used the net proceeds to reduce our outstanding indebtedness. Additionally, we paid out approximately $15.7 million in distributions to unitholders in the nine months ended September 30, 2004. Net cash provided by financing activities for the nine months ended September 30, 2003, was primarily the result of borrowings from our credit facility, which were used to finance the Pinnacle acquisition.

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.

Forward-Looking Statements

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

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

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

• The availability of raw natural gas supply for our gathering and processing services;

• The availability of NGLs for our transportation, fractionation and storage services;

• Our dependence on certain significant customers, producers, gatherers, treaters, and transporters of natural gas, including MarkWest Hydrocarbon;

•&# 160; The risks that third-party oil and gas exploration and production activities will not occur or be successful;

• Prices of NGL products, crude oil, and natural gas, including the effectiveness of any hedging activities;

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

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

• Our ability to identify and consummate grass roots projects or acquisi tions complementary to our business.

Many of such factors are beyond our ability to control or predict. Investors are cautioned not to put undue reliance on forward-looking statements.

In addition, certain of our 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 se rvice, 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, therby requiring us 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 to complain about the transportation rates and question the jurisdictional status of the pipeline. FERC requested that we and the shipper resolve the dispute. If we are unable to

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

For the nine months ended September 30, 2004, approximately 39% of our business (as measured by gross margin, which is defined as revenues less purchased product cost) was directly subject to natural gas and NGL product price risk. This includes our entire gross margin from our business based on percent-of-index contracts, percent-of-proceeds contracts and keep-whole contracts. Regarding the 19% of our gross margin governed by keep-whole contracts, we actively manage our related commodity price risk exposure, to the extent possible, by not operating our 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”.

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 of our general partner, 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 into 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 (with non-bank counterparties) 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 unfavorable changes in such prices.

We are also subject to basis risk, which is the risk that an adverse change in the hedging market will not be completely offset by an equal and opposite change in the price of the physical commodity being hedged. Basis risk is primarily due to geographic price differentials between our physical sales locations and the hedging contract delivery location. While we are able to hedge our basis risk for natural gas commodity transactions in the readily available natural gas financial marketplace, similar markets do not exist for hedging basis risk on NGL products. NGL product basis risk also results from the difference in relative price movements between crude oil and NGL products. We may use crude oil, instead of NGL products, in our hedges because the NGL hedge products and markets are limited. Crude oil is typically highly correlated with certain NGL products. We may hedge our NGL product sales by selling forward propane, other NGLs or crude oil.

We hedge our 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, we hedged our 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, we also had hedged our 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, we had hedged our 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

We are exposed to changes in interest rates, primarily as a result of our long-term debt under our credit facility with floating interest rates. We make 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, we are 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 2. Unregistered Sales of Equity Securities and Use of Proceeds.

(a) On July 30, 2004 the Partnership completed a non-underwritten private placement transaction in which it sold only to accredited investors an aggregate of 1,304,438 common units at an aggregate offering price of $45.0 million. The common units were sold in transactions not involving any public offering within the meaning of Section 4(2) of the Securities Act of 1933, as amended, pursuant to Rule 506 of Regulation D promulgated under the Securities Act. The Partnership filed a Form D with the Securities and Exchange Commission with respect to the transaction on August 19, 2004. The proceeds were used to partially finance the East Texas System acquisition.

(b) N/A

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

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

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

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

32.2		Certification of the Chief 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

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		Chief Executive Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act

31.2		Chief Financial Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act

31.3		Chief Accounting Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act

32.1		Certification of Chief Executive Officer of the General Partner 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 Chief Financial Officer of the General Partner 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 Chief Accounting Officer of the General Partner 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.

(1) Filed as an exhibit to the Registrants’ Form 8KA dated July 30, 2004 and filed on September 13, 2004.

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

Delaware		27-0005456
(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

PART I—FINANCIAL INFORMATION

Item 1.	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 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 Capital for the Nine Months Ended September 30, 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 2.	Unregistered Sales of Equity Securities and Use of Proceeds
Item 6.	Exhibits

SIGNATURE

Glossary of Terms

Bbl/d	barrels of oil per day
Btu	one British thermal unit, 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
MMcf/d	million cubic feet of natural gas per day
NGL	natural gas liquids, such as propane, butanes and natural gasoline

	MarkWest Energy Partners, L.P. (Registrant)


	By:		MarkWest Energy GP, L.L.C.,
			Its General Partner

Date: November 4, 2004	/s/ James G. Ivey
		James G. Ivey
		Chief Financial Officer

		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.

Glossary of Terms

Lubbock Pipeline Acquisition

Pinnacle Acquisition

Pro Forma Results of Operations (Unaudited)

Subsequent event

Subsequent Event

Management Overview of the Three and Nine Months Ended September 30, 2004

Our Business

Results of Operations

Interest Expense. Interest expense increased during the three months ended September 30, 2004, relative to the same time period in 2003 primarily due to increased debt levels resulting from the financing of our late 2003 and

2004 acquisitions. Additionally, we incurred approximately $1.0 million in accelerated amortization of deferred financing costs due to the refinancing of our credit facility in July 2004.

Liquidity and Capital Resources

Cash Flows