UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2004

OR

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

For the transition period from to

Commission File Number 001-31239

MARKWEST ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes ý No o

The number of the registrant’s Common and Subordinated Units outstanding at July 31, 2004, were 5,301,940 and 3,000,000, respectively.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements
Consolidated Balance Sheets at June 30, 2004 and December 31, 2003
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2004 and 2003
Consolidated Statements of Other Comprehensive Income for the Three and Six Months Ended June 30, 2004 and 2003
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2004 and 2003
Consolidated Statement of Changes in Capital for the Six Months Ended June 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 6. Exhibits and Reports on Form 8-K

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

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

(in thousands)

	June 30, 2004			December 31, 2003
ASSETS
Current assets:
Cash and cash equivalents	$	8,871		$	8,753
Receivables, net	16,530			11,942
Receivables from affiliate	3,653			2,417
Inventories	250			353
Other assets	176			223
Total current assets	29,480			23,688

Property, plant and equipment	233,678			224,534
Less: Accumulated depreciation	(46,970		)	(40,320		)
Total property, plant and equipment, net	186,708			184,214

Deferred financing costs, net	3,178			3,831
Deferred offering costs	—			995
Investment in and advances to equity investee	232			250
Total assets	$	219,598		$	212,978

LIABILITIES AND CAPITAL

Current liabilities:
Accounts payable	$	17,856		$	14,064
Payables to affiliate	2,779			1,524
Accrued liabilities	5,932			5,163
Risk management liability	749			373
Current portion of long-term debt	86,200			—
Total current liabilities	113,516			21,124

Long-term debt	—			126,200
Risk management liability	397			125
Other liabilities	479			478
Commitments and contingencies

Capital:
Partners’ capital	106,351			65,549
Accumulated other comprehensive loss	(1,145		)	(498		)
Total capital	105,206			65,051
Total liabilities and capital	$	219,598		$	212,978

The accompanying notes are an integral part of these financial statements

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except per unit amounts)

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Revenues:
Sales to unaffiliated parties	$	50,626		$	19,554		$	100,145		$	23,853
Sales to affiliate	13,805			10,082			28,099			23,476
Total revenues	64,431			29,636			128,244			47,329

Operating expenses:
Purchased product costs	47,560			18,423			95,060			26,815
Facility expenses	6,097			5,167			12,421			9,504
Selling, general and administrative expenses	2,074			1,678			4,724			2,931
Depreciation	3,414			1,860			6,671			3,205
Total operating expenses	59,145			27,128			118,876			42,455

Income from operations	5,286			2,508			9,368			4,874

Other income (expense):
Interest expense, net	(1,316		)	(984		)	(2,802		)	(1,745		)
Miscellaneous income (expense)	(24		)	14			(1		)	34

Net income	$	3,946		$	1,538		$	6,565		$	3,163

Interest in net income:
General partner	$	299		$	60		$	528		$	92
Limited partners	$	3,647		$	1,478		$	6,037		$	3,071

Net income per limited partner unit:
Basic	$	0.52		$	0.27		$	0.88		$	0.57
Diluted	$	0.52		$	0.27		$	0.87		$	0.56

Weighted average units outstanding:
Basic	6,998			5,428			6,886			5,422
Diluted	7,024			5,476			6,914			5,470

The accompanying notes are an integral part of these financial statements

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME

(UNAUDITED)

(in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Net income	$	3,946		$	1,538		$	6,565		$	3,163

Other comprehensive loss:
Risk management activities	(526		)	(203		)	(647		)	(199		)

Comprehensive income	$	3,420		$	1,335		$	5,918		$	2,964

The accompanying notes are an integral part of these financial statements

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)

	Six Months Ended June 30,
	2004			2003
Cash flows from operating activities:
Net income	$	6,565		$	3,163
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	6,671			3,205
Gain from sale of property, plant and equipment	(8		)	—
Amortization of deferred financing costs included in interest expense	636			438
Non-cash compensation expense	344			400
Other	18			9
Changes in operating assets and liabilities:
(Increase) decrease in receivables	(5,824		)	2,511
Decrease in inventories	103			16
(Increase) decrease in other current assets	47			(114		)
Increase in accounts payable and accrued liabilities	5,898			250
Net cash provided by operating activities	14,450			9,878

Cash flows from investing activities:
Pinnacle acquisition, net of cash acquired	—			(38,238		)
Hobbs Lateral acquisition	(2,275		)	—
Capital expenditures	(7,006		)	(1,144		)
Proceeds from sale of assets	138			3
Other	4			—
Net cash used in investing activities	(9,139		)	(39,379		)

Cash flows from financing activities:
Payments for debt issuance costs	—			(759		)
Proceeds from long-term debt	3,000			51,000
Repayment of long-term debt	(43,000		)	(17,300		)
Proceeds from secondary offering, net	44,915			—
Proceeds from private placement of common units, net	—			7,807
Distributions to unitholders	(10,108		)	(6,103		)
Net cash provided by (used in) financing activities	(5,193		)	34,645

Net increase in cash	118			5,144
Cash and cash equivalents at beginning of period	8,753			2,776
Cash and cash equivalents at end of period	$	8,871		$	7,920

Supplemental cash flow information:
Cash paid for interest	$	2,077		$	709

The accompanying notes are an integral part of these 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 offering, net	1,173	43,042			—	—			879			—		—			43,921

Phantom unit vest	11	424			—	—			—			—		—			424

Net income	—	3,342			—	2,695			528			—		—			6,565

Distributions to partners	—	(5,429		)	—	(4,080		)	(599		)	—		—			(10,108		)

Other comprehensive loss	—	—			—	—			—			—		(647		)	(647		)

Balance, June 30, 2004	3,998	$	92,422		3,000	$	11,984		$	1,250		$	695	$	(1,145	)	$	105,206

The accompanying notes are an integral part of these 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 controls and conducts our operations. 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 six months ended June 30, 2004, are not necessarily indicative of results for the full year 2004 or any other future period.

3. Secondary Public Offering

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.

4. Subsequent Event – American Central East Texas Acquisition

On July 30, 2004, we completed the acquisition (the “American Central East Texas Acquisition”) of American Central East Texas Gas Company, L.P.’s (“American Central”) Carthage gathering system and gas processing assets located in east Texas for approximately $240 million.

The Carthage gathering system has been constructed over the last 10 years and offers both low- and high-pressure service to producers in the Carthage Field, gathering gas from the Cotton Valley, Pettit and Travis Peak formations. The system consists of approximately 180 miles of pipeline connected to approximately 1,700 wells with an additional 82 miles of pipeline currently under construction. The gathering system also includes approximately 65,000 horsepower of compression with an additional 35,000 horsepower currently being installed. Current system throughput is approximately 245 MMcf/d and is anticipated to increase to approximately 310 MMcf/d by the end of 2004 due to the connection to the system of additional contracted volumes. The gathering system has a capacity of approximately 350 MMcf/d. Also included in the acquisition is a 175 MMcf/d processing facility currently under construction and an NGL pipeline to be constructed in 2005.

In conjunction with the closing of the acquisition, we completed an offering of approximately 1.3 million of our common units, at $34.50 per unit, which netted us approximately $45 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 million to $315 million. The credit facility includes a $265 million revolving facility and a $50 million term loan facility. We used the proceeds from the offering and borrowings under our amended and restated credit facility to finance the American Central East Texas 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. Consequently, as of June 30, 2004, we have reclassified debt from non-current liabilities to current liabilities.

5. Acquisitions

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.

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.

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

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

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. Substantially all of the acquired assets are pledged to the credit facility lenders to secure the repayment of the outstanding borrowings under the credit facility.

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

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

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 and Michigan Crude Pipeline

acquisition each had occurred on January 1, 2003. The unaudited pro forma results have been prepared for comparative purposes only and may not be indicative of future results.

	Three Months Ended June 30, 2003		Six Months Ended June 30, 2003
	(in thousands, except per unit data)
Revenue	$	40,715	$	88,388
Net income	$	760	$	2,904
Basic net income per limited partner unit	$	0.14	$	0.52
Diluted net income per limited partner unit	$	0.14	$	0.52

6. Property, Plant and Equipment

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

	June 30, 2004			December 31, 2003
	(in thousands)
Property, plant and equipment:
Gas gathering facilities	$	82,570		$	73,424
Gas processing plants	56,322			55,888
Fractionation and storage facilities	22,524			22,160
Natural gas pipelines	38,848			38,790
Crude oil pipeline	18,460			18,352
NGL transportation facilities	4,415			4,415
Land, building and other equipment	7,526			9,664
Construction in-progress	3,013			1,841
	233,678			224,534
Less: Accumulated depreciation	(46,970		)	(40,320		)
Total property, plant and equipment, net	$	186,708		$	184,214

7. 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.

Subsequent Event

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 distribution will be paid on August 13, 2004, to unitholders of record as of July 30, 2004.

8. 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.

9. 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 of 2004, the Partnership achieved a specified annualized distribution objective, thereby accelerating the vesting of approximately 10,800 restricted units as of February 23, 2004. 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.

In addition, for the three months ended June 30, 2004 and 2003, we recorded no compensation expense and compensation expense of $0.2 million, respectively, related to our variable plan. For the six months ended June 30, 2004 and 2003, we recorded compensation expense of $0.3 million and $0.4 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 six months ended June 30, 2004 and 2003, would have been the same.

10. 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.

In October 2003, the board of directors of our general partner approved a plan to shut down our existing Cobb processing facility, contingent upon the construction of a replacement facility. Construction of the new facility

is expected to be completed by the end of 2004. During the fourth quarter of 2003, we estimated the amount of the asset retirement obligation associated with the shut down of the old Cobb facility to be $0.5 million, and, accordingly, we recorded a related accrued liability. At June 30, 2004, and December 31, 2003, our asset retirement obligation was $0.5 million.

At January 1 and December 31, 2003, and June 30, 2004, there were no assets legally restricted for purposes of settling asset retirement obligations.

11. 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) Appalachia, through MarkWest Energy Appalachia, L.L.C.; (2) 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); and (3) Southwest, through MarkWest Texas GP, L.L.C. and MW Texas Limited, L.L.C., and their affiliates (gathering systems and lateral pipelines) and MarkWest Western Oklahoma Gas Company, L.L.C. (the Foss Lake Gathering System and Arapaho processing plant). Our direct investment in natural gas gathering and processing, and crude oil transportation, has increased as a result of three acquisitions in the Southwest and one acquisition in Michigan, respectively, all completed in 2003.

The accounting policies we apply in the generation 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, 2003, Annual Report on Form 10-K, as amended, 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, as adjusted (“segment operating income”), in relation to capital employed. To derive capital employed, certain Partnership assets are allocated based on relative segment assets. We have no intersegment sales or asset transfers.

Revenues from MarkWest Hydrocarbon, reflected as “Affiliate”, represented 21% and 34% of our revenues for the three months ended June 30, 2004 and 2003, respectively, and 22% and 50% of our revenues for the six months ended June 30, 2004 and 2003, respectively.

	Appalachia		Michigan		Southwest		Total
	(in thousands)
Three Months Ended June 30, 2004:
Revenues:
Unaffiliated parties	$	442	$	3,632	$	46,552	$	50,626
Affiliate	13,805		—		—		13,805
Depreciation	930		1,059		1,425		3,414
Segment operating income	3,383		283		3,694		7,360
Capital expenditures	961		694		4,868		6,523
Total segment assets	49,901		59,075		110,622		219,598

Three Months Ended June 30, 2003:
Revenues:
Unaffiliated parties	$	233	$	2,642	$	16,679	$	19,554
Affiliate	10,082		—		—		10,082
Depreciation	717		588		555		1,860
Segment operating income	2,724		35		1,427		4,186
Capital expenditures	355		19		672		1,046
Total segment assets	49,400		36,370		48,594		134,364

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 June 30,
	2004			2003
	(in thousands)
Segment operating income	$	7,360		$	4,186
Selling, general and administrative expenses	2,074			1,678

Income from operations	5,286			2,508

Interest expense, net	(1,316		)	(984		)
Miscellaneous income (expense)	(24		)	14
Net income	$	3,946		$	1,538

	Appalachia		Michigan		Southwest		Total
	(in thousands)
Six Months Ended June 30, 2004:
Revenues:
Unaffiliated parties	$	821	$	7,550	$	91,774	$	100,145
Affiliate	28,099		—		—		28,099
Depreciation	1,788		2,119		2,764		6,671
Segment operating income	7,192		639		6,261		14,092
Capital expenditures	1,299		857		4,850		7,006
Total segment assets	49,901		59,075		110,622		219,598

Six Months Ended June 30, 2003:
Revenues:
Unaffiliated parties	$	464	$	5,883	$	17,506	$	23,853
Affiliate	23,476		—		—		23,476
Depreciation	1,430		1,174		601		3,205
Segment operating income	6,002		314		1,489		7,805
Capital expenditures	452		1		691		1,144
Total segment assets	49,400		36,370		48,594		134,364

	Six Months Ended June 30,
	2004			2003
	(in thousands)
Segment operating income	$	14,092		$	7,805
Selling, general and administrative expenses	4,724			2,931

Income from operations	9,368			4,874

Interest expense, net	(2,802		)	(1,745		)
Miscellaneous income (expense)	(1		)	34

Net income	$	6,565		$	3,163

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

Management Overview of the Three and Six Months Ended June 30, 2004

We reported net income for the three months ended June 30, 2004, of $3.9 million, or $0.52 per diluted limited partner unit, compared to net income of $1.5 million, or $0.27 per diluted limited partner unit, for the second quarter of 2003. For the six months ended June 30, 2004, the Partnership reported net income of $6.6 million, or $0.87 per diluted limited partner unit, compared to net income of $3.2 million or $0.56 per diluted limited partner unit, for the six months ended June 30, 2003.

On July 21, 2004, the board of directors of the general partner of MarkWest Energy Partners, L.P. declared the Partnership’s quarterly cash distribution of $0.74 per common and subordinated unit for the second quarter of 2004. This distribution represents an increase of $0.05 per unit over the previous quarter’s distribution. The indicated annualized rate is $2.96 per unit. The second quarter distribution is payable August 13, 2004, to unitholders of record on July 30, 2004.

Second-quarter and year-to-date net income increased over the comparable prior periods primarily due to the contributions of our 2003 acquisitions.

In addition, on July 30, 2004, the Partnership significantly expanded its midstream business by completing the acquisition of American Central East Texas Gas Company, L.P.’s Carthage gathering system and gas processing assets for $240 million. The acquisition was funded with a combination of private equity and interim debt financing. Consistent with its long-term strategy of maintaining a debt to total capital ratio of less than 50%, the Partnership intends in the near term to replace the interim debt financing with additional equity and long-term debt financing. The Carthage gathering system offers both low- and high-pressure service to producers in the Carthage Field, gathering gas from the Cotton Valley, Pettit and Travis Peak formations. The system consists of approximately 180 miles of pipeline connected to approximately 1,700 wells with an additional 82 miles of pipeline currently under construction. The gathering system also includes approximately 65,000 horsepower of compression with an additional 35,000 horsepower currently being installed. Current system throughput is approximately 245 MMcf/d and is anticipated to increase to approximately 310 MMcf/d by the end of 2004. The gathering system has a capacity of approximately 350 MMcf/d.

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. While all of these services constitute midstream energy operations, we provide our services pursuant to four different 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 generally 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 by our customers. 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, 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 value 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.

At June 30, 2004, our exposure to keep-whole contracts was limited to our Arapaho (OK) processing plant. At the 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 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.

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

	Fee-Based		Percent-of- Proceeds		Percent-of- Index		Keep-Whole		Total
Revenues	18	%	15	%	23	%	44	%	100	%
Gross Margin	69	%	11	%	11	%	9	%	100	%

Comparability of Financial Results

Recent Acquisition Activity

In reading the discussion of our historical results of operations, you should be aware of the impact 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 five acquisitions for an aggregate amount of approximately $112.3 million. These five acquisitions include:

• The Pinnacle acquisition, which closed on March 28, 2003, for consideration of $38.5 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;

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

• The Hobbs Lateral acquisition, which closed on April 1, 2004, for consideration of $2.3 million.

The first acquisition closed during the last few days of the first quarter of 2003. Three acquisitions closed during the second half of 2003 and one acquisition closed in the second quarter of 2004. Accordingly, our historical results of operations for the six months ended June 30, 2003, save for three months of activity from our Pinnacle acquisition, do not reflect the impact of these acquisitions on our operations. However, our results of operations for the three and six months ended June 30, 2004, do reflect the impact from our four 2003 acquisitions.

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 six months ended June 30, 2004, accounted for 22% of our revenues and 43% of our gross margin. This represents a decrease from the year ended December 31, 2003, during which MarkWest Hydrocarbon accounted for 42% of our revenues and 59% of our gross margin. Currently, we derive a significant portion of our revenues from the services we provide under our contracts with MarkWest Hydrocarbon. However, these percentages are likely to decrease in the future as we continue to acquire assets and increase our customer and business diversification. At June 30, 2004, MarkWest Hydrocarbon and its subsidiaries owned 35% of our limited partner interests and continues to direct our business operations through its majority ownership and control of our general partner.

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 June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
Appalachia:
Natural gas processed for a fee (Mcf/d)(1)	197,000	189,000	202,000	196,000
NGLs fractionated for a fee (Gal/d)	480,000	391,000	469,000	418,000
NGL product sales (gallons)	11,001,000	8,116,000	21,927,000	18,199,000
Michigan:
Natural gas processed for a fee (Mcf/d)	12,200	14,500	13,000	14,900
NGL product sales (gallons)	2,390,000	2,917,000	5,103,000	5,859,000
Crude oil transported for a fee (Bbl/d)(2)	14,700	—	14,700	—
Southwest:
Gathering systems throughput (Mcf/d)(3)	103,900	44,600	100,900	NM
Lateral throughput volumes (Mcf/d)(4)	119,300	—	74,100	—
NGL product sales (gallons)(5)	8,317,000	—	16,512,000	—

NM – Not meaningful^.

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

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

(3) Includes volumes from our Pinnacle gathering systems, which were acquired in late March 2003, and our Foss Lake (OK) gathering system, which was acquired in December 2003.

(4) Includes volumes from our Power-Tex Lateral pipeline (a/k/a the Lubbock Pipeline), which was acquired in September 2003, and our Hobbs Lateral pipeline, which was acquired 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 three other lateral pipelines and, consequently, the throughput data from these three lateral pipelines is excluded from this statistic.

(5) Includes sales from our Arapaho (OK) processing plant, which was acquired in December 2003.

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

	Three Months Ended June 30,						Change
	2004			2003			$			%
	(dollars in thousands)
Revenues:
Sales to unaffiliated parties	$	50,626		$	19,554		$	31,072		159	%
Sales to affiliate	13,805			10,082			3,723			37	%
Total revenues	64,431			29,636			34,795			117	%

Operating expenses:
Purchased product costs	47,560			18,423			29,137			158	%
Facility expenses	6,097			5,167			930			18	%
Selling, general and administrative	2,074			1,678			396			24	%
Depreciation	3,414			1,860			1,554			84	%
Total operating expenses	59,145			27,128			32,017			118	%

Income from operations	5,286			2,508			2,778			111	%

Other income (expense):
Interest expense, net	(1,316		)	(984		)	(332		)	34	%
Other income (expense)	(24		)	14			(38		)	(271%	)

Net income	$	3,946		$	1,538		$	2,408		157	%

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

Purchased Product Costs. Purchased product costs increased during the three months ended June 30, 2004, relative to the same time period in 2003 primarily due to our 2003 acquisitions, which increased purchased product costs approximately $27.4 million. The remainder of the increase is principally attributable to price and volume increases for our Appalachian NGL product sales.

Facility Expenses. Facility expenses increased during the three months ended June 30, 2004, relative to the same time period in 2003 primarily due to our 2003 acquisitions, which increased our facility expenses $1.1 million. Reductions in expenses in our Pinnacle operations partially offset the above.

Selling, General and Administrative Expenses. Selling, general and administrative expenses (“SG&A”) increased during the three months ended June 30, 2004, relative to the same time period in 2003 primarily because of increased professional services costs.

Depreciation. Depreciation increased during the three months ended June 30, 2004, relative to the same time period in 2003 primarily due to our 2003 acquisitions, which increased depreciation by approximately $826,000 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 June 30, 2004, relative to the same time period in 2003 primarily due to increased debt levels resulting from the financing of our 2003 acquisitions.

Six Months Ended June 30, 2004, Compared to Six Months Ended June 30, 2003

	Six Months Ended June 30,						Change
	2004			2003			$			%
	(dollars in thousands)
Sales to unaffiliated parties	$	100,145		$	23,853		$	76,292		320	%
Sales to affiliate	28,099			23,476			4,623			20	%
Total revenues	128,244			47,329			80,915			171	%

Operating expenses:
Purchased product costs	95,060			26,815			68,245			255	%
Facility expenses	12,421			9,504			2,917			31	%
Selling, general and administrative	4,724			2,931			1,793			61	%
Depreciation	6,671			3,205			3,466			108	%
Total operating expenses	118,876			42,455			76,421			180	%

Income from operations	9,368			4,874			4,494			92	%

Other income (expense):
Interest expense, net	(2,802		)	(1,745		)	(1,057		)	61	%
Other income (expense)	(1		)	34			(35		)	(103%	)

Net income	$	6,565		$	3,163		$	3,402		108	%

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

Purchased Product Costs. Purchased product costs increased during the first six months of 2004 relative to the same time period in 2003 primarily due to our 2003 acquisitions, which increased purchased product costs approximately $65.1 million. The remainder of the increase is primarily attributable to price and volume increases for our Appalachian NGL product sales.

Facility Expenses. Facility expenses increased during the first six months of 2004 relative to the same time period in 2003 primarily due to our 2003 acquisitions, which increased our facility expenses $3.3 million. Reductions in expenses of approximately $0.4 million at our historical Michigan operations due to reduced throughput partially offset the increase from our 2003 acquisitions.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased during the first six months of 2004 relative to the same time period in 2003 primarily because our SG&A was contractually limited 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. The addition of our three Southwest acquisitions—Pinnacle, Power-Tex Lateral pipeline, and the western Oklahoma gathering and processing assets—directly added approximately $0.4 million.

Depreciation. Depreciation increased during the first six months of 2004 relative to the same time period in 2003 primarily due to our 2003 acquisitions, which increased depreciation approximately $2.8 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 first six months of 2004 relative to the same time period in 2003 primarily due to increased debt levels resulting from the financing of our 2003 acquisitions.

Liquidity and Capital Resources

During January 2004, we completed an offering of 1.17 million 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 an offering of approximately 1.3 million of our common units, at $34.50 per unit, which netted us approximately $45 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 million to $315 million. We used the proceeds from the offering and borrowings under our credit facility to finance the American Central East Texas Acquisition.

The credit facility includes a $265 million revolving facility and a $50 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. At August 2, 2004, $287 million was outstanding, and $28 million was available, under the credit facility. We intend to permanently finance these assets in the near term with additional equity and long-term debt. 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.

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. In the event that we desire or need to raise additional capital, we cannot assure 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 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, 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 $1.6 million for the remainder of 2004. For the six months ended June 30, 2004, these expenditures were $0.8 million.

Credit Facility

The Partnership’s $315.0 million credit facility is available to fund capital expenditures and certain permitted acquisitions not to exceed $10.0 million in aggregate, 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 June 30, 2004, $86.2 million was outstanding, and $53.8 million was available, under the Partnership’s credit facility. During July 2004, the maximum lending limit under the Partnership’s credit facility was increased from $140.0 million to $315.0 million, in order to finance the American Central East Texas Acquisition. At August 2, 2004, $287.0 million was outstanding, and $28.0 million was available, under the Partnership’s credit facility. The Partnership’s revolving facility matures in May 2005 and the term loan facility matures in December 2004. Our average interest rate was approximately 3.8% at June 30, 2004.

Cash Flows

	Six Months Ended June 30,
	2004			2003
	(in thousands)
Net cash provided by operating activities	$	14,450		$	9,878
Net cash used in investing activities	$	(9,139	)	$	(39,379	)
Net cash provided by (used in) financing activities	$	(5,193	)	$	34,645

Net cash provided by operating activities for the six months ended June 30, 2004, increased relative to the same period from the prior year primarily due to increased net income, a function of our four 2003 acquisitions.

Net cash used in investing activities for the six months ended June 30, 2004, decreased relative to the same period from the prior year primarily due to the acquisition of Pinnacle in March 2003.

Net cash provided by financing activities during the six months ended June 30, 2004, was primarily a result of our January 2004 secondary offering, the proceeds from which were principally used to pay down our outstanding debt. Additionally, we paid out $10.1 million in distributions to unitholders in the six months ended June 30, 2004. Net cash provided by financing activities for the six months ended June 30, 2003, was primarily the result of borrowings from our credit facility, which were used to finance the Pinnacle acquisition.

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;

• 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;

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

• Our ability to refinance our outstanding debt.

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

For the six months ended June 30, 2004, approximately 31% 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 9% 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. 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 uses a statistical method that analyzes 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 hedge our NGL product sales by selling forward propane or crude oil.

We hedge our natural gas price risk in Texas (part of our Pinnacle acquisition) by entering into fixed-for-float swaps or buying puts. As of June 30, 2004, we hedged our Texas natural gas price risk via swaps as follows:

	Year Ending December 31,
	2004		2005

MMBtu	92,000		182,500
$/MMBtu	$	4.57	$	4.26

As of June 30, 2004, we also had hedged our Texas natural gas price risk via puts as follows:

	Year Ending December 31,
	2004		2005

MMBtu	184,000		—
Strike price ($/MMBtu)	$	4.00	$	—

As of June 30, 2004, we had no contracts in place to manage our NGL product price risk.

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 June 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) 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 June 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 June 30, 2004, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, our Certifying Officers concluded that as of June 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.

PART II. OTHER INFORMATION

Item 2. Changes in Securities and Use of Proceeds

(a) N/A

(b) N/A

(c) 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 will file a Form D with the Securities and Exchange Commission with respect to the transaction on or about August 13, 2004. The proceeds were used to partially finance the American Central East Texas Acquisition.

(d) N/A

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

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.

(b) Reports on Form 8-K

A Current Report on Form 8-K was filed with the SEC under Item 4 on April 16, 2004, announcing that the Partnership engaged KPMG LLP as its independent accountants for the fiscal year ending December 31, 2004.

A Current Report on Form 8-K was furnished with the SEC under Item 12 on May 6, 2004, concerning the Partnership’s first quarter earnings release dated May 6, 2004.

A Current Report on Form 8-K was furnished with the SEC under Item 9 on June 4, 2004, announcing the appointment of James G. Ivey as Chief Financial Officer of MarkWest Hydrocarbon, Inc., the entity that controls the general partner of the Partnership.

SIGNATURE

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

		MarkWest Energy Partners, L.P.
		(Registrant)

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

Date: August 9, 2004		/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 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.