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, 2003

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 1-31239

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 o No ý

The number of the registrant’s Common Units outstanding at April 30, 2003, was 2,415,000.


PART I-FINANCIAL INFORMATION

Item 1. Financial Statements
Consolidated and Combined Balance Sheets at March 31, 2003 and December 31, 2002
Consolidated and Combined Statements of Operations for the Three Months Ended March 31, 2003 and 2002
Consolidated and Combined Statements of Cash Flows for the Three Months Ended March 31, 2003 and 2002
Consolidated and Combined Statements of Changes in Capital for the Three Months Ended March 31, 2003
Notes to the Consolidated and Combined 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

CERTIFICATIONS

Glossary of Terms

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 AND COMBINED BALANCE SHEETS

(UNAUDITED)

ASSETS	March 31, 2003			December 31, 2002
	(in thousands)
Current assets:
Cash and cash equivalents	$	3,318		$	2,776
Receivables	11,329			976
Receivables from affiliate	4,142			2,847
Inventories	121			130
Other assets	369			336
Total current assets	19,279			7,065

Property, plant and equipment:
Gas gathering equipment	45,945			34,398
Gas processing plants	47,403			47,403
Pipelines	25,880			—
Fractionation and storage equipment	22,076			22,076
NGL transportation equipment	4,402			4,402
Land, building and other equipment	3,075			3,021
Construction in progress	368			348
	149,149			111,648
Less:Accumulated depreciation	(33,145		)	(31,824		)
Total property, plant and equipment, net	116,004			79,824

Deferred financing costs	1,450			820
Total assets	$	136,733		$	87,709

LIABILITIES AND CAPITAL

Current liabilities:
Accounts payable	$	9,635		$	1,199
Payables to affiliate	2,014			723
Accrued liabilities	3,713			2,880
Risk management liability	493			501
Total current liabilities	15,855			5,303

Long-term debt	61,100			21,400
Risk management liability	159			143
Commitments and contingencies

Capital:
Partners’ capital	60,326			61,574
Accumulated other comprehensive income (loss)	(707		)	(711		)
Total capital	59,619			60,863
Total liabilities and capital	$	136,733		$	87,709

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

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended March 31, 2003 (Partnership)			Three Months Ended March 31, 2002 (MarkWest Hydrocarbon Midstream Business)
	(in thousands, except per unit amounts)

Revenues:
Sales to affiliate.	$	13,394		$	27,440
Sales to unaffiliated parties	4,299			—
Total revenues	17,693			27,440

Operating expenses:
Purchased product costs	8,392			19,675
Plant operating and other expenses	4,337			3,779
Selling, general and administrative expenses	1,253			1,362
Depreciation	1,345			1,202
Total operating expenses	15,327			26,018

Income from operations	2,366			1,422

Other income and (expenses):
Interest expense, net	(761		)	(301		)
Miscellaneous income	20			—

Income before income taxes	1,625			1,121

Provision (benefit) for income taxes:
Current due to (from) parent	—			(220		)
Deferred	—			651
Provision for income taxes	—			431
Net income	$	1,625		$	690

General partner’s interest in net income	$	32

Limited partners’ interest in net income	$	1,593

Net income per limited partner unit	$	0.29

Weighted average units outstanding	5,415

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

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three Months Ended March 31, 2003 (Partnership)			Three Months Ended March 31, 2002 (MarkWest Hydrocarbon Midstream Business)
	(in thousands)
Cash flows from operating activities:
Net income	$	1,625		$	690
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	1,345			1,202
Amortization of deferred financing costs included in interest expense	130			—
Non-cash compensation expense	212			—
Deferred income taxes	—			651
Other	(1		)	(252		)
Changes in operating assets and liabilities:
(Increase) decrease in receivables	(4,210		)	1,064
(Increase) decrease in inventories	9			3,926
(Increase) decrease in prepaid replacement natural gas and other assets	44			7,508
Increase (decrease) in accounts payable and accrued liabilities	3,654			1,880
Increase in long-term replacement natural gas payable	—			3,090

Net cash provided by operating activities	2,808			19,759

Cash flows from investing activities:
Pinnacle acquisition, net of cash acquired	(38,238		)	—
Capital expenditures	(98		)	(404		)
Proceeds from sale of assets	3			—

Net cash used in investing activities	(38,333		)	(404		)

Cash flows from financing activities:
Proceeds from long-term debt	40,200			—
Repayment of long-term debt	(500		)	—
Distributions to unitholders	—			(2,873		)
Payments for debt issuance costs	(760		)	—
Net advances from (distributions to) parent	—			(19,355		)

Net cash provided by (used in) financing activities	36,067			(19,355		)

Net increase (decrease) in cash	542			—
Cash and cash equivalents at beginning of period	2,776			—
Cash and cash equivalents at end of period	$	3,318		$	—

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

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN CAPITAL

(UNAUDITED)

(in thousands)

												Accumulated Other Comprehensive Income (Loss)
	PARTNERS’ CAPITAL
	Limited Partners								General Partner						Total
	Common				Subordinated
	Units	$			Units	$			$

Balance at December 31, 2002	2,415	$	43,858		3,000	$	17,357		$	359		$	(711	)	$	60,863

Net income	—	710			—	882			33			—			1,625

Distributions to unitholders	—	(1,256		)	—	(1,560		)	(57		)	—			(2,873		)

Risk management activities	—	—			—	—			—			4			4

Balance at March 31, 2003	2,415	$	43,312		3,000	$	16,679		$	335		$	(707	)	$	59,619

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

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

1. Organization

MarkWest Energy Partners, L.P. (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 (the “MarkWest Hydrocarbon Midstream Business” or the “Midstream Business”). The transfer of assets and liabilities to the Partnership from MarkWest Hydrocarbon represented a reorganization of entities under common control and was recorded at historical cost.

We are engaged in the business of gathering, processing and transportation of natural gas and the transportation, fractionation, and storage of NGL products.

We completed our initial public offering (the “IPO”) of 2,415,000 common units at a price of $20.50 per unit on May 24, 2002. Total proceeds for the 2,415,000 units were $49.0 million before offering costs and underwriters’ commissions. Effective with the closing of the IPO, MarkWest Hydrocarbon and its wholly owned subsidiaries received 3,000,000 subordinated units (since reduced to 2,479,762 units as of March 31, 2003) and a 2% general partner interest in the Partnership. Through its ownership and control of our general partner, MarkWest Energy GP, L.L.C., MarkWest Hydrocarbon controls and directs our business operations. Also concurrent with the closing of our IPO, through our wholly owned subsidiary, MarkWest Energy Operating Company, L.L.C. (the “Operating Company”), we borrowed $21.4 million under the Operating Company’s $60 million credit facility with various lenders.

2. Basis of Presentation

The accompanying unaudited consolidated and combined financial statements include the accounts of MarkWest Energy Partners, L.P. and its wholly owned subsidiaries. The financial statements have been prepared in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States for interim financial reporting. These financial statements involve the use of estimates and judgments where appropriate. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s and the Midstream Business’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 and combined financial statements along with the audited financial statements and notes thereto included in our December 31, 2002 Annual Report on Form 10-K. Results for the three months ended March 31, 2003, are not necessarily indicative of results for the full year 2003.

3. Pinnacle Acquisition

On March 28, 2003, we completed the acquisition of Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG Transmission Company, Inc., PNG Utility Company and Bright Star Gathering, Inc. (collectively, the “Sellers”). The purchase price was comprised of $23.4 million paid in cash to the Sellers, plus the assumption of specified liabilities, including $16.6 million of bank indebtedness.

The 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 MarkWest Energy Partners 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 three lateral natural gas pipelines consist of approximately 67 miles of pipe and transport up to 1.1 Bcf/d under firm contracts to power plants. The twenty gathering systems gather more than 44 MMcf/d.

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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

Acquisition costs:
Long-term debt incurred	$	39,471
Direct acquisition costs	450
Current liabilities assumed	8,150
Total	$	48,071

Allocation of acquisition costs:
Current assets	$	10,643
Fixed assets (including long-term contracts)	37,428
Total	$	48,071

Pro Forma Results of Operations (Unaudited)

The following table reflects the unaudited pro forma consolidated results of operations for the three months ended March 31, 2003 and 2002, as though our Pinnacle acquisition had occurred on January 1, 2002. These unaudited pro forma results have been prepared for comparative purposes only and are not indicative of future results.

	Three Months Ended March 31,
	2003		2002
	(in thousands, except per share data)
Revenue	$	35,480	$	35,482
Net income	$	2,340	$	474
Basic net income per limited partner unit	$	0.42	$	N/A
Diluted net income per limited partner unit	$	0.42	$	N/A

4. Debt

In conjunction with our Pinnacle acquisition (see Note 3), we amended our credit agreement with various lenders effective March 28, 2003. The amended agreement provides for a $15 million increase to our maximum borrowing amount, now $75 million. All other aspects of the amended agreement, including rates, collateralization and covenants are similar to the original agreement.

5. 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.

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

6. Concentration of Credit Risk

MarkWest Hydrocarbon is our largest customer, accounting for 76% of our revenues for the three months ended March 31, 2003. If the Pinnacle acquisition had occurred on January 1, 2003, MarkWest Hydrocarbon would have accounted for approximately 38% of our revenues for the three months ended March 31, 2003. Although our recent Pinnacle acquisition diversifies our customer base and reduces the percentage of overall revenues derived from MarkWest Hydrocarbon, we expect MarkWest Hydrocarbon to remain our largest single customer.

MarkWest Hydrocarbon is forecasting a reduction in cash flow and possible limits on its available borrowings due to unusually high prices for natural gas it purchases to satisfy its keep-whole contractual arrangements relative to the price it is receiving for the NGLs it markets. MarkWest Hydrocarbon has undertaken a series of initiatives to address these issues, including a potential sale of assets, reducing discretionary capital expenditures and discussing with its lenders possible waivers of certain covenants under its senior credit facility should noncompliance with such covenants occur as a result of its reduced cash flow. MarkWest Hydrocarbon believes these initiatives will be successful in improving its liquidity and that it will be able to obtain any necessary waivers from its lenders of any noncompliance with its financial covenants pending consummation of its efforts to improve its liquidity position. However, the inability of MarkWest Hydrocarbon to consummate such initiatives or otherwise improve its liquidity could have an adverse impact on us.

7. Distribution to Unitholders

On February 14, 2003, we paid our cash distribution for the quarterly period ended December 31, 2002, of $0.52 per unit to our common and subordinated unitholders. The distributions were declared on January 23, 2003, payable to unitholders of record as of January 31, 2003.

On April 17, 2003, we declared our cash distribution for the quarterly period ended March 31, 2003, of $0.58 per unit. The distribution will be paid on May 15, 2003, to unitholders of record as of May 5, 2003.

8. Net Income Per Limited Partner Unit

Basic and diluted net income per unit is determined by dividing net income, after deducting the general partner’s 2% interest, by the weighted average number of outstanding common units and subordinated units.

9. Stock and 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 and stock-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. We have a variable plan and certain employees of MarkWest Hydrocarbon dedicated to or otherwise principally supporting MarkWest Energy Partners received stock-based compensation awards from MarkWest Hydrocarbon. We account for these plans using variable and fixed accounting as appropriate. 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. MarkWest Hydrocarbon stock options are issued under a fixed plan. Accordingly, compensation expense is not recognized for stock options unless the options were granted at an exercise price lower than market on the grant date.

Had compensation cost for those employees principally supporting the Partnership who participated in MarkWest Hydrocarbon’s stock-based compensation plan been determined based on the fair value at the grant dates under the plan consistent with the method prescribed by SFAS No. 123, our net income and net income per limited partner unit would have been affected as follows:

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	Three Months Ended March 31, 2003 (Partnership)			Three Months Ended March 31, 2002 (MarkWest Hydrocarbon Midstream Business)
	(in thousands)

Net income, as reported	$	1,625		$	1,121
Deduct: Total stock-based employee compensation expense determined
under fair value based method for all awards, net of related tax effects	(45		)	(62		)
Pro forma net income	$	1,580		$	1,059

Net income per limited partner unit: (1)
Basic-as reported	$	0.29		N/A
Basic-pro forma	$	0.29		N/A
Diluted-as reported	$	0.29		N/A
Diluted-pro forma	$	0.29		N/A

N/A—Not applicable

(1)The MarkWest Hydrocarbon Midstream Business did not issue any units. Consequently, no earnings per limited partner unit information is available.

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

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 o ur 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, Inc.

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

• Prices of NGL products and crude oil, including the effect iveness 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.

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

• Our ability to integrate our recent Pinnacle acquisition.

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

Results of Operations

Overview

We are a Delaware limited partnership formed by MarkWest Hydrocarbon to acquire most of the assets, liabilities and operations of the MarkWest Hydrocarbon Midstream Business (the “Midstream Business”). We are engaged in the gathering, processing and transportation of natural gas and the transportation, fractionation, and storage of NGL products. We are the largest processor of natural gas in the northeastern United States, processing gas from the Appalachian basin, one of the country’s oldest natural gas producing regions, and from Michigan. Additionally, since March 28, 2003, through our merger with the Pinnacle companies (see further information below), we gather and transport natural gas in the western part of Texas.

The financial statements of MarkWest Energy Partners, L.P., reflect historical cost-basis accounts of the Midstream Business for periods prior to May 24, 2002, the closing date of the Partnership’s initial public offering (the “IPO”) (see Note 4 of the Notes to Consolidated and Combined Financial Statements appearing earlier in this Form 10-Q) and include charges from MarkWest Hydrocarbon for direct costs and allocations of indirect corporate overhead and the results of contracts in force at that time. We believe that the allocation methods are reasonable, and that the allocations are representative of the costs that would have been incurred on a standalone basis. Beginning on May 24, 2002, the consolidated and combined financial statements reflect the financial statements of the Partnership and its subsidiaries, including the results of contracts entered into on May 24, 2002.

The Midstream Business’s financial statements differ substantially from our financial statements principally because of the differences in the way in which we generate revenues and the way in which the MarkWest Hydrocarbon Midstream Business generated revenues. Historically, the Midstream Business generated its revenues pursuant to two types of contracts:

• “Keep-whole” contracts under which Midstream Business would take title to and sell the NGLs it produced in its processing operations and would reimburse or “keep whole” the producers for the Btu content of the NGLs removed through the redelivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas.

• “Percent-of-proceeds” contracts under which the Midstream Business would take title to the NGLs it produced in its p rocessing operations, sell the NGLs to third parties, and pay the producer a specified percentage of the proceeds received from the sales.

However, currently, none of our revenues are generated pursuant to keep-whole contracts. Rather, we generate the majority of our revenues pursuant to contracts that we entered into with MarkWest Hydrocarbon at the closing of our IPO that provide for us to be paid a fee per unit for services that we provide. Like the Midstream Business, we continue to generate a portion of our revenues pursuant to percent-of-proceeds contracts under which we retain a percentage of the NGLs that we produce as compensation for processing the raw gas for producers. The largest of the differences between the financial statements of the Midstream Business and our financial statements is in revenues and purchased product cost. Generally, revenues and purchased product costs in the Midstream Business’s financial statements are higher because:

• The Midstream Business’s revenues included the aggregate sales price for all the NGL products produced in its operations.

• The Midstream Business’s purchased product costs included the cost of natural gas purchases needed to replace the Btu content of the NGLs extracted in its processing operations and the percentage of the proceeds from the sale of NGL products remitted to producers under percent-of-proceeds contracts.

In contrast, our revenues and purchased product costs, for the most part, do not include these items. Instead,

• Our revenues include just the fees we receive for the provision of gathering, processing, transportation, fractionation and storage services and the aggregate proceeds from NGL sales we receive under our percent-of-proceeds contracts.

• &# 160; Our purchased product costs primarily consists of the percentage of proceeds from the sale of NGL products remitted to producers under our percent-of-proceeds contracts.

Accordingly, whereas the Midstream Business’s results of operations depended on the volumes of NGL products sold and the difference between the sale price of NGL products and the cost of replacement natural gas, our results of operations depend primarily on the volume of natural gas processed, NGLs fractionated and, to the extent of our percent-of-proceeds contracts, the market price of NGL products. Because of these significant differences, the “Resu lts of Operations” for the Midstream Business discussed below may be of limited use in evaluating the business conducted by us. The nature of the Midstream Business’s and our revenues and costs are presented in more extensive detail below and may help you better understand the historical results discussed herein, as well as our operating results going forward.

MarkWest Hydrocarbon Midstream Business

The Midstream Business historically generated the majority of its revenues through the sale of NGL products obtained in exchange for providing processing and fractio nation services to natural gas producers. NGL product prices, and the volume of natural gas processed and NGLs fractionated and sold, were the primary determinants of revenues. In Appalachia, the Midstream Business processed natural gas under keep-whole contracts and a contract containing both fee and percent-of-proceeds components. In Michigan, the Midstream Business processed natural gas under contracts containing both fee and percent-of-proceeds components. Under keep-whole and percent-of-proceeds contracts, the Midstream Business recorded as revenues the gross proceeds retained from the sale of NGL products produced. Gathering and processing contracts containing a fee component required producers to pay the Midstream Business a fee to gather and process their gas.

The Midstream Business’s purchased product costs were comprised of a keep-whole contract component and a percent-of-proceeds contract component. Under keep-whole contracts, the Midstream Business’s principal cost was the reimbursement to the natural gas producers for the energy extracted from their natural gas stream in the form of NGLs. The Midstream Business kept the producers whole on an energy basis by replacing the extracted Btu content of the NGLs with additional volumes of dry natural gas. Under percent-of-proceeds contracts, the Midstream Business’s principal cost was the percentage of the proceeds from the sale of the NGL products that was remitted to the producers.

The Midstream Business’s plant operating expenses principally consisted of costs needed to operate its facilities, including personnel costs, fuel needed to operate the plants, plant utility costs and maintenance expenses. The Midstream Business’s fuel costs were partially offset by contractual reimbursements from producers. Some operating costs, such as fuel costs, fluctuated depending on the amount of natural gas processed or NGL products fractionated and the price of natural gas.

The Midstream Business’s general and administrative expenses were costs allocated by MarkWest Hydrocarbon. Historically, these costs have included legal, accounting, treasury, engineering, information technology, insur ance and other corporate services.

MarkWest Energy Partners, L.P.

We generate the majority of our revenues from gas gathering, processing and transportation and NGL transportation, fractionation and storage. In Appalachia, our primary sources of revenues are our operating agreements with MarkWest Hydrocarbon.

These operating agreements include:

• A Gas Processing Agreement under which MarkWest Hydrocarbon delivers all gas gathered by Columbia Gas and delivered to MarkWest Hydrocarbon upstream of our facilities for processing at our Kenova, Boldman and Cobb plants. We accept and process all such gas up to the then-existing capacity of the applicable plant. As payment for these services, we receive a monthly processing fee based on the natural gas volumes delivered to us.

• A Pipeline Liquids Transportation Agreement under which MarkWest Hydrocarbon delivers all of its NGLs acquired from our Kenova facility, and any of its NGLs it desires to deliver from our Boldman facility or from other sources in the Appalachian region for transportation through our pipeline facilities to our Siloam fractionation facility. As payment for these services, MarkWest Hydrocarbon pays us a monthly transportation fee based on the number of gallons transported.

• A Fractionation, Storage and Loading Agreement under which MarkWest Hydrocarbon delivers all of the mixed NGLs produced at our Kenova, Boldman or Cobb processing plants for fractionation at our Siloam fractionation facility. We unload the NGLs delivered to us, fractionate all the NGLs, lease tracking rights on our Siloam railroad siding to MarkWest Hydrocarbon, load the finished

NGL products for shipment and as directed by MarkWest Hydrocarbon, store the finished NGL products in underground storage caverns. As payment for these services, MarkWest Hydrocarbon pays us a monthly fractionation fee based on the number of gallons we fractionate, an annual storage fee and a monthly fee based on the number of gallons of NGLs we unload at our Siloam facility.

• A Natural Gas Liquids Purchase Agreement under which MarkWest Hydrocarbon receives and purchases, and we deliver and sell, all of the NGL products we produce pursuant to our gas processing agreement with a third party. Under the terms of this agreement, MarkWest Hydrocarbon pays us a purchase price equal to the proceeds it receives from the resale to third parties of such NGL products. This contract applies to any other NGL products we acquire. We retain a percentage of the proceeds attributable to the sale of NGL products we produce pursuant to our agreement with a third party, and remit the balance from such NGL product sale proceeds to a third party.

A portion of each of the above-mentioned fees is adjusted annually to reflect changes in the Producers Price Index for Oil and Gas Field Services.

In Michigan, we assumed the MarkWest Hydrocarbon Midstream Business’s existing contracts and gather and process natural gas directly for those third parties. We receive 100% of all fee and percent-of-proceeds consideration for the first 10,000 Mcf/d that we gather in Michigan. MarkWest Hydrocarbon retains a 70% net profit interest in the gathering and processing income we earn on quarterly Michigan pipeline through put in excess of 10,000 Mcf/d.

Starting on March 28, 2002, in western Texas, our revenues are generated primarily through the gathering of natural gas and the transportation of natural gas to the end user. On a pro forma basis, had we acquired the Pinnacle companies as of January 1, 2003, our revenues would have increased by approximately $17.8 million for the three months ended March 31, 2003. The Pinnacle acquisition provides additional customer diversification as all of the revenues generated are with third parties.

Our principal purchased product costs are the percentage of proceeds from the sale of NGL products that we remit to a third party in Appalachia and the third-party producers in Michigan. We also pay third-party producers in Texas a percentage of index for the gas we gather.

Our plant operating expenses, similar to the Midstream Business, principally consist of those expenses needed to operate our facilities, including applicable personnel costs, fuel, plant utility costs and maintenance expenses. One difference between our plant operating expenses and those of the MarkWest Hydrocarbon Midstream Business is fuel costs. MarkWest Hydrocarbon retains th e producer fuel reimbursement.

Our general and administrative expenses are dictated by the terms of the omnibus agreement between MarkWest Hydrocarbon and us. We reimburse MarkWest Hydrocarbon monthly for the general and administrative support it provided us in the prior month. In the first year of the agreement (ending May 23, 2003), this reimbursement will not exceed $4.9 million. This limitation excludes the cost of any third party legal, accounting or advisory services received, or the direct expenses of MarkWest Hydrocarbon and its affiliates incurred, in connection with business development opportunities evaluated on our behalf.

Pinnacle Acquisition

On March 28, 2003, we completed the acquisition of Pinnacle Natural Gas Company; Pinnacle Pipeline Company; PNG Transmission Company, Inc.; PNG Utility Company; and Bright Star Gathering, Inc. (collectively, the “Sellers”). The purchase price was comprised of $23.4 million paid in cash to the Sellers, plus the assumption of specified liabilities, including $16.6 million of bank indebtedness.

were allocated to the MarkWest Energy Partners 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 three lateral natural gas pipelines consist of approximately 67 miles of pipe and transport up to 1.1 Bcf/d under firm contracts to power plants. The twenty gathering systems gather more than 44 MMcf/d.

Operating Data

	Three Months Ended March 31, 2003 (Partnership)	Three Months Ended March 31, 2002 (MarkWest Hydrocarbon Midstream Business)
Appalachia:
Natural gas processed for a fee(1) (Mcf/d) under contracts in effect:
Beginning May 24, 2002	264,000	—
Prior to May 24, 2002	—	269,000
NGLs fractionated for a fee (gallons/day) under contracts in effect:
Beginning May 24, 2002	446,000	—
Prior to May 24, 2002	—	479,000
NGL product sales (gallons) under contracts in effect:
Beginning May 24, 2002	10,083,000	—
Prior to May 24, 2002	—	10,073,000
Michigan:
Natural gas processed for a fee (Mcf/d)	15,400	11,000
NGL product sales (gallons)	2,900,000	2,500,000

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

Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002

Revenues. Revenues were $17.7 million for the three months ended March 31, 2003, compared to $27.4 million for the three months ended March 31, 2002, a decrease of $9.7 million, or 36%. Revenues were lower in 2003 than in 2002 primarily due to the terms of the new contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of the IPO. You should read the Overview section appearing under “Results of Operations” earlier in this Form 10-Q for a detailed discussion of the financial statement line items differences between the Partnership and the Midstream Business.

Purchased Product Costs. Purchased product costs were $8.4 million for the three months ended March 31, 2003, compared to $19.7 million for the three months ended March 31, 2002, a decrease of $11.3 million, or 57%. Purchased product costs were lower in 2003 primarily due to the terms of new contracts entered into by MarkWest Hydrocarbon and us concurrent with the closing of our IPO. You should read the Overview section appearing under “Results of Operations” earlier in this Form 10-Q for a detailed discussion of the financial statement line items differences between the Partnership and the Midstream Business.

Plant Operating and Other Expenses. Plant operating and other expenses were $4.3 million for the three months ended March 31, 2003, compared to $3.8 million for the three months ended March 31, 2002, an increase of $0.6 million, or 15%. Plant operating and other expenses increased due to significantly higher fuel costs in 2003.

Selling, General and Administrative Expenses. Selling, general and administrative expenses were $1.3 million for the three months ended March 31, 2003, compared to $1.4 million for the three months ended March 31, 2002, a decrease of $0.1 million, or 8%.

Depreciation. Depreciation expense was $1.3 million for the three months ended March 31, 2003, compared to $1.2 million for the three months ended March 31, 2002, an increase of $0.1 million, or 12%.

Interest Expense. Interest expense was $0.8 million for the three months ended March 31, 2003, compared to $0.3 million for the three months ended March 31, 2002. Interest expense increased in 2003 as we expensed $0.4 in third party fees incurred with the March 28, 2003, amendment of our credit facility.

Income Taxes. The Partnership has not been subject to income taxes since its inception on May 24, 2002.

Seasonality

A portion of the Midstream Business’s revenues and, as a result, its gross margins, were dependent upon the sales prices of NGL products, particularly propane, which fluctuate with winter weather conditions, and other supply and demand determinants. The strongest demand for propane, which increases sales volumes, and the highest propane sales margins generally occur during the winter heating season. As a result, the Midstream Business recognized a substantial portion of its annual income during the first and fourth quarters of the year.

With respect to our percent-of-proceeds contracts, which account for approximately 15% of our gross margin (revenue less product purchases) prior to the acquisition of Pinnacle, we are also dependent upon the sales price of NGL products, particularly propane, which fluctuates with the winter weather conditions, and other supply and demand determinants.

Liquidity and Capital Resources

As has been the case since our IPO closed on May 24, 2002, we believe that cash generated from operations and funds available under our credit facility will be sufficient to meet both our short-term and long-term working capital requirements and anticipated capital expenditures. In addition, if needed, we have the ability to issue additional common units to raise capital. 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. If the Pinnacle acquisition had occurred on January 1, 2003, MarkWest Hydrocarbon would have accounted for approximately 38% of our revenues for the three months ended March 31, 2003. 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 capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives, are estimated to approximate $0.5 million, including Pinnacle, for the remainder of 2003. Additionally, our budget for Pinnacle pipeline connections and other system improvements for the remainder of 2003 is $2.3 million. Under certain circumstances, the party from which we acquired the Pinnacle assets has the right to require MarkWest Energy Partners to purchase an additional lateral pipeline for up to $2.5 million.

Cash Flows. Net cash provided by operating activities was $2.8 million for the three months ended March 31, 2003, compared to $19.8 million for the three months ended March 31, 2002, for the Midstream Business. Net cash provided by operating activities was lower in 2003 than in 2002 primarily due to the Midstream Business’s seasonal conversion of inventories to cash during 2002.

Net cash used in investing activities was $38.3 million for the three months ended March 31, 2003, compared to $0.4 million for the three months ended March 31, 2002, for the Midstream Business. The increase was

caused by the acquisition of the Pinnacle companies on March 28, 2003.

Net cash provided by financing activities was $36.1 million for the three months ended March 31, 2003. Net cash used in investing activities was $19.4 million for the three months ended March 31, 2002, for the Midstream Business. Net cash provided by financing activities for 2003 was caused by borrowings used to finance the Pinnacle acquisition. Financing activities through March 31, 2002, primarily represent repayments to MarkWest Hydrocarbon following the Midstream Business’s seasonal conversion of working capital to cash.

Outlook

Our Appalachian plants were shut down during April and early May 2003 for annual repair and maintenance. The shut down period varied by plant and lasted between a few days to two to three weeks. Consequently, our second quarter 2003 Appalachian throughput volumes will decrease relative to the first quarter of 2003. However, the resulting decrease in cash flow from Appalachian operations should be more than offset by cash flow from our Texas (Pinnacle) operations, which began contributing to our results March 28, 2003.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

As of March 31, 2003, approximately 15% 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. Our Maytown gas processing plant in Appalachia and our Michigan operations have percent-of-proceeds contracts. Under percent-of-proceeds contracts, we, as the processor, retain a portion of the sales price of the NGL products produced as compensation for our services. Additionally, we are subject to natural gas price risk as a result of our March 2003 Pinnacle acquisition. MarkWest Energy Partners gathers and transports natural gas for producers behind our gathering systems in Texas, many under percent-of-proceeds or percent-of-index contracts. Under these contracts MarkWest Energy Partners is entitled to approximately 10% of the natural gas produced.

Our primary risk management objective is to manage our price risk, thereby reducing 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 over-the-counter (OTC) market. New York Mercantile Exchange (NYMEX) traded futures are authorized for use. Swaps and futures allow us to protect our margins because corresponding losses or gains in the value of financial instruments are generally offset by gains or losses in the physical market.

We enter OTC swaps with counterparties that are primarily financial institutions. 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 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 may be similarly insulated against unfavorable changes in such prices.

We are also subject to basis risk. Basis risk 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. We have two different types of NGL product basis risk. First, NGL product basis risk stems from the geographic price differentials between our sales locations and hedging contract delivery locations. We cannot hedge our geographic

basis risk because there are no readily available products or markets. Second, 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 are generally unable to hedge our basis risk for NGL products.

We hedge our Appalachian and Michigan NGL product sales by selling forward propane or crude oil. As of March 31, 2003, we have hedged NGL product sales as follows:

	Year Ending December 31, 2003
NGL Volumes Hedged Using Crude Oil
NGL gallons	2,862,000
NGL sales price per gallon	$	0.46

NGL Volumes Hedged Using Propane
NGL gallons	1,008,000
NGL sales price per gallon	$	0.41

Total NGL Volumes Hedged
NGL gallons	3,870,000
NGL sales price per gallon	$	0.44

All projected margins or prices on open positions assume (a) the basis differentials between our sales location and the hedging contract’s specified location, and (b) the correlation between crude oil and NGL products, are consistent with historical averages.

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, 2003, no such hedges were in place. As of May 6, 2003, we had hedged our Texas natural gas price risk via swaps as follows:

	Year Ending December 31,
	2003		2004		2005

MMBtu	122,500		183,000		182,500
$/MMBtu	$	5.09	$	4.57	$	4.26

As of May 6, 2003, we had hedged our Texas natural gas price risk via puts as follows:

	Year Ending December 31,
	2003		2004		2005

MMBtu	245,000		366,000		—
Strike price ($/MMBtu)	$	4.50	$	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, 2003, 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

Based on their evaluation of the internal controls, disclosure controls and procedures within 90 days of the filing date of this report, the Chief Executive Officer and the Chief Financial Officer have concluded that the effectiveness of such controls and procedures is satisfactory. Further, there were not any significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

PART II. OTHER INFORMATION

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

99.1* Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.2* Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*Filed herewith.

(b) Reports on Form 8-K

A report on Form 8-K was filed on March 25, 2003, announcing that MarkWest Energy Partners, L.P. has entered into a Purchase and Sale Agreement with Energy Spectrum Partners, L.P., for the acquisition of Pinnacle Natural Gas Company and certain affiliates for approximately $38 million.

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 14, 2003	By:	/s/ Donald C. Heppermann

			Donald C. Heppermann
			Senior Executive Vice President,
			Chief Financial Officer and Secretary

CERTIFICATION

I, John M. Fox, certify that:

1. I have reviewed this quarterly report on Form 10-Q of MarkWest Energy Partners, L.P.

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report.

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report.

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared.

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”).

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date.

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls.

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls.

6. The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 14, 2003

							/s/ John M. Fox

							John M. Fox
							President and Chief Executive Officer

CERTIFICATION

I, Donald C. Heppermann, certify that:

1. I have reviewed this quarterly report on Form 10-Q of MarkWest Energy Partners, L.P.

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”).

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date.

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls.

Date: May 14, 2003

/s/ Donald C. Heppermann

Donald C. Heppermann

Senior Executive Vice President,

Chief Financial Officer, and Secretary