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 March 31, 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 April 30, 2004, were 3,997,502 and 3,000,000, respectively.

PART I-FINANCIAL INFORMATION

Item 1.	Financial Statements
	Consolidated Balance Sheets at March 31, 2004 and December 31, 2003
	Consolidated Statements of Operations for the Three Months Ended March 31, 2004 and 2003
	Consolidated Statements of Other Comprehensive Income for the Three Months Ended March 31, 2004 and 2003
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2004 and 2003
	Consolidated Statements of Changes in Capital for the Three Months Ended March 31, 2004
	Notes to the Consolidated Financial Statements

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

PART II-OTHER INFORMATION

Item 6.	Exhibits and Reports on Form 8-K

SIGNATURE

Glossary of Terms

Bpd		barrels of oil per day
Gal/d		gallons per day
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

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

(in thousands)

	March 31, 2004			December 31, 2003
ASSETS
Current assets:
Cash and cash equivalents	$	11,216		$	8,753
Receivables, net	12,689			11,942
Receivables from affiliate	3,206			2,417
Inventories	230			353
Other assets	206			223
Total current assets	27,547			23,688

Property, plant and equipment	227,284			224,534
Less: Accumulated depreciation	(43,569		)	(40,320		)
Total property, plant and equipment, net	183,715			184,214

Deferred financing costs, net	3,507			3,831
Deferred offering costs	—			995
Investment in and advances to equity investee	245			250
Total assets	$	215,014		$	212,978

LIABILITIES AND CAPITAL

Current liabilities:
Accounts payable	$	15,194		$	14,064
Payables to affiliate	1,770			1,524
Accrued liabilities	5,765			5,163
Risk management liability	465			373
Total current liabilities	23,194			21,124

Long-term debt	84,200			126,200
Risk management liability	154			125
Other liabilities	478			478
Commitments and contingencies

Capital:
Partners’ capital	107,607			65,549
Accumulated other comprehensive loss	(619		)	(498		)
Total capital	106,988			65,051
Total liabilities and capital	$	215,014		$	212,978

The accompanying notes are 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 March 31,
	2004			2003
Revenues:
Sales to unaffiliated parties	$	49,519		$	4,299
Sales to affiliate	14,294			13,394
Total revenues	63,813			17,693

Operating expenses:
Purchased product costs	47,500			8,392
Facility expenses	6,324			4,337
Selling, general and administrative expenses	2,650			1,253
Depreciation	3,257			1,345
Total operating expenses	59,731			15,327

Income from operations	4,082			2,366

Other income (expense):
Interest expense, net	(1,486		)	(761		)
Miscellaneous income	23			20

Net income	$	2,619		$	1,625

Interest in net income:
General partner	$	229		$	32
Limited partners	$	2,390		$	1,593

Net income per limited partner unit:
Basic	$	0.35		$	0.29
Diluted	$	0.35		$	0.29

Weighted average units outstanding:
Basic	6,777			5,415
Diluted	6,806			5,464

The accompanying notes are integral part of these financial statements.

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME

(UNAUDITED)

(in thousands)

	Three Months Ended March 31,
	2004			2003
Net income	$	2,619		$	1,625

Other comprehensive income (loss):
Risk management activities		(121	)	4

Comprehensive income	$	2,498		$	1,629

The accompanying notes are integral part of these financial statements.

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)

	Three Months Ended March 31,
	2004			2003
Cash flows from operating activities:
Net income	$	2,619		$	1,625
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation	3,257			1,345
Gain from sale of property, plant and equipment	(24		)	—
Amortization of deferred financing costs included in interest expense	313			130
Non-cash compensation expense	374			212
Other	5			(1		)
Changes in operating assets and liabilities:
Increase in receivables	(1,536		)	(4,210		)
Decrease in inventories	123			9
Decrease in other current assets	17			44
Increase in accounts payable and accrued liabilities	1,604			3,654
Net cash provided by operating activities	6,752			2,808

Cash flows from investing activities:
Pinnacle acquisition, net of cash acquired	—			(38,238		)
Capital expenditures	(2,758		)	(98		)
Proceeds from sale of assets	32			3
Other	3			—
Net cash used in investing activities	(2,723		)	(38,333		)

Cash flows from financing activities:
Proceeds from long-term debt	—			40,200
Repayment of long-term debt	(42,000		)	(500		)
Proceeds from secondary offering, net	45,391			—
Distributions to unitholders	(4,957		)	(2,873		)
Payments for debt issuance costs	—			(760		)
Net cash provided by (used in) financing activities	(1,566		)	36,067

Net increase in cash	2,463			542
Cash and cash equivalents at beginning of period	8,753			2,776
Cash and cash equivalents at end of period	$	11,216		$	3,318

The accompanying notes are integral part of these financial statements.

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL

(UNAUDITED)

(in thousands)

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

Proceeds from secondary offering, net	1,173	43,508			—	—			888			—		—			44,396

Net income	—	1,235			—	1,155			229			—		—			2,619

Distributions to partners	—	(2,671		)	—	(2,010		)	(276		)	—		—			(4,957		)

Other comprehensive loss	—	—			—	—			—			—		(121		)	(121		)

Balance, March 31, 2004	3,987	$	93,115		3,000	$	12,514		$	1,283		$	695	$	(619	)	$	106,988

The accompanying notes are 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 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 months ended March 31, 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 $3.4 million resulted in net proceeds from the secondary public offering of $44.4 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 $45.4 million.

4. Acquisitions

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, are 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 (the “western Oklahoma acquisition”) of certain assets of American Central Western Oklahoma Gas Company, L.L.C. (“AWOC”) for approximately $38 million. Western Oklahoma’s results of operations have been included in the Partnership’s consolidated financial statements since that date.

The assets acquired include the Foss Lake gathering system (the “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 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 million to $140 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

	$	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 $21.2 million. The System’s results of operations have been included in the Partnership’s consolidated financial statements since December 18, 2003. The $21.2 million purchase price was financed through borrowings under the Partnership 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, and comprises approximately 100 miles of pipe. 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 $21.2 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
	$	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 March 31, 2003
	MarkWest Energy Partners		Pinnacle		Western Oklahoma		Michigan Crude Pipeline		Adjustments			Total
	(in thousands, except per unit)
Revenue	$	17,693	$	18,614	$	11,083	$	1,110	$	(827	)	$	47,673
Net income	$	1,625	$	1,114	$	16	$	494	$	(1,105	)	$	2,144
Basic net income per limited partner unit	$	0.29										$	0.39
Diluted net income per limited partner unit	$	0.29										$	0.38

Subsequent Event

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.

5. Property, Plant and Equipment

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

		March 31, 2004			December 31, 2003
		(in thousands)
Property, plant and equipment:
Gas gathering facilities		$	75,631		$	73,424
Gas processing plants		56,289			55,888
Fractionation and storage facilities		22,387			22,160
Natural gas pipelines		38,817			38,790
Crude oil pipelines		18,352			18,352
NGL transportation facilities		4,415			4,415
Land, building and other equipment		9,768			9,664
Construction in-progress		1,625			1,841
		227,284			224,534
Less:	Accumulated depreciation	(43,569		)	(40,320		)
	Total property, plant and equipment, net	$	183,715		$	184,214

6. Distribution to Unitholders

On January 21, 2004, the Partnership declared a cash distribution of $0.67 per unit on its outstanding common and subordinated units for the quarter ended December 31, 2003. The approximate $5.0 million distribution, including $0.3 million distributed to the general partner, was paid on February 13, 2004, to unitholders of record as of the close of business on January 31, 2004.

On April 21, 2004, we declared a cash distribution of $0.69 per common and subordinated unit for the quarter ended March 31, 2004. The distribution will be paid on May 14, 2004, to unith olders of record as of April 30, 2004.

7. 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.

8. Unit Compensation

As permitted under SFAS No. 123, Accounting for Stock-Based Compensation, 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.

In addition, for the three months ended March 31, 2004 and 2003, we recorded compensation expense of $0.4 million and $0.2 million, respectively, related to our variable plan. These charges are included in selling, general and administrative expenses.

9. Adoption of SFAS No. 143

In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, a gain or loss is recognized on settlement. We adopted the provisions of SFAS No. 143 effective January 1, 2003. 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 we did not identify any legal obligations associated with the retirement of our tangible long-lived assets. Therefore, the adoption of SFAS No. 143 did not have an impact on our consolidated financial statements.

10. 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 (the Appleby and 18 other gathering systems) 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.

We had revenues from MarkWest Hydrocarbon, reflected as “Affiliate”, which represented 22% and 76% of our revenues for the three months ended March 31, 2004 and 2003, respectively.

	Appalachia		Michigan		Southwest		Total
	(in thousands)
Three Months Ended March 31, 2004:
Revenues:
Affiliate	$	14,294	$	—	$	—	$	14,294
Unaffiliated parties	379		3,918		45,222		49,519
Depreciation	857		1,060		1,340		3,257
Segment operating income	3,809		356		2,567		6,732
Capital expenditures	338		163		2,257		2,758
Total segment assets	50,262		58,639		106,113		215,014

Three Months Ended March 31, 2003:
Revenues:
Affiliate	$	13,394	$	—	$	—	$	13,394
Unaffiliated parties	231		3,241		827		4,299
Depreciation	713		586		46		1,345
Segment operating income	3,278		279		62		3,619
Capital expenditures	97		1		—		98
Total segment assets	50,453		36,200		50,080		136,733

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 March 31,
	2004			2003
	(in thousands)
Segment operating income	$	6,732		$	3,619
Selling, general and administrative expenses	2,650			1,253

Income from operations	4,082			2,366

Interest expense, net	(1,486		)	(761		)
Miscellaneous income	23			20

Net income	$	2,619		$	1,625

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

Management Overview of the Quarter ended March 31, 2004

We reported net income of $2.6 million for the three months ended March 31, 2004, or $0.35 per diluted limited partner unit, compared to net income of $1.6 million, or $0.29 per diluted limited partner unit, for the first quarter of 2003.

First quarter 2004 net income included the first full quarterly contributions by our two December 2003 acquisitions: the Foss Lake gathering system and Arapaho gas processing assets in western Oklahoma, which were acquired December 1, 2003, and the Michigan crude oil pipeline, which was acquired December 18, 2003. For the first quarter of 2004, our Oklahoma acquisition generated approximately $1.0 million in income from operations, and our Michigan crude pipeline acquisition generated approximately $0.2 million in income from operations.

First quarter 2004 results were adversely impacted by unexpected downtime at our Cobb processing plant in Appalachia. The facility was shutdown for approximately 45 days during the first quarter due to equipment failure. The plant has since been repaired and is operating normally. Income from operations was approximately $0.3 million less than it would have been had our Cobb operations not been interrupted during first quarter 2004. Current plans are to replace the existing plant with a new facility during the second half of 2004.

During January 2004, we raised approximately $44.4 million, net of transaction costs, through a secondary offering of 1.17 million units at a price of $39.90 per unit. The proceeds from the offering were used to pay down long-term debt.

As previously announced, on April 1, 2004, we acquired the Hobbs Lateral pipeline for approximately $2.3 million dollars. The Hobbs Lateral consists of a four-mile segment of 10-inch and 12-inch gas pipeline 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 and was recently expanded to a capacity of approximately 160 MMcf/d.

On April 21, 2004, the board of directors of the general partner of MarkWest Energy Partners, L.P., declared the Partnership’s quarterly cash distribution of $0.69 per unit for the first quarter of 2004. This distribution represents an increase of $0.02 per unit, or 3%, over the previous quarterly distribution. The indicated annual rate is $2.76 per unit. The first quarter distribution will be paid May 14, 2004, to unitholders of record on April 30, 2004.

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. 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. 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.

In our current areas of operations, we have a combination of contract types and limited keep-whole arrangements. The only keep-whole contracts we presently have are associated with our Arapaho processing plant, a part of our December 2003 Oklahoma acquisition. However, since the Btu content of the inlet natural gas meets the downstream pipeline specifications, we have the option of not extracting NGLs in a low processing margin environment. In addition, approximately 45% 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, and the additional fees provided for in the gas gathering contracts, our 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 three months ended March 31, 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	%	16	%	23	%	43	%	100	%
Gross Margin	69	%	12	%	11	%	8	%	100	%

Items Impacting 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 four acquisitions for an aggregate purchase price of approximately $110 million. These four 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; and

• The Michigan Crude Pipeline acquisition, which closed December 18, 2003, for consideration of $21.2 million.

The first acquisition closed during the last few days of the first quarter of 2003. The other three acquisitions closed during the second half of 2003. Accordingly, our historical results of operations for the three months ended March 31, 2003, save for four days 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 months ended March 31, 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 three months ended March 31, 2004, accounted for 22% of our revenues and 44% 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. The three months ended March 31, 2004, represents the first full quarter’s impact of our December 2003 acquisitions. 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, 2004, MarkWest Hydrocarbon and its subsidiaries owned 34.6% of our limited partner interests and continues to direct our business operations through its 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 March 31,
	2004	2003
Appalachia:
Natural gas processed for a fee (Mcf/d)(1)	207,000	203,000
NGLs fractionated for a fee (Gal/d)	462,000	446,000
NGL product sales (gallons)	10,926,000	10,214,000
Michigan:
Natural gas processed for a fee (Mcf/d)	13,900	15,400
NGL product sales (gallons)	2,700,000	2,900,000
Crude oil transported for a fee (bpd)(2)	14,600	—
Southwest:
Gathering systems throughput (Mcf/d)(3)	97,800	NM
Lateral throughput volumes (Mcf/d)(4)	28,900	—
NGL product sales (gallons)(5)	8,200,000	—

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 Oklahoma gathering systems, which were acquired in December 2003.

(4) Includes volumes from our Power-Tex Lateral pipeline, which was acquired in September 2003. Our Power-Tex Lateral pipeline (previously referred to as the Lubbock Pipeline) is the only lateral we owned during the first quarter of 2004 that produces revenue on a per-unit-of-throughput basis. We receive a flat fee from the other three lateral pipelines we owned during the first quarter of 2004 and, therefore, the throughput data from these lateral pipelines is excluded from this statistic. We acquired a fifth lateral pipeline, referred to as the Hobbs Lateral, on April 1, 2004. The Hobbs Lateral generates revenue on a per-unit-of-throughput basis similar to the Power-Tex lateral.

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

Three Months Ended March 31, 2004, Compared to Three Months Ended March 31, 2003

	Three Months Ended March 31,						Change
	2004			2003			$			%
	(dollars in thousands)
Revenues:
Sales to unaffiliated parties	$	49,519		$	4,299		$	45,220		1,052	%
Sales to affiliate	14,294			13,394			900			7	%
Total revenues	63,813			17,693			46,120

Operating expenses:
Purchased product costs	47,500			8,392			39,108			466	%
Facility expenses	6,324			4,337			1,987			46	%
Selling, general and administrative	2,650			1,253			1,397			111	%
Depreciation	3,257			1,345			1,912			142	%
Total operating expenses	59,731			15,327			44,404			290	%

Income from operations	4,082			2,366			1,716			73	%

Other income (expense):
Interest expense, net	(1,486		)	(761		)	(725		)	95	%
Other income	23			20			3			15	%

Net income	$	2,619		$	1,625		$	994		61	%

Revenues. Revenues increased during the first three months of 2004 relative to the same time period in 2003 primarily due to our 2003 acquisitions, which increased revenues approximately $44.6 million. The remainder of the increase is principally attributable to a 750,000-gallon sales increase of our Maytown production.

Purchased Product Costs. Purchased product costs increased during the first three months of 2004 relative to the same time period in 2003 primarily due to our 2003 acquisitions, which increased purchased product costs approximately $38.0 million.

Facility Expenses. Facility expenses increased during the first three months of 2004 relative to the same time period in 2003 primarily due to our 2003 acquisitions, which increased our facility expenses $2.4 million. Reductions in expenses of approximately $0.4 million at our historical Appalachian and Michigan operations partially offset the increase from our 2003 acquisitions.

Selling, General and Administrative Expenses. Selling, general and administrative expenses (“SG&A”) increased during the first three 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 elapsed. The addition of our three Southwest acquisitions—Pinnacle, Power-Tex Lateral pipeline, and the Oklahoma gathering and processing assets—directly added $0.3 million.

Depreciation. Depreciation increased during the first three months of 2004 relative to the same time period in 2003 primarily due to our 2003 acquisitions, which increased depreciation approximately $1.9 million for the quarter. Additionally, commencing January 1, 2004, we have 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 three 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 a secondary offering of 1.17 million of our common units, at $39.90 per unit, which netted us approximately $44.4 million after transaction costs and the general partner contribution. We primarily used the proceeds to pay down our outstanding debt.

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, 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 $2.1 million for the remainder of 2004. For the three months ended March 31, 2004, these expenditures were $0.2 million.

Credit Facility

The Partnership’s $140 million credit facility is available to fund capital expenditures and acquisitions, working capital requirements (including letters of credit) and distributions to unit holders. Advances to fund distributions to unit holders 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 unit holders. At March 31, 2004, $84.2 million was outstanding, and $55.8 million was available, under the Partnership’s credit facility. The Partnership’s credit facility matures in November 2006. Our average interest rate was approximately 4.6% at March 31, 2004.

Cash Flows

	Three Months Ended March 31,
	2004			2003
	(in thousands)

Net cash provided by operating activities	$	6,752		$	2,808
Net cash used in investing activities	$	(2,723	)	$	(38,333	)
Net cash provided by (used in) financing activities	$	(1,566	)	$	36,067

Net cash provided by operating activities was higher during the three months ended March 31, 2004, than during the three months ended March 31, 2003, primarily due to increased activities as a result of the Pinnacle, Power-Tex lateral pipeline, western Oklahoma, and Michigan Crude Pipeline acquisitions. Net cash used in investing activities during the three months ended March 31, 2004, was due to capital expenditures for existing facilities; net cash used in investing activities during the three months ended March 31, 2003, was primarily due to the Pinnacle acquisition. 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. In addition, the Partnership distributed $5.0 million to unitholders. Net cash provided by financing activities during the three months ended March 31, 2003, included $39.5 million of net proceeds from long-term debt, the majority of which was used to fund the Pinnacle acquisition, and repayments of long-term debt of $0.5 million. In addition, the Partnership distributed $2.9 million to unitholders.

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.

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;

•< /font> 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;

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

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

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

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

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

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

For the three months ended March 31, 2004, approximately 31% of our business (as measured by gross margin, which is defined as revenues less purchased product cost) was directly subject to 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 8% of our business 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 buy puts. As of March 31, 2004, we hedged our Texas natural gas price risk via swaps as follows:

	Year Ending December 31,
	2004		2005		2006

MMBtu	137,500		182,500		—
$/MMBtu	$	4.57	$	4.26	$	—

As of March 31, 2004, we also had hedged our Texas natural gas price risk via puts as follows:

	Year Ending December 31,
	2004		2005		2006

MMBtu	274,500		—		—
Strike price ($/MMBtu)	$	4.00	$	—	$	—

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 agreements expiring May 19, 2005 to adjust the ratio of fixed and floating rates in the debt portfolio. As of March 31, 2004, we are a party to contracts to fix interest rates on $8.0 million of our debt at 3.84% compared to floating LIBOR, plus an applicable margin.

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 March 31, 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 March 31, 2004, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, our Certifying Officers concluded that as of March 31, 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 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 Accounting Officer Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act.

31.3		Vice President, Treasurer and Secretary 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 Vice President, Treasurer and Secretary 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 March 1, 2004, announcing that the Partnership dismissed PricewaterhouseCoopers LLP as its independent accountants.

A current report on Form 8-K was furnished with the SEC under Item 12 on March 11, 2004, concerning the Partnership’s fourth quarter earnings release dated March 11, 2004.

An amended current report on Form 8-K/A was filed with the SEC under Item 4 on March 22, 2004, announcing that March 15, 2004, was the effective date of the dismissal of PricewaterhouseCoopers LLP as the Partnership’s independent accountants.

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: May 6, 2004	/s/ Ted S. Smith
	Ted S. Smith
	Chief Accounting Officer

Exhibit Number		Exhibit Index

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

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

31.3		Vice President, Treasurer and Secretary 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 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 Vice President, Treasurer and Secretary 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.