PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

MARKWEST ENERGY PARTNERS, L.P.

(UNAUDITED)

(in thousands)

	March 31, 2005			December 31, 2004
ASSETS
Current assets:
Cash and cash equivalents	$	15,184		$	24,263
Receivables, net of allowance for doubtful accounts of $211 and $211, respectively	31,098			41,890
Receivables from affiliate	4,063			5,846
Inventories	518			449
Other assets	368			511
Total current assets	51,231			72,959

Property, plant and equipment	350,613			335,430
Less: Accumulated depreciation and impairment	(58,997		)	(54,795		)
Total property, plant and equipment, net	291,616			280,635

Other Assets:
Investment in Starfish	41,688			—
Investment in and advances to other equity investee	179			177
Fair value of derivative instruments	9			—
Intangibles and other assets, net of accumulated amortization of $5,714 and $3,619, respectively	159,907			162,001
Deferred financing costs, net of accumulated amortization of $6,168 and $5,630, respectively	13,198			13,650
Total other assets	214,981			175,828
Total assets	$	557,828		$	529,422

LIABILITIES AND CAPITAL

Current liabilities:
Accounts payable	$	31,537		$	35,695
Payables to affiliate	5,507			7,003
Accrued liabilities	17,117			19,329
Fair value of derivative instruments	450			385
Total current liabilities	54,611			62,412

Senior notes	225,000			225,000
Long-term debt	40,000			—
Other liabilities	875			868
Commitments and contingencies

Capital:
General partner	5,466			5,160
Limited Partners:
Common unitholders (7,643 and 7,642 units issued and outstanding at March 31, 2005 and December 31, 2004, respectively)	224,641			227,483
Subordinated unitholders (3,000 units issued and outstanding at March 31, 2005 and December 31, 2004)	7,698			8,813
Accumulated other comprehensive loss	(463		)	(314		)
Total capital	237,342			241,142
Total liabilities and capital	$	557,828		$	529,422

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 March 31,
	2005			2004
Revenues:
Sales to unaffiliated parties	$	73,832		$	49,531
Sales to affiliate	15,805			14,294
Total revenues	89,637			63,825

Operating expenses:
Purchased product costs	60,785			47,853
Facility expenses	9,331			6,290
Selling, general and administrative expenses	4,639			2,898
Depreciation	4,326			3,145
Amortization of intangible assets	2,095			34
Accretion of asset retirement and lease obligations	10			—
Total operating expenses	81,186			60,220

Income from operations	8,451			3,605

Other expense:
Interest income	67			7
Interest expense	(3,674		)	(1,129		)
Amortization of deferred financing costs	(475		)	(308		)
Miscellaneous expense	(104		)	(14		)

Net income	$	4,265		$	2,161

Interest in net income (loss):
General partner	$	(81	)	$	(1	)
Limited partners	$	4,346		$	2,162

Net income per limited partner unit:
Basic	$	0.41		$	0.32
Diluted	$	0.41		$	0.32

Weighted average units outstanding:
Basic	10,642			6,777
Diluted	10,673			6,806

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

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL

(UNAUDITED)

(in thousands)

	PARTNERS’ CAPITAL											Accumulated
	Limited Partners											Other
	Common				Subordinated				General			Comprehensive
	Units	Amount			Units	Amount			Partner			Loss			Total
Balance, December 31, 2004	7,642	$	227,483		3,000	$	8,813		$	5,160		$	(314	)	$	241,142

Capital contribution by MarkWest Energy GP, LLC	—	—			—	—			404			—			404

Common units issued for vested restricted units, including contribution by MarkWest Energy GP, LLC	1	36			—	—			—			—			36

Common unit registration costs	—	(38		)	—	—			—			—			(38		)

Participation Plan compensation expense allocated from MarkWest Hydrocarbon	—	—			—	—			1,006			—			1,006

Net income	—	3,121			—	1,225			(81		)	—			4,265

Distributions to partners	—	(5,961		)	—	(2,340		)	(1,023		)	—			(9,324		)

Other comprehensive loss	—	—			—	—			—			(149		)	(149		)

Balance, March 31, 2005	7,643	$	224,641		3,000	$	7,698		$	5,466		$	(463	)	$	237,342

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)

	Three Months Ended March 31,
	2005			2004
Cash flows from operating activities:
Net income	$	4,265		$	2,161
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	4,326			3,145
Amortization of intangible assets	2,095			34
Amortization of deferred financing costs	475			308
Accretion of asset retirement and lease obligations	10			—
Restricted unit compensation expense	230			374
Participation Plan compensation expense	1,006			225
Equity in earnings of investees	(2		)	—
Unrealized gain on derivative instruments	(51		)	—
Gain on sale of property, plant and equipment	(11		)	(24		)
Other	(1		)	5
Changes in operating assets and liabilities:
(Increase) decrease in receivables	10,792			(1,650		)
(Increase) decrease in receivables from affiliates	1,783			(789		)
(Increase) decrease in inventories	(69		)	856
Decrease in other current assets	143			17
Increase (decrease) in accounts payable, accrued liabilities and other liabilities	(5,973		)	477
Increase (decrease) in payables to affiliates	(1,496		)	246
Net cash provided by operating activities	17,522			5,385

Cash flows from investing activities:
Starfish acquisition	(41,688		)	—
Capital expenditures	(15,879		)	(1,524		)
Proceeds from sale of assets	11			32
Payments on financing lease receivable	—			133
Other	—			3
Net cash used in investing activities	(57,556		)	(1,356		)

Cash flows from financing activities:
Proceeds from long-term debt	40,000			—
Repayment of long-term debt	—			(42,000		)
Payment of deferred financing costs and registration costs	(125		)	—
Proceeds from secondary offering, net of offering costs	—			45,391
Capital contributions from MarkWest Energy GP, LLC	404			—
Distributions to unitholders	(9,324		)	(4,957		)
Net cash provided by (used in) financing activities	30,955			(1,566		)

Net increase (decrease) in cash	(9,079		)	2,463
Cash and cash equivalents at beginning of period	24,263			8,753
Cash and cash equivalents at end of period	$	15,184		$	11,216

Supplemental cash flow information:
Construction projects in progress obligation	$	3,401		$	1,199

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”), was formed on January 25, 2002, as a Delaware limited partnership. The Partnership and its wholly owned subsidiary, MarkWest Energy Operating Company, L.L.C. (the “Operating Company”), were formed to acquire, own and operate most of the assets, liabilities and operations of our parent company 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 controls and conducts our operations. We are engaged in the gathering, processing and transmission of natural gas, the transportation, fractionation and storage of natural gas liquids and the gathering and transportation of crude oil. We are a processor of natural gas in the northeastern United States, processing gas from the Appalachian Basin, one of the country’s oldest natural gas producing regions, and from Michigan. Through seven acquisitions completed during 2003, 2004 and 2005, the Partnership has expanded its natural gas gathering, processing and transmission geographic coverage to the southwest United States. 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 the Partnership and its wholly-owned subsidiaries. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial reporting. The year-end consolidated balance sheet data was derived from audited financial statements. 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, 2004 Annual Report on Form 10-K. Results for the three months ended March 31, 2005, are not necessarily indicative of results for the full year 2005 or any other future period.

3. Recent Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment. This statement addresses the accounting for share-based payment transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the enterprise, or (b) liabilities that are based on the fair value of the enterprise’s equity instruments or that may be settled by the issuance of such equity instruments. SFAS No. 123(R) requires an entity to recognize the grant-date fair-value of stock options and other equity-based compensation issued to employees in the income statement. The revised Statement generally requires that an entity account for those transactions using the fair-value-based method, and eliminates the intrinsic value method of accounting in APB Opinion No. 25, Accounting for Stock Issued to Employees, which was permitted under SFAS No. 123, as originally issued. The revised Statement requires entities to disclose information about the nature of the share-based payment transactions and the effects of those transactions on the financial statements. SFAS 123(R) is effective for public companies for the first fiscal year beginning after December 15, 2005. All public companies must use either the modified prospective or the modified retrospective transition method. On March 29, 2005, the SEC staff issued Staff Accounting Bulletin (“SAB”) No. 107, “Share-Based Payment” to express the views of the staff regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. The Partnership will take into consideration the additional guidance provided by SAB 107 in connection with the implementation of SFAS No. 123(R). We have not yet evaluated the impact of the adoption of this pronouncement, which must be adopted in the first quarter of calendar year 2006.

value of the liability can be reasonably estimated. FIN 47 permits, but does not require, restatement of interim financial information. The provisions of FIN 47 are effective for reporting periods ending after December 15, 2005. The Partnership has not yet assessed the impact of adopting FIN 47 on its consolidated financial statements

4. Incentive Compensation Plans

We have elected to continue to measure compensation costs for unit-based employee compensation plans as prescribed by APB 25, Accounting for Stock Issued to Employees, as permitted under SFAS No. 123, Accounting for Stock Based Compensation, and SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure. The Partnership issues restricted units under the MarkWest Energy Partners, L.P. Long-Term Incentive Plan. A restricted unit is a “phantom” unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit, or at the discretion of the Compensation Committee, cash equivalent to the value of a common unit. In accordance with APB 25, we apply variable accounting for our plan because a phantom unit is an award to an employee entitling them to increases in the market value of the Partnership’s units subsequent to the date of grant without issuing units to the employees, similar to a stock appreciation right. As a result, we are required to mark to market the awards at the end of each reporting period. Compensation expense is measured for our phantom unit grants using the market price of MarkWest Energy Partners’ common units on the date the units are granted. The fair value of the units awarded is amortized into earnings over the period of service, adjusted quarterly for the change in the fair value of the unvested unit awards. The phantom units vest over a stated period. For certain employees vesting is accelerated if certain performance measures are met. The accelerated vesting criteria provisions are based on quarterly distribution goals. If the Partnership’s distributions are at or above the goal for a certain number of consecutive quarters, vesting of the employee’s phantom units is accelerated. However, the vesting of any restricted units may not occur until at least one year following the date of grant. The general partner of the Partnership may also elect to accelerate the vesting of outstanding awards, which results in an immediate charge to operations for the unamortized portion of the award.

In the first quarter of 2005, the Partnership achieved a specified annualized distribution goal, thereby accelerating the vesting of 750 phantom units. 750 units were issued in exchange for the vested phantom units. In the first quarter of 2004, the Partnership also achieved a specified annualized distribution goal, thereby accelerating the vesting of 10,932 phantom units as of February 23, 2004. 10,800 units were issued in exchange for the vested phantom units and 132 phantom units were settled for cash. In addition, in the first quarter of 2005 and 2004, the Partnership granted 2,939 and 2,400 phantom units, respectively. 2,500 phantom units were forfeited in the first quarter of 2004. For the three months ended March 31, 2005 and 2004, we recorded compensation expense of $0.2 million and $0.4 million, respectively, related to our Long-Term Incentive Plan, including amounts related to accelerated vesting. These charges are included in selling, general and administrative expenses.

MarkWest Hydrocarbon also has entered into arrangements with certain employees and directors of MarkWest Hydrocarbon. These arrangements are referred to as the Participation Plan. Under the Participation Plan, MarkWest Hydrocarbon sells subordinated partnership units of the Partnership and interests in the Partnership’s general partner to employees and directors of MarkWest Hydrocarbon under a purchase and sale agreement. In accordance with the provisions of APB 25, Accounting for Stock Issued to Employees, the Participation Plan is accounted for as a variable plan. Compensation expense for the subordinated units is measured as the difference in the market value of the subordinated Partnership units and the amount paid by those individuals. The difference is amortized into earnings over the period of service, adjusted quarterly for the change in the fair value of the unvested units awarded. Compensation related to the general partner interest is calculated as the difference in the formula value and the amount paid by those individuals. The formula value is the amount MarkWest Hydrocarbon would have to pay the employees and directors to repurchase the general partner interests which is derived from the current market value of the Partnership’s common units and the quarterly distributions previously paid. The difference is amortized into earnings over the period of service, adjusted quarterly for the change in the fair value of the unvested interests awarded. Increases or decreases in the market value of the subordinated units and the formula value of the general partner interests between the date they are acquired and the end of each reporting period result in a change in the measure of compensation, which is reflected currently in operations.

Under Topic 1-B of the codification of the Staff Accounting Bulletins, Allocation of Expenses And Related Disclosure In Financial Statements of Subsidiaries, Divisions Or Lesser Business Components of Another Entity compensation expense related to services provided by MarkWest Hydrocarbon’s directors and employees recognized under the Participation Plan should be allocated to the Partnership. The allocation is based on the amount of time that each employee devotes to the Partnership. Compensation attributable to interests that were sold to individuals who serve on both our board of directors and on the board of directors of MarkWest Hydrocarbon is allocated equally. The Partnership recorded compensation expense under the Participation Plan of $1.0 million and $0.2 million for the three months ended March 31, 2004 and 2003, respectively. Under the Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P. (the “Partnership Agreement”), the general partner is deemed to have made a capital contribution equal to the compensation expense recorded under the Participation Plan, with the compensation expense allocated 100% to the general partner. These charges are included in selling, general and administrative expenses.

Assuming the compensation cost for the Long-Term Incentive Plan and the Participation Plan had been determined based on the fair-value methodology of SFAS No. 123, compensation expense recognized for the three months ended March 31, 2005 and 2004, would have been the same.

5. Acquisitions

Starfish Acquisition

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

East Texas System Acquisition

On July 30, 2004, we completed the acquisition of American Central Eastern Texas’ Carthage gathering system and gas processing assets located in East Texas (the “East Texas System”) for approximately $240.7 million. The Partnership’s consolidated financial statements include the results of operations of the East Texas System from July 30, 2004.

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

In conjunction with the closing of the acquisition, we completed a private offering of 1,304,438 common units, at $34.50 per unit, representing approximately $45.0 million in proceeds after transaction costs of approximately $0.9 million and including a contribution from the general partner of $0.9 million to maintain its ownership interest. In addition, we amended and restated our credit facility, increasing our maximum lending limit from $140.0 million to $315.0 million. The credit facility included a $265.0 million revolving facility and a $50.0 million term loan facility. We used the proceeds from the private offering and borrowings of $195.7 million under the credit facility to finance the East Texas System acquisition.

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

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

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

Pro Forma Results of Operations (Unaudited)

The following table reflects the unaudited pro forma consolidated results of operations for the three months ended March 31, 2005 and 2004, as though the East Texas acquisition and the Starfish had occurred on January 1, 2004. The unaudited pro forma results have been prepared for comparative purposes only and may not be indicative of future results.

	Three Months Ended March 31,
	2005		2004
	(in thousands, except per unit amounts)
Revenue	$	89,637	$	71,682
Net income	$	4,427	$	2,908
Net income per limited partner	$	4,505	$	2,898

Net income per limited partner unit:
Basic	$	0.42	$	0.35
Diluted	$	0.42	$	0.35
Weighted average units outstanding:
Basic	10,642		8,285
Diluted	10,673		8,314

6. Property, Plant and Equipment

Property, plant and equipment consists of:

	March 31,			December 31,
	2005			2004
	(in thousands)

Gas gathering facilities	$	179,771		$	160,763
Gas processing plants	58,499			56,239
Fractionation and storage facilities	22,721			22,112
Natural gas pipelines	38,167			38,167
Crude oil pipelines	19,447			18,499
NGL transportation facilities	4,381			4,381
Land, building and other equipment	6,500			6,510
Construction in-progress	21,127			28,759
	350,613			335,430
Less: Accumulated depreciation	(58,997		)	(54,795		)
Total property, plant and equipment, net	$	291,616		$	280,635

For the three months ended March 31, 2005 and 2004, we capitalized interest on construction in progress, including amortization of deferred financing costs, of $0.5 million and $0.1 million, respectively.

7. Related Party Transactions

Prior to the initial public offering (“IPO”), substantially all related party transactions were settled immediately through the net parent investment account. Subsequent to the IPO, normal trade terms apply to transactions with MarkWest Hydrocarbon as contained in various agreements discussed below which were entered into concurrent with the closing of the IPO.

Affiliated revenues in the consolidated statements of income consist of service fees and NGL product sales. Concurrent with the closing of the IPO, we entered into a number of contracts with MarkWest Hydrocarbon. Specifically, we entered into:

• A gas processing agreement pursuant to which MarkWest Hydrocarbon delivers to us all natural gas it receives from third party producers for processing at our processing plants. MarkWest Hydrocarbon pays us a monthly fee based on the natural gas volumes delivered to us for processing.

• A transportation agreement pursuant to which MarkWest Hydrocarbon delivers most of its NGLs to us for transportation through our pipeline to our Siloam fractionator. MarkWest Hydrocarbon pays us a monthly fee based on the number of gallons delivered to us for transportation.

• A fractionation agreement pursuant to which MarkWest Hydrocarbon delivers all of its NGLs to us for unloading, fractionation, loading and storage at our Siloam facility. MarkWest Hydrocarbon pays us a monthly fee based on the number of gallons delivered to us for fractionation, an annual storage fee, and a monthly fee based on the number of gallons of NGLs unloaded.

• A natural gas liquids purchase agreement pursuant to which MarkWest Hydrocarbon receives and purchases, and we deliver and sell, all of the NGL products we produce pursuant to our gas processing agreement with a third party. Under the terms of this agreement, MarkWest Hydrocarbon pays us a purchase price equal to the proceeds it receives from the resale to third parties of such NGL products. This contract also applies to any other NGL products we acquire. We retain a percentage of the proceeds

attributable to the sale of the NGL products we produce pursuant to our agreement with a third party, and remit the balance of the proceeds from such NGL products sales to this third party.

Under the Services Agreement with MarkWest Hydrocarbon, MarkWest Hydrocarbon is continuing to provide centralized corporate functions such as accounting, treasury, engineering, information technology, insurance and other corporate services. We reimburse MarkWest Hydrocarbon monthly for the selling, general and administrative support MarkWest Hydrocarbon allocates to us. For the three months ended March 31, 2005 and 2004, MarkWest Hydrocarbon allocated approximately $2.5 million and $1.5 million, respectively, of selling, general and administrative expenses to us.

The Partnership is also reimbursing MarkWest Hydrocarbon for the salaries and employee benefits, such as 401(k) and health insurance, of plant operating personnel as well as other direct operating expenses. For the three months ended March 31, 2005 and 2004, these costs totaled $2.6 million and $1.7 million, respectively, and are included in facility expenses. The Partnership has no employees.

In Michigan, we assumed the Midstream Business’s existing third party contracts. As a result, we gather and processes gas directly for those third parties. We receive 100% of all fee and percent-of-proceeds consideration for the first 10,000 Mcf/d that is gathered in Michigan. MarkWest Hydrocarbon retains a 70% net profit interest in the gathering and processing income earned on Michigan pipeline throughput in excess of 10,000 Mcf/d, calculated quarterly. There was no net profit interest payable for the three months ended March 31, 2005. For the three months ended March 31, 2004, MarkWest Hydrocarbon’s net profit interest was $0.2 million, which amount is included in facility expenses.

8. Distribution to Unitholders

On January 20, 2005, the Partnership declared a cash distribution of $0.78 per unit on its outstanding common and subordinated units for the quarter ended December 31, 2004. The approximate $9.3 million distribution, including $0.3 million distributed to the general partner, was paid on February 11, 2005, to unitholders of record as of February 2, 2005.

On April 27, 2005, we declared a cash distribution of $0.80 per common and subordinated unit for the quarter ended March 31, 2005. The distribution was paid on May 16, 2005, to unitholders of record as of May 10, 2005.

9. Segment Information

In accordance with the manner in which we manage our business, including the allocation of capital and evaluation of business segment performance, we report our operations in the following geographical segments: (1) East Texas, through MarkWest Energy East Texas Gas Company, L.P. and MarkWest Pipeline Company, L.P. (gathering and processing assets) (2) Oklahoma, through MarkWest Western Oklahoma Gas Company, L.L.C. (Foss Lake gathering system and Arapaho processing plant) (3) Other Southwest, through MarkWest Power Tex L.P. (Powertex pipeline), MarkWest Pinnacle L.P. (Pinnacle gathering assets), MarkWest PNG Utility L.P. (Lake Whitney lateral), MarkWest Texas PNG Utility L.P. (Rio Nogales lateral), MarkWest Blackhawk L.P. (Borger lateral) and MarkWest New Mexico L.P. (Hobbs lateral) (4) Appalachia, through MarkWest Energy Appalachia, L.L.C. (Kenova, Boldman, Maytown, Cobb and Kermit processing plants, NGL pipelines, a fractionation facility and storage facilities) (5) Michigan, through Basin Pipeline, L.L.C. and West Shore Processing Company, L.L.C. (gas gathering and processing) and MarkWest Michigan Pipeline Company, L.L.C. (crude oil transportation).

The accounting policies we apply in the preparation of business segment information are generally the same as those described in Note 2 to the Consolidated and Combined Financial Statements in our December 31, 2004, Annual Report on Form 10-K, except that certain items below the “Income from operations” line are not allocated to business segments as they are not considered by management in their evaluation of business unit performance. In addition, selling, general and administrative expenses are not allocated to individual business

segments. Management evaluates business segment performance based on operating income before selling, general and administrative expenses.

Revenues from MarkWest Hydrocarbon is reflected as revenue from Affiliates.

	East Texas		Oklahoma		Other Southwest				Appalachia			Michigan			Total
Three Months Ended March 31, 2005:
Revenues:
Affiliate	$	—	$	—	$	—			$		15,805	$	—		$	15,805
Unaffiliated parties	14,727		37,257		18,155				538			3,155			73,832
Total Revenues	14,727		37,257		18,155				16,343			3,155			89,637
Purchased product costs	3,597		32,476		14,726				9,253			733			60,785
Facility expenses	2,335		927		1,008				3,756			1,305			9,331
Depreciation	1,012		526		816				817			1,155			4,326
Accretion of asset retirement and lease obligation	8		—		2				—			—			10
Amortization of intangible assets	2,061		—		34				—			—			2,095
Operating income (loss) before selling, general and administrative expenses	$	5,714	$	3,328	$	1,569			$		2,517	$	(38	)	$	13,090
Capital expenditures	$	12,852	$	762	$	1,333			$		842	$	90		$	15,879
Total segment assets	293,916		57,746		103,582				48,194			54,390			557,828

Three Months Ended March 31, 2004:
Revenues:
Affiliate	$	—	$	—	$	—			$		14,294	$	—		$	14,294
Unaffiliated parties	—		28,718		16,516				379			3,918			49,531
Total Revenues	—		28,718		16,516				14,673			3,918			63,825
Purchased product costs	—		26,820		12,989				7,127			917			47,853
Facility expenses	—		809		994				2,903			1,584			6,290
Depreciation	—		492		735				858			1,060			3,145
Amortization of intangible assets	—		—		34				—			—			34
Operating income before selling, general and administrative expenses	$	—	$	597	$		1,764		$		3,785	$	357		$	6,503
Capital expenditures	$	—	$	664	$			394	$	326		$	140		$	1,524
Total segment assets	—		55,492		50,591				50,293			58,616			214,992

The following is a reconciliation of operating income before selling, general and administrative expenses to net income:

	Three Months Ended March 31,
	2005			2004
	(in thousands)
Total operating income before selling, general and administrative expenses	$	13,090		$	6,503
Selling, general and administrative expenses	4,639			2,898

Income from operations	8,451			3,605

Interest income	67			7
Interest expense	(3,674		)	(1,129		)
Amortization of deferred financing costs	(475		)	(308		)
Miscellaneous expense	(104		)	(14		)

Net income	$	4,265		$	2,161

10. Commitments and Contingencies

Legal

The Partnership and several of our affiliates were recently served with several complaints for recovery for property and personal injury damages sustained as a result of a leak occurring November 8, 2004 in a NGL pipeline owned by a third party, and leased and operated by our subsidiary, MarkWest Energy Appalachia, LLC. The 4-inch pipeline transported NGLs from the Maytown gas processing plant to our Siloam fractionator. A subsequent ignition and fire from the leaked vapors resulted in property damage to five homes and injuries to some of the residents. The exact cause of the leak and resulting fire is unknown and is being investigated by us and the U.S. Department of Transportation Office of Pipeline Safety.

While investigation into the incident continues, at this time we believe that we have adequate insurance coverage for property damage and personal injury liability, if any, resulting from the incident. The deductible for the insurance is $0.3 million, which we have recorded during the year ended December 31, 2004 as a charge to income.

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

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

Management’s Discussion and Analysis (“MD&A”) contains statements that are forward-looking. These statements are based on current expectations and assumptions that are subject to risks and uncertainties. Actual results could differ materially from those expressed or implied in the forward-looking statements.

Management Overview of the Quarter ended March 31, 2005

We reported net income of $4.3 million for the three months ended March 31, 2005, or $0.41 per diluted limited partner unit, compared to net income of $2.2 million, or $0.32 per diluted limited partner unit, for the first quarter of 2004.

The increase in the first quarter net income over the comparable period in 2004 is primarily attributable to the contribution of the East Texas system acquisition in July 2004. This acquisition increased operating income by approximately $5.3 million compared to the three months ended March 31, 2004. Operating income before selling, general and administrative expenses from our Oklahoma segment also increased by $2.7 million as a result of higher volumes and processing margins. This was offset somewhat by an increase in interest expense and amortization of deferred financing costs of $2.7 million due to an increase in debt levels and financing costs resulting from our 2004 acquisitions. The Partnership also was impacted by a decrease in operating income contributed by our Appalachia and Michigan segments primarily as a result of reduced volumes, due to suboptimal well operations in Michigan negatively impacting transportation, processing and sales opportunities, as well as an increase in transportation costs and pipeline testing, repair and improvement costs incurred as a result of the November 2004 pipeline failure and resulting fire and explosion that occurred on a section of one of our leased pipelines in Appalachia. Testing and repair of the Appalachia pipeline commenced in the first quarter of 2005 and will likely continue through the second and third quarters. Our current estimate is that the full cost of pipeline testing, repair and improvements will be approximately $5.0 million. First quarter testing and repair costs incurred were $0.2 million, and based on current facts and circumstances, second quarter costs are expected to be approximately $2.5 million. Increased transportation costs have been approximately $0.6 million a quarter. The Partnership is seeking recovery under its business interruption insurance and considers and has asserted that the costs associated with such testing, repair and improvements are also subject to a sharing arrangement with the owner of the pipeline pursuant to the terms of the pipeline lease agreement.

Selling, general and administrative expenses also increased by $1.7 million over the comparable period in 2004 as a result of costs of Sarbanes Oxley implementation and additional compensation expense recognized under the MarkWest Hyrocarbon’s Participation Plan. The compensation expense is allocated to the Partnership pursuant to Topic 1-B of the codification of the Staff Accounting Bulletins, Allocation of Expenses And Related Disclosure In Financial Statements of Subsidiaries, Divisions Or Lesser Business Components of Another Entity. The charge is a non-cash item that did not affect management’s determination of the Partnership’s distributable cash flow for the period, and did not affect net income attributed to the limited partners.

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

On April 27, 2005, the board of directors of the general partner of the Partnership declared the Partnership’s quarterly cash distribution of $0.80 per unit for the first quarter of 2005. This distribution represents an increase of $0.02 per unit, or 3%, over the previous quarterly distribution. The indicated annual rate is $3.20 per unit. The first quarter distribution was paid on May 16, 2005, to unitholders of record on May 10, 2005.

Our Business

We are a Delaware limited partnership formed by MarkWest Hydrocarbon on January 25, 2002 to acquire most of the assets, liabilities and operations of the MarkWest Hydrocarbon Midstream Business. We are engaged in the gathering, processing and transmission of natural gas, the transportation, fractionation and storage of natural gas liquids products and the gathering and transportation of crude oil. Our primary business strategy is to grow our business, increase distributable cash flow to our common unitholders, improve financial flexibility and increase our

ability to access capital to fund our growth. Since our initial public offering in May of 2002, we have significantly expanded our operations through a series of acquisitions.

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 2004 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 variety 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. Generally, 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, or at a different percentage discount to the index price. With respect to (1) and (3) above, the gross margins we realize under the arrangements decrease in periods of low natural gas prices because these gross margins are based on a percentage of the index price. Conversely, our gross margins increase during periods of high 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 energy content of this natural gas. Accordingly, under these arrangements, our revenues and gross margins increase as the price of NGLs increases 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 specified per contract allowance, 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 index based price, and retains the proceeds.

In our current areas of operations, we have a combination of contract types and limited number of keep-whole arrangements. 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 mix will impact our financial results.

At March 31, 2005, our primary exposure to keep-whole contracts was limited to our Arapaho (Oklahoma) processing plant and our East Texas processing contracts. At the Arapaho plant inlet, the Btu content of the natural gas meets the downstream pipeline specification; 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 East Texas approximately 18% of the inlet volume is processed pursuant to keep-whole contracts.

For the three months ended March 31, 2005, 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	18	%	13	%	30	%	39	%	100	%
Gross Margin	54	%	5	%	31	%	10	%	100	%

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

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

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

Impact of Recent Acquisitions on Comparability of Financial Results

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

Since our initial public offering, we have completed seven acquisitions for an aggregate purchase price of approximately $396.1 million. Four of these acquisitions occurred in 2003 and are included in the results of operations for both the three months ending March 31, 2005 and 2004, respectively. These four acquisitions include:

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

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

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

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

Two acquisitions occurred after the first quarter of 2004. Therefore, our historic results of operations for the three months ended March 31, 2004, does not reflect the impact of these acquisitions.

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

• the East Texas acquisition, which closed on July 30, 2004, for consideration of $240.7 million; and

The Starfish acquisition closed on March 31, 2005, for consideration of $41.7 million. As a result, the acquisition did not effect our results of operations in 2004 and 2005.

Our Relationship with MarkWest Hydrocarbon, Inc.

We were formed by MarkWest Hydrocarbon to acquire most of its natural gas gathering and processing assets and NGL transportation, fractionation and storage assets. MarkWest Hydrocarbon remains our largest customer and, for the three months ended March 31, 2005, accounted for 18% of our revenues and 23% of our gross margin. This represents a decrease from the year ended December 31, 2004, during which MarkWest Hydrocarbon accounted for 20% of our revenues and 33% of our gross margin. We expect to continue to derive a significant portion of our revenues from the services we provide under our contracts with MarkWest Hydrocarbon for the foreseeable future. At March 31, 2005, MarkWest Hydrocarbon and its subsidiaries, in the aggregate, owned a 25% interest in the Partnership, consisting of 2,469,496 subordinated limited partner units, which represents a 23% interest in the Partnership, and 90% of the general partner interest, which owns a 2% interest in the Partnership.

Under a Services Agreement, MarkWest Hydrocarbon acts in a management capacity rendering day-to-day operational, business and asset management, accounting, personnel and related administrative services to the Partnership. In turn, the Partnership is obligated to reimburse MarkWest Hydrocarbon for all documented expenses incurred on behalf of the Partnership and which are expressly designated as reasonably necessary for the performance of the prescribed duties and specified functions.

Results of Operations

Operating Data

	Three Months Ended March 31,
	2005	2004

Operating Data:
*Southwest:*
East Texas (1)
Gathering systems throughput (Mcf/d)	287,000	NA
NGL product sales (gallons)	27,612,000	NA

Oklahoma
Foss Lake gathering systems throughput (Mcf/d) (2)	67,000	55,000
Arapaho NGL product sales (gallons) (3)	15,217,000	10,459,000

Other
Appleby gathering systems throughput (Mcf/d) (4)	28,000	24,000
Other gathering systems throughput (Mcf/d) (4)	17,000	18,000
Lateral throughput volumes (Mcf/d) (5)	52,000	61,000

*Appalachia:*
Natural gas processed for a fee (Mcf/d) (6)	210,000	207,000
NGLs fractionated for a fee (Gal/day)	462,000	462,000
NGL product sales (gallons)	10,765,000	10,926,000

*Michigan:*
Natural gas processed for a fee (Mcf/d)	6,900	13,900
NGL product sales (Mcf/d)	1,563,000	2,714,000
Crude oil transported for a fee (Bbl/d) (7)	14,100	14,600

(1) We acquired our East Texas System in late July 2004. Volumes are for the period of time we owned the facility during 2004.

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

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

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

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

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

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

Segment Reporting

Our five geographical segments are: East Texas, Oklahoma, Other Southwest, Appalachia and Michigan. The segment information in this MD&A consists of information that we capture by segment, except that certain items below the “Operating Income” line are not allocated to our business segments as they are not considered by management in their evaluation of business unit performance. In addition, general and administrative expenses are not allocated to individual business segments since management evaluates each business segment based on operating income before selling, general and administrative expenses. The segment information appearing in Note 9, “Segment Information”, to the consolidated financial statements is presented on a basis consistent with the Partnership’s internal management reporting, in accordance with SFAS No. 131, Disclosure about Segments of an Enterprise and Related Information. As a result of our recent acquisitions, segment information for the three months ended March 31, 2004 has been restated to conform to the current period presentation.

Three Months Ended March 31, 2005, Compared to Three Months Ended March 31, 2004

East Texas

	Three Months Ended March 31,				Change
	2005		2004		%

Revenues	$	14,727	$	—	NA

Operating expenses:
Purchased product costs	3,597		—		NA
Facility expenses	2,335		—		NA
Depreciation	1,012		—		NA
Amortization of intangible assets	2,061		—		NA
Accretion of asset retirement obligation	8		—		NA
Total operating expenses before selling, general and administrative expenses	9,013		—		NA

Income from operations before selling, general and administrative expenses	$	5,714	$	—	NA

Revenue, Purchased Product Costs, Facility Expenses, Depreciation, Amortization of intangible assets, Accretion of asset retirement obligation. The increase in revenue, purchased product costs, facility expenses, depreciation and amortization is the result of the Partnership acquiring the East Texas System on July 30, 2004.

Oklahoma

	Three Months Ended March 31,				Change
	2005		2004		%

Revenues	$	37,257	$	28,718	30	%

Operating expenses:
Purchased product costs	32,476		26,820		21	%
Facility expenses	927		809		15	%
Depreciation	526		492		7	%
Total operating expenses before selling, general and administrative expenses	33,929		28,121		21	%

Income from operations before selling, general and administrative expenses	$	3,328	$	597	457	%

Revenue. Revenue increased 30% during the first three months of 2005 relative to the same time period in 2004 due to increased well volumes contracted to the gathering system, higher crude oil prices positively impacting condensate sales and higher processing margins.

Purchased Product Costs. Purchased product costs increased 21% during the first three months of 2005 relative to the same period in 2004 primarily as a result of an increase in purchased volumes and price increases.

Facility Expenses. Facility expenses increased during the first three months of 2005 relative to the comparable period in 2004 primarily due to an increase in utility and maintenance expense incurred with the expansion of our Oklahoma systems. The increase was also attributed to an increase in salaries for field personnel.

Depreciation. Depreciation expense increased slightly during the first three months of 2005 relative to the same time period in 2004 due to the addition of compressors to our Butler compressor station and additional well connections in the field.

Other Southwest

	Three Months Ended March 31,				Change
	2005		2004		%

Revenues	$	18,155	$	16,516	10	%

Operating expenses:
Purchased product costs	14,726		12,989		13	%
Facility expenses	1,008		994		1	%
Depreciation	816		735		11	%
Amortization of intangible assets	34		34		0	%
Accretion of lease obligation	2		—		NA
Total operating expenses before selling, general and administrative expenses	16,586		14,752		12	%

Income from operations before selling, general and administrative expenses	$	1,569	$	1,764	(11	)%

Revenue. Revenues increased during the first three months of 2005 relative to the same time period in 2004 due to a 21% increase in natural gas volumes on the Appleby and Edwards gathering systems offset by the effect of a one-time inventory sale on the Powertex system in February 2004.

Purchased Product Costs. Purchased product costs increased during the first three months of 2005 relative to the same time period in 2004 primarily due to increased volumes and prices on the Appleby gathering system.

Facility Expenses. Facility expenses increased slightly during the first three months of 2005 relative to the comparable period in 2004 primarily due to higher site repairs and maintenance at our Ocotillo and Laguna Grande gathering systems partially offset by decreased operating expenses in 2005 due to the sale of the Dublin Ranch and Willow Lake systems.

Depreciation. Depreciation expense increased slightly during the first three months of 2005 relative to the same period in 2004 due to new assets added to the North and South Appleby systems during 2004.

Appalachia

	Three Months Ended March 31,				Change
	2005		2004		%
Revenues:
Sales to unaffiliated parties	$	538	$	379	42	%
Sales to affiliate	15,805		14,294		11	%
Total revenues	16,343		14,673		11	%

Operating expenses:
Purchased product costs	9,253		7,127		30	%
Facility expenses	3,756		2,903		29	%
Depreciation	817		858		(5	)%
Total operating expenses before selling, general and administrative expenses	13,826		10,888		27	%

Income from operations before selling, general and administrative expenses	$	2,517	$	3,785	(34	)%

Revenue. Revenues increased during the first three months of 2005 relative to the same time period in 2004 as a result of a $0.165 per gallon or 22% increase in sales price for our Maytown natural gas liquids production.

Purchased Product Costs. Purchased product costs increased during the first three months of 2005 relative to the same time period in 2004 due to a $0.143 per gallon increase in purchase costs associated with the Maytown percent of proceeds contract. The remainder of the increase is attributable to trucking costs incurred to transport product from our Maytown and Boldman plants to our Siloam fractionation plant as a result of the November 2004 pipeline failure.

Facility Expenses. Facility expenses increased during the first three months of 2005 relative to the same time period in 2004 primarily due to increased pipeline repair and maintenance costs, salary and utility expenses.

Depreciation. Depreciation expense decreased during the first three months of 2005 relative to the same time period in 2004 due to the impairment of plant processing equipment recorded in 2004.

Michigan

	Three Months Ended March 31,					Change
	2005			2004		%

Revenues	$	3,155		$	3,918	(19	)%

Operating expenses:
Purchased product costs	733			917		(20	)%
Facility expenses	1,305			1,584		(18	)%
Depreciation	1,155			1,060		9	%
Total operating expenses before selling, general and administrative expenses	3,193			3,561		(10	)%

Income (loss) from operations before selling, general and administrative expenses	$	(38	)	$	357	(111	)%

Revenue. Revenues decreased during the first three months of 2005 relative to the same time period in 2004 by approximately $0.8 million due to lower transport and processing volumes with corresponding reductions in natural gas liquids sales volumes resulting from suboptimal producer well operations reducing volume throughput on our systems. Increased crude oil pipeline throughput resulted in a $0.3 million increase in revenue.

Purchased Product Costs. Purchased product costs decreased during the first three months of 2005 relative to the same time period in 2004 due to reduced natural gas liquids production purchases stemming from production declines caused by suboptimal producer well operations.

Facility Expenses. Facility expenses decreased during the first three months of 2005 relative to the same time period in 2004 primarily due to a decrease of $0.2 million in the amount of net profit interest paid to MarkWest Hydrocarbon. MarkWest Hydrocarbon retains a 70% net profits interest in the gathering and processing income we earn on quarterly pipeline throughput in excess of 10,000 Mcf/d. As throughput was below 10,000 Mcf/d for the first quarter of 2005, there was no net profits interest payable to MarkWest Hydrocarbon. In addition, facility expenses decreased as a result of the reduction of crude oil pipeline inventory losses.

Depreciation. Depreciation expense increased slightly during the first three months of 2005 relative to the same time period in 2004 due to 2004 crude oil pipeline and equipment additions being depreciated in 2005.

Consolidated Financial Information

	Three Months Ended March 31,						Change
	2005			2004			%

Segment operating income	$	13,090		$	6,503		101	%
Selling, general and administrative expense	4,639			2,898			60	%

Income from operations	8,451			3,605			134	%

Interest income	67			7			857	%
Interest expense	(3,674		)	(1,129		)	225	%
Amortization of deferred financing costs	(475		)	(308		)	54	%
Miscellaneous expense	(104		)	(14		)	643	%

Net income	$	4,265		$	2,161		97	%

Selling, General and Administrative Expense. Selling, general and administrative expenses (“SG&A”) increased during the first three months of 2005 relative to the same time period in 2004 as a result of an increase in audit and Sarbanes Oxley related costs of $0.7 million. The addition of our East Texas acquisition added approximately $0.4 million to our SG&A costs. In addition, the allocation of compensation expense from the Participation Plan increased SG&A by $0.7 million.

Interest Income. Interest income increased during 2005 relative to the same period in 2004 primarily due to an increase in interest earned on cash equivalents.

Interest Expense. Interest expense increased during 2005 relative to the same period in 2004 primarily due to increased debt levels resulting from the financing of our 2004 acquisitions. In October 2004, we issued $225.0 million in senior notes.

Amortization of Deferred Financing Costs. We amortized approximately $0.5 million of deferred financing costs related to debt issuance costs incurred to finance our 2004 acquisitions. The increase in 2005 relative to the same period in 2004 is attributable to debt refinancing completed in the last half of 2004 as well as an increase in deferred financing cost as a result of the increase in our debt level. Deferred financing costs are being amortized over the terms of the related obligations, which approximates the effective interest method.

Liquidity and Capital Resources

Our primary source of liquidity to meet operating expenses and fund capital expenditures (other than for certain acquisitions) is cash flow from operations. Based on current volume, price and expense assumptions, we expect cash flow from operations and borrowings under our credit facility to fund our planned capital expenditures in 2005. The public and institutional markets have been our principal source of capital to finance a significant amount of our growth (including acquisitions). During the first quarter of 2005, we borrowed $40.0 million from our credit facility to finance the acquisition of a 50% non-operating membership interest in Starfish. Starfish owns the FERC regulated Stingray natural gas pipeline and the unregulated Triton natural gas gathering system and West Cameron dehydration facility, all located in the Gulf of Mexico and southwestern Louisiana. In addition we spent $15.9 million on capital expenditures, primarily for the construction of new processing plants and gathering systems in East Texas to handle our future contractual commitments.

The Partnership’s $200.0 million credit facility was established to fund capital expenditures and acquisitions, working capital requirements (including letters of credit) and distributions to unitholders. Advances to fund distributions to unitholders may not exceed $0.50 per outstanding unit in any 12-consecutive-month period. To date there have been no advances to fund distributions to unitholders. At March 31, 2005, the Partnership had borrowed $40.0 million to finance its investment in Starfish. As of March 31, 2005, $78.0 million was available

under the credit facility based on the covenants used to calculate the available borrowing capacity on a quarterly basis. The available borrowing capacity at March 31, 2005 was calculated using the most restrictive debt covenant, as the amount that, when added to existing debt would provide a maximum leverage ratio of 5.0 to 1.0. The Partnership’s credit facility matures on October 23, 2009.

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

The Partnership and its subsidiary, MarkWest Energy Finance Corporation, also have $225.0 million in senior notes at a fixed rate of 6.875% outstanding at March 31, 2005. The notes mature on November 2, 2014. Subject to compliance with certain covenants, we may issue additional notes from time to time under the indenture pursuant to Rule 144A and Regulation S under the Securities Act of 1933. The proceeds from these notes were used to pay down our outstanding debt under our credit facility in October 2004.

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

The Partnership has agreed to file an exchange offer registration statement, or under certain circumstances, a shelf registration statement, pursuant to a registration rights agreement relating to the 2004 senior notes. The Partnership failed to complete the exchange offer in the time provided for in the subscription agreements (March 31, 2005) and as a consequence is incurring an interest rate penalty of 0.5% until such time as the exchange offer is completed.

On March 30, 2005, the Partnership announced that it would be delaying the filing of its 2004 Annual Report on Form 10-K with the Securities and Exchange Commission (“SEC”) beyond the prescribed filing deadline of March 31, 2005. As a consequence of the delayed filing, the Partnership was in default of certain debt covenants under both its credit facility and its indenture, which defaults resulted from the failure to file its 2004 Form 10-K within the time periods specified in the SEC’s rules and regulations. The lenders under the credit facility granted the Partnership a waiver of compliance with the credit facility’s debt covenants until June 30, 2005.

The indenture governing our outstanding senior notes contains restrictions on our ability to make cash distributions. Under the indenture, we are restricted from making distributions (a “Restricted Payment”) if at the time of making the Restricted Payment, a default or an event of default has occurred and is continuing. The Partnership’s failure to file this Annual Report on Form 10-K for year ended December 31, 2004 and its Quarterly Report on Form 10-Q for the first quarter of 2005 within the time periods specified in the Securities and Exchange Commission’s rules and regulations constituted a default under the indenture, and the failure to file the Form 10-K within thirty days after the April 8, 2005 notice from the indenture trustee constituted an event of default under the indenture. On May 16, 2005, the Partnership paid a cash distribution to unitholders for the first quarter of 2005. This cash distribution, made while the event of default for failure to file its Form 10-K had occurred and was continuing, constituted a default under the indenture, and this default matured into an event of default thirty days after such Restricted Payment was made, or June 15, 2005. Both of these events of default are cured through the filing of this Quarterly Report on Form 10-Q and the Annual Report on Form 10-K for the year ended December 31, 2004 prior to any declaration of acceleration of the senior notes by the trustee as a result of such events of default.

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, or both.

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 primary 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 our liquidity.

The Partnership has budgeted $59.4 million for capital expenditures for the remainder of 2005, exclusive of any acquisitions, consisting of $57.9 million for expansion capital and $1.5 million for sustaining capital. Expansion capital includes expenditures made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition. Sustaining capital includes expenditures to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives.

Cash Flows

	Three Months Ended March 31,
	2005			2004
	(in thousands)

Net cash provided by operating activities	$	17,522		$	5,385
Net cash used in investing activities	$	(57,556	)	$	(1,356	)
Net cash provided by (used in) financing activities	$	30,955		$	(1,566	)

Net cash provided by operating activities was higher during the three months ended March 31, 2005, than during the three months ended March 31, 2004, primarily due to an increase in operating income before non-cash charges. The increase is also attributable to higher processing margins and volumes from our Oklahoma segment. We expect that overall our 2005 volumes for the remainder of the year will be higher than in 2004, principally due to a full year of activity for our July 2004 East Texas acquisition, and that cash provided by operating activities in 2005 will exceed 2004 levels. However a precipitous decline in natural gas or NGL prices for the remainder of 2005 would significantly affect the amount of cash flow that would be generated from operations.

Net cash used in investing activities was higher during the three months ended March 31, 2005, than during the three months ended March 31, 2004, primarily due to our March 31, 2005 acquisition of a 50% non-operating interest in Starfish for approximately $41.7 million. In addition, the Partnership used cash of $15.9 million for capital expenditures, primarily for the construction of new processing plants and gathering systems in East Texas to handle our future contractual commitments and construction of the new Cobb replacement processing facility in Appalachia. During the three months ended March 31, 2004, the Partnership used cash of $1.5 million for capital expenditures.

Net cash used in financing activities during the three months ended March 31, 2005, included net proceeds from the Partnership’s credit facility of $40.0 million and capital contributions from the general partner of $0.4 million for the Cobb processing replacement facility. In addition, the Partnership distributed $9.3 million to unitholders in 2005. Net cash used in financing activities during the three months ended March 31, 2004, included net proceeds from a secondary public offering of $45.4 million. Of the net proceeds from the secondary offering, $42.0 million were used for the repayment of long-term debt. The Partnership distributed $5.0 million to unitholders

in the 2004 period.

Total Contractual Cash Obligations

A summary of our total contractual cash obligations as of March 31, 2005, is as follows, in thousands:

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

Long-term debt (1)	$	426,925	$	13,852	$	36,937	$	76,370	$	299,766
Operating leases	6,767		2,480		3,193		648		446
Purchase obligations	3,587		3,587		—		—		—
Total contractual cash obligations	$	437,279	$	19,919	$	40,130	$	77,018	$	300,212

(1) Includes interest on our 6.875% senior notes through 2014 of $148.2 million and interest on our 7.5% credit facility through 2009 of $13.7 million.

Matters Impacting Future Results

We earn fees for transporting the NGLs recovered from the Kenova, Maytown, and Boldman plants to Siloam via our Appalachian pipeline. In November of 2004, a failure and ensuing explosion and fire occurred on a leased section of this pipeline. The office of pipeline safety (“OPS”) issued an order requiring among other things hydrostatic testing of the line prior to its return to service. Until the pipeline is returned to service, Maytown and Boldman NGLs are being trucked to Siloam for fractionation resulting in an increase in our NGL transportation costs. MarkWest has business interruption insurance and has submitted claims to cover the increased transportation and production costs incurred due to the pipeline being out of service as a result of the fire and explosion and OPS order. From November 2004 through March 31, 2005, our business interruption loss was estimated to be approximately $1.3 million. As previously mentioned, we expect to incur these additional costs until the pipeline is returned to service, which we expect to be no later than December 31, 2005.

On April 14, 2005, we received a notice of violation from the West Virginia Department of Environmental Protection setting forth alleged past violations of certain air quality regulations at our Cobb extraction plant. We are investigating the matter and are in the process of preparing responses.

Recent Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment. This statement addresses the accounting for share-based payment transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the enterprise, or (b) liabilities that are based on the fair value of the enterprise’s equity instruments or that may be settled by the issuance of such equity instruments. SFAS No. 123(R) requires an entity to recognize the grant-date fair-value of stock options and other equity-based compensation issued to employees in the income statement. The revised Statement generally requires that an entity account for those transactions using the fair-value-based method, and eliminates the intrinsic value method of accounting in APB Opinion No. 25, Accounting for Stock Issued to Employees, which was permitted under SFAS No. 123, as originally issued. The revised Statement requires entities to disclose information about the nature of the share-based payment transactions and the effects of those transactions on the financial statements. SFAS 123(R) is effective for public companies for the first fiscal year beginning after December 15, 2005. All public companies must use either the modified prospective or the modified retrospective transition method. We have not yet evaluated the impact of the adoption of this pronouncement, which must be adopted in the first quarter of calendar year 2006. On March 29, 2005, the SEC staff issued Staff Accounting Bulletin (“SAB”) No. 107, Share-Based Payment to express the views of the staff regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. The Partnership will take into consideration the additional guidance provided by SAB 107 in connection with the implementation of SFAS No. 123(R). We have not yet evaluated the impact of the adoption of this pronouncement, which must be adopted in the first quarter of calendar year 2006.

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

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,” “intend,” “project,” “anticipate,” and similar expressions to identify forward-looking statements.

These forward-looking statements are made based upon management’s current 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.

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

• Our ability to successfully integrate our recent or future acquisitions;

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

• Our substantial debt and other financial obligations could adversely impact our financial condition;

• 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 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;

• Our ability to identify and complete grass roots projects or acquisitions complementary to o ur business; and

• Our ability to raise sufficient capital to execute our business plan through borrowing or issuing equity.

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

Board of Directors, senior management directed that we dedicate additional resources to implement internal controls to reasonably assure accurate and timely financial reporting in the future.

Subsequent to December 31, 2004, we have initiated the following measures to strengthen our internal control processes:

Ineffective control environment:

• We are in the process of recruiting a Chief Accounting Officer with technical accounting skills relevant to our public company financial reporting needs.

• We are developing plans to formally implement an internal audit function in conjunction with our compliance function designed to assist in the future development and review of sound internal policies and procedures.

• We are conducting an assessment and review of our accounting general ledger systems to determine what changes could be made to improve our overall control environment.

Insufficient technical accounting expertise, inadequate policies and procedures and management review in the preparation of our financial statements:

• We are in the process of recruiting a Chief Accounting Officer with public company reporting technical expertise, and we intend to add at least one additional staff person with specific technical accounting and SEC reporting expertise to supplement our existing internal technical accounting resources.

• We have reaffirmed our corporate policy to capitalize interest on major construction projects. The financial reporting team in our corporate office has assumed the responsibility for calculating and recording capitalized interest relating to major construction projects.

• We plan to establish a relationship with an accounting consulting and advisory firm to provide additional technical accounting support and have begun the selection process.

Inadequate personnel, processes and controls at our Southwest Business Unit:

• We have formalized the monthly account reconciliation process for all balance sheet accounts. We have also implemented a formal review of these reconciliations by our Business Unit accounting management.

• We have instituted a quarterly corporate review of all account reconciliations by the corporate accounting staff and management.

• We plan to have our Southwest Business Unit accountants receive specific training on our accounting systems.

• We formalized a consistent procedure across all subsidiaries relating to revenue, purchased product costs and their associated balance sheet accounts to completely reverse the prior period accruals, and analyze and document the current period accruals.

• We initiated the process of consistently comparing each month’s accrual to the actual results in an effort to further refine the estimation process.

• We have systematized the data gathering function for the accounts payable invoices received after period end. This accrual is now reviewed monthly by corporate accounting staff.

• Our executive operations management is now requiring field personnel to expedite the invoice approval process.

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 March 31, 2005 and December 31, 2004 (unaudited)
Consolidated Statements of Operations for the Three Months Ended March 31, 2005 and 2004 (unaudited)
Consolidated Statements of Other Comprehensive Income for the Three Months Ended March 31, 2005 and 2004 (unaudited)
Consolidated Statements of Changes in Capital for the Three Months Ended March 31, 2005 (unaudited)
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2005 and 2004 (unaudited)
Notes to the Consolidated Financial Statements (unaudited)
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Item 4. Controls and Procedures

PART II—OTHER INFORMATION

Item 6. Exhibits

SIGNATURE

Bpd		barrels of oil per day
Bbl/d		barrels of oil per day
Gal/d		gallons per day
Gross margin		revenues less purchase product costs
Mcf		thousand cubic feet of natural gas
Mcf/d		thousand cubic feet of natural gas per day
NGL		natural gas liquids, such as propane, butanes and natural gasoline

	2005

MMBtu (total for the period)	137,500
$/MMBtu	$	4.26

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

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

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

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

Glossary of Terms

PART I—FINANCIAL INFORMATION

Management Overview of the Quarter ended March 31, 2005

Our Business

Results of Operations

Liquidity and Capital Resources

Cash Flows

Total Contractual Cash Obligations

Forward-Looking Statements

Item 4. Controls and Procedures

Remediation of Internal Control Weaknesses

SIGNATURE

2005	$	2,480
2006	2,235
2007	958
2008	371
2009	277
2010 and thereafter	446
Total	$	6,767

		MarkWest Energy Partners, L.P.
		(Registrant)

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

Date: June 23, 2005		/s/ James G. Ivey
		James G. Ivey
		Chief Financial Officer

Exhibit Number		Exhibit Index

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

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

31.3		Chief Financial Officer Certification Pursuant to Section 13a-14(a) 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 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.

32.3		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.