MARKWEST ENERGY PARTNERS L P - 10-Q Quarterly Report

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 September 30, 2003

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 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 by Rule 12b-2 of the Act).

Yes o No ý

The number of the registrant’s units outstanding at October 31, 2003, was 2,790,000 common units and 3,000,000 subordinated units.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements
			Condensed Consolidated Balance Sheets (Unaudited) at September 30, 2003 and December 31, 2002
			Condensed Consolidated Statements of Operations (Unaudited) for the Three Months Ended September 30, 2003 and 2002
			Condensed Consolidated and Combined Statements of Operations (Unaudited) for the Nine Months Ended September 30, 2003 and 2002
			Condensed Consolidated and Combined Statements of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2003 and 2002
			Condensed Consolidated Statement of Changes in Capital (Unaudited) for the Nine Months Ended September 30, 2003
			Notes to the Unaudited Condensed 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 2. Changes in Securities and Use of Proceeds
Item 6. Exhibits and Reports on Form 8-K

SIGNATURE

Glossary of Terms

Bcf/d		billion cubic feet of natural gas per day
Btu		British thermal units, an energy measurement
LIBOR		London Inter-Bank Offered Rate
Mcf		thousand cubic feet of natural gas
Mcf/d		thousand cubic feet of natural gas per day
NGLs		natural gas liquids, such as propane, butanes and natural gasoline

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

MARKWEST ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	September 30, 2003			December 31, 2002
	(in thousands)
ASSETS

Current assets:
Cash and cash equivalents	$	6,373		$	2,776
Receivables	6,364			976
Receivables from affiliate	2,247			2,847
Inventories	114			130
Other assets	135			336
Total current assets	15,233			7,065

Property, plant and equipment:
Gas gathering equipment	47,112			34,398
Gas processing plants	47,644			47,403
Pipelines	38,103			—
Fractionation and storage equipment	22,160			22,076
NGL transportation equipment	4,415			4,402
Land, building and other equipment	3,088			3,021
Construction in progress	685			348
	163,207			111,648
Less: Accumulated depreciation	(37,030		)	(31,824		)
Total property, plant and equipment, net	126,177			79,824

Deferred financing costs	880			820
Total assets	$	142,290		$	87,709

LIABILITIES AND CAPITAL

Current liabilities:
Accounts payable	$	8,489		$	1,199
Payables to affiliate	815			723
Accrued liabilities	3,786			2,880
Risk management liability	263			501
Total current liabilities	13,353			5,303

Long-term debt	61,300			21,400
Risk management liability	196			143

Capital:
Partners’ capital	67,912			61,574
Accumulated other comprehensive loss, net of tax	(471		)	(711		)
Total capital	67,441			60,863
Total liabilities and capital	$	142,290		$	87,709

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

MARKWEST ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended September 30,
	2003			2002
	(in thousands, except per unit amounts)

Revenues:
Sales to unaffiliated parties	$	18,888		$	3,096
Sales to affiliate	12,524			10,772
Total revenues	31,412			13,868

Operating expenses:
Purchased product costs	18,510			4,903
Facility expenses	5,396			3,893
Selling, general and administrative expenses	1,883			894
Depreciation	2,026			1,272
Total operating expenses	27,815			10,962

Income from operations	3,597			2,906

Other income (expenses):
Interest expense, net	(847		)	(392		)
Miscellaneous income	17			12

Income before income taxes	2,767			2,526

Provision for income taxes	—			—

Net income	$	2,767		$	2,526

General partner’s interest in net income	$	55		$	51
Limited partners’ interest in net income	$	2,712		$	2,475

Basic net income per limited partner unit	$	0.47		$	0.46
Diluted net income per limited partner unit	$	0.46		$	0.45

Weighted average units outstanding:
Basic	5,783			5,415
Diluted	5,833			5,449

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

MARKWEST ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Nine Months Ended September 30, 2003 (Partnership)			Period From Commencement of Operations (May 24, 2002) Through September 30, 2002 (Partnership)			Period From January 1, 2002 Through May 23, 2002 (MarkWest Hydrocarbon Midstream Business)
	(in thousands, except per unit amounts)
Revenues:
Sales to unaffiliated parties	$	42,741		$	4,081		$	37,043
Sales to affiliates	36,000			14,647			—
Total revenues	78,741			18,728			37,043

Operating expenses:
Purchased gas costs	45,325			6,436			26,598
Facility expenses	14,900			5,236			5,705
Selling, general and administrative expenses	4,814			1,423			2,206
Depreciation	5,231			1,787			1,916
Total operating expenses	70,270			14,882			36,425

Income from operations	8,471			3,846			618

Other income (expenses):
Interest expense, net	(2,592		)	(528		)	(461		)
Miscellaneous income	51			18			—

Income before income taxes	5,930			3,336			157

Provision (benefit) for income taxes:
Current due from parent	—			—			(1,535		)
Deferred	—			—			1,596
Provision for income taxes	—			—			61
Net income	$	5,930		$	3,336		$	96

General partner’s interest in net income	$	119		$	67
Limited partners’ interest in net income	$	5,811		$	3,269

Basic net income per limited partner unit	$	1.05		$	0.60
Diluted net income per limited partner unit	$	1.04		$	0.60

Weighted average units outstanding:
Basic	5,543			5,415
Diluted	5,593			5,449

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

MARKWEST ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine Months Ended September 30, 2003 (Partnership)			Period From Commencement of Operations (May 24, 2002) through September 30, 2002 (Partnership)			Period From January 1, 2002 through May 23, 2002 (MarkWest Hydrocarbon Midstream Business)
	(in thousands)
Cash flows from operating activities:
Net income	$	5,930		$	3,336		$	96
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	5,231			1,787			1,916
Amortization of deferred financing costs included in interest expense	702			—			—
Non-cash compensation expense	554			—			—
Deferred income taxes	—			—			1,596
Other	20			68			(252		)
Changes in operating assets and liabilities:
(Increase) decrease in receivables	3,369			(4,801		)	3,765
(Increase) decrease in inventories	16			(100		)	2,449
(Increase) decrease in prepaid replacement natural gas and other assets	285			(73		)	5,253
Increase in accounts payable and accrued liabilities	333			3,241			7,770
Increase in long-term replacement natural gas payable	—			—			3,090
Net cash flow provided by operating activities	16,440			3,458			25,683

Cash flows from investing activities:
Pinnacle acquisition, net of cash acquired	(38,238		)	—			—
Lubbock pipeline acquisition	(12,222		)	—			—
Capital expenditures	(1,934		)	(1,407		)	(498		)
Proceeds from sale of assets	3			18			—
Net cash used in investing activities	(52,391		)	(1,389		)	(498		)

Cash flows from financing activities:
Proceeds from initial public offering, net of transaction costs	—			43,662			—
Proceeds from private placement of common units, net of transaction costs	9,764			—			—
Proceeds from long-term debt	67,600			23,400			—
Repayment of long-term debt	(27,700		)	(2,000		)	—
Distributions to unitholders	(9,557		)	(1,160		)	—
Capital contribution from general partner	201			—			—
Net distributions to parent	—			—			(24,218		)
Debt due from parent	—			—			(967		)
Payments for debt issuance costs	(760		)	(1,077		)	—
Distribution to MarkWest Hydrocarbon	—			(63,476		)	—
Net cash provided by (used in) financing activities	39,548			(651		)	(25,185		)
Net increase in cash	3,597			1,418			—
Cash and cash equivalents at beginning of period	2,776			—			—
Cash and cash equivalents at end of period	$	6,373		$	1,418		$	—

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

MARKWEST ENERGY PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN CAPITAL

(UNAUDITED)

	PARTNERS’ CAPITAL											Accumulated Other Comprehensive Income (Loss)

	Limited Partners								General Partner
	Common				Subordinated
	Units	$			Units	$			$			$			Total
	(in thousands)

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

Private placement of common units, net of transaction costs	375	9,764			—	—			201			—			9,965

Distributions to partners	—	(4,275		)	—	(5,040		)	(242		)	—			(9,557		)

Net income	—	2,689			—	3,122			119			—			5,930

Change in fair value of derivatives	—	—			—	—			—			240			240

Balance at September 30, 2003	2,790	$	52,036		3,000	$	15,439		$	437		$	(471	)	$	67,441

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

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

1. Organization

MarkWest Energy Partners, L.P., a Delaware limited partnership (the “Partnership”, “we” or “us”), 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”). Through its majority ownership of our general partner, MarkWest Energy GP, L.L.C., MarkWest Hydrocarbon controls and conducts our operations. We are engaged in the business of gathering, processing and transporting natural gas and the transportation, fractionation and storage of NGL products. We are not a taxable entity because of our partnership structure.

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. For periods prior to May 24, 2002, the closing date of our initial public offering, the financial statements reflect historical cost-basis accounts of the Midstream Business. 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. The year-end consolidated balance sheet data was derived from audited financial statements. Preparation of 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 and nine months ended September 30, 2003, are not necessarily indicative of results for the full year 2003 or any other future period.

3. 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, 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 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	8,150
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 comparable periods presented, as though the Pinnacle Acquisition had occurred on January 1, 2002. These unaudited pro forma results have been prepared for comparative purposes only and may not be indicative of future results.

	Nine Months Ended September 30, 2003		Period From Commencement of Operations (May 24, 2002) Through September 30, 2002 (Partnership)		Period From January 1, 2002 Through May 23, 2002 (MarkWest Hydrocarbon Midstream Business)
	(in thousands, except per unit data)

Revenue	$	96,528	$	34,275	$	51,586
Net income	$	6,645	$	3,125	$	2
Basic net income per limited partner unit(1)	$	1.17	$	0.57	N/A
Diluted net income per limited partner unit(1)	$	1.16	$	0.56	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 a available.

4. Lubbock Pipeline Acquisition

On September 2, 2003, the Partnership, through its wholly owned subsidiary, MarkWest Pinnacle L.P., completed the acquisition (the “Lubbock Pipeline Acquisition”) of a 68-mile intrastate gas transmission pipeline near Lubbock, Texas from a subsidiary of ConocoPhillips for approximately $12.2 million. The transaction was financed through borrowings under our existing credit facility. The acquisition was accounted for as a purchase business combination. The pro forma results of operations of the Lubbock Pipeline Acquisition have not been presented as they are not significant.

5. Private Placement

The Partnership sold 375,000 common units in two installments at a price of $26.23 per unit in a private placement to certain accredited investors. The first installment of 300,031 units was completed on June 27, 2003, and grossed approximately $7.9 million. The second installment of 74,969 units was completed on July 10, 2003, and grossed approximately $1.9 million. Transaction costs for both installments were less than $0.1 million. The Partnership’s general partner paid its pro rata contribution in July 2003 after the second installment was completed. We used the net proceeds from both installments to pay down debt under our credit facility.

6. Distribution to Unitholders

On August 14, 2003, we paid our cash distribution of $0.58 per common and subordinated unit for the quarterly period ended June 30, 2003. The distribution was declared on July 11, 2003, payable to unitholders of record as of August 4, 2003.

On October 22, 2003, we declared our cash distribution of $0.64 per common and subordinated unit for the quarterly period ended September 30, 2003. The distribution will be paid on November 14, 2003, to unitholders of record as of November 4, 2003.

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, by the weighted average number of outstanding common units and subordinated units. 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, increased to include the dilutive effect of outstanding restricted units.

8. 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 who perform services for us receive 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 our common units on the last trading day of the corresponding quarter and is amortized into earnings over the period of service. For the nine months ended September 30, 2003, we recognized $0.6 million of compensation expense for the variable plan. 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:

	Three Months Ended September 30, 2003			Three Months Ended September 30, 2002
	(in thousands, except per unit data)
Net income as reported	$	2,767		$	2,526
Add: Compensation expenses included in reported net income	116			—
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(163		)	(47		)
Pro forma net income	$	2,720		$	2,479

Net income per limited partner unit: (1)
Basic—as reported	$	0.47		$	0.46
Basic—pro forma	$	0.46		$	0.45
Diluted—as reported	$	0.47		$	0.46
Diluted—pro forma	$	0.46		$	0.45

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

	Nine Months Ended September 30, 2003 (Partnership)			Period From Commencement of Operation (May 24, 2002) Through September 30, 2002 (Partnership)			Period from January 1, 2002 Through May 23, 2002 (MarkWest Hydrocarbon Midstream Business)
	(in thousands, except per unit data)
Net income, as reported	$	5,930		$	3,336		$	96
Add: Compensation expense included in reported net income	554			—			—
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(693		)	(66		)	(72		)
Pro forma net income	$	5,791		$	3,270		$	24

Net income per limited partner unit: (1)
Basic—as reported	$	1.05		$	0.60		N/A
Basic—pro forma	$	1.02		$	0.59		N/A
Diluted—as reported	$	1.04		$	0.60		N/A
Diluted—pro forma	$	1.01		$	0.59		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.

8. 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.

9. Recent Accounting Pronouncements

In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150 (“SFAS No. 150”), “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” This statement establishes standards for the measurement and classification of certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise effective the first interim period beginning after June 15, 2003. The adoption of this standard did not have any impact on the Partnership’s financial position or results of operations.

In April 2003, the FASB issued Statement of Financial Accounting Standards No. 149 (“SFAS No. 149”), “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under Statement of Financial Accounting Standards No. 133

(“SFAS No. 133”), “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003 and should be applied prospectively. However, provisions related to SFAS No. 133 Implementation Issues effective for fiscal quarters beginning prior to June 15, 2003 should continue to be applied in accordance with their respective dates. The adoption of this standard did not have any impact on the Partnership’s financial position or results of operations.

10. Subsequent Event

On November 7, 2003, MarkWest Energy Partners entered into a Purchase and Sale Agreement with Shell Pipeline Company LP and other Shell subsidiaries, for the acquisition of Shell’s Michigan Crude Gathering Pipeline assets for approximately $21 million. The acquisition will be financed utilizing our existing credit facility, which we anticipate expanding in conjunction with this acquisition.

The crude gathering assets, located in northern Michigan, are comprised of approximately 250 miles of pipelines, 4 truck unloading stations, associated terminals and tank facilities. The system is a common carrier Michigan intrastate pipeline and gathers approximately 16,000 barrels per day of light crude oil from wells throughout Michigan. The oil is transported for a fee to the Lewiston station where it is batch injected into the Enbridge Lakehead Pipeline, which then transports the oil to refineries in Sarnia Ontario, Canada. The pipeline provides the producers in Michigan an alternative to trucking the crude to the Sarnia refinery complex.

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 of Financial Condition and Results of Operations 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.

• 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 effectiveness of any hedging activities, and indirectly, 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 the Pinnacle Acquisition and the Lubbock Pipeline 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 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. We also have a growing base of gas gathering and intrastate gas transmission assets in the southwestern United States (the “Southwest”), primarily in 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 our initial public offering 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. 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 compared to the way in which the MarkWest Hydrocarbon Midstream Business generated revenues. Historically, the Midstream Business primarily generated its revenues pursuant to:

• 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 processing operations, sell the NGLs to third parties, and pay the producer a specified percentage of the proceeds received from the sales.

• Fee-based contracts under which the Midstream Business received a fee in exchange for services—transportation, processing, or fractionation—that it provided.

Currently, however, none of our revenues are generated pursuant to keep-whole contracts. Rather, we generate the majority of our revenues pursuant to:

• Percent-of-index and percent-of-proceeds contracts that were acquired in connection with the Pinnacle Acquisition, under which we retain a percentage of the index or proceeds from the sale of natural gas and NGLs we transport as compensation for our services.

• We also generate revenues in the Southwest from contracts pursuant to which (a) we receive a flat monthly fee in exchange for delivering natural gas to end users or (b) we receive a throughput fee for transporting a customer’s natural gas.

• 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 processing, fractionation and other services that we provide in Appalachia.

• Percent-of-proceeds contracts, which we assumed from MarkWest Hydrocarbon at the completion of our IPO, under which we retain a percentage of the NGLs that we produce in Appalachia and Michigan as compensation for processing the raw gas for producers.

• Fee-based contracts under which we receive a fee in exchange for services—transportation, processing, or fractionation—that we provide.

The largest of the differences between the financial statements of the Midstream Business and our financial statements is in revenues and purchased product costs. 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 natural gas and NGL sales we receive under our percent-of-proceeds and percent-of-index contracts.

• Our purchased product costs primarily consists of the percentage of proceeds from the sale of natural gas and NGL products remitted to producers under our percent-of-proceeds and percent- of-index 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 and percent-of-index contracts, the market price of natural gas and NGL products. Because of these significant differences, the “Results 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 fractionation 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 facility 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, insurance and other corporate services.

MarkWest Energy Partners, L.P.

We generate the majority of our revenues from natural gas gathering, processing and transportation and NGL transportation, fractionation and storage in three primary geographic areas: the Southwest, Appalachia, and Michigan.

With the completion of the Pinnacle Acquisition on March 28, 2003, and the Lubbock Pipeline Acquisition on September 2, 2003, our Southwest revenues are primarily generated by providing natural gas gathering and

transportation services in areas located in Texas, New Mexico, Louisiana and Mississippi. Our two recent acquisitions provide us with additional customer diversification as all of the revenues generated from the acquired assets are with third parties. For the three months ended September 30, 2003 (which includes only four weeks of the Lubbock Pipeline Acquisition’s results), our two recent acquisitions collectively generated 49% of our revenues.

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. 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 throughput in excess of 10,000 Mcf/d.

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 the Southwest a percentage of index or a percentage of proceeds 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 the producer fuel reimbursement.

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 (ended May 23, 2003), this reimbursement did not exceed $4.9 million. This limitation excluded 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

We completed the Pinnacle Acquisition on March 28, 2003. 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 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 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 acquired gathering systems gather more than 44 MMcf/d.

Lubbock Pipeline Acquisition

On September 2, 2003, through our wholly owned subsidiary, MarkWest Pinnacle L.P., we completed the acquisition of a 68-mile intrastate gas transmission pipeline near Lubbock, Texas from a subsidiary of ConocoPhillips for approximately $12.2 million. The transaction was financed through borrowings under our existing credit facility.

Three Months Ended September 30, 2003 Compared to Three Months Ended September 30, 2002

Operating Data

	Three Months Ended September 30, 2003	Three Months Ended September 30, 2002
Appalachia:
Natural gas processed for a fee(1) (Mcf/d)	204,000	213,000
NGLs fractionated for a fee (gallons/day)	511,000	484,000
NGL product sales (gallons)	10,771,000	9,840,000
Southwest(2)^:
Pipeline throughput (Mcf/d)	59,000	—
Michigan:
Natural gas processed for a fee (Mcf/d)	17,300	16,900
NGL product sales (gallons)	3,982,000	3,212,000

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

(2) Our Southwest assets are located primarily in Texas and four surrounding states and were acquired March 28, 2003, and September 2, 2003.

Revenues. Revenues were $31.4 million for the three months ended September 30, 2003, compared to $13.8 million for the three months ended September 30, 2002, an increase of $17.5 million, or 127%. Revenues were higher in 2003 than in 2002 primarily due to the Pinnacle Acquisition and the Lubbock Pipeline Acquisition, which collectively added $15.3 million in revenues. Additionally, a $0.12 per gallon price increase and a 900,000-gallon volume increase in Appalachian NGL product sales collectively increased revenues $1.7 million. A $0.15 per gallon NGL product sales price increase in Michigan increased revenues $0.5 million.

Purchased Product Costs. Purchased product costs were $18.5 million for the three months ended September 30, 2003, compared to $4.9 million for the three months ended September 30, 2002, an increase of $13.6 million, or 278%. Purchased product costs were higher in 2003 than in 2002 primarily due to the Pinnacle Acquisition, which added $12.1 million in purchased product costs. Additionally, a $0.10 per gallon price increase and a 900,000-gallon volume increase in Appalachian NGL product sales collectively increased purchased product costs $1.5 million.

Facility Expenses. Facility expenses were $5.4 million for the three months ended September 30, 2003, compared to $3.9 million for the three months ended September 30, 2002, an increase of $1.5 million, or 39%. Facility expenses increased $0.9 million due to the Pinnacle Acquisition and the Lubbock Pipeline Acquisition. The remainder of the increase is primarily attributable to higher fuel and repair costs in Appalachia.

Selling, General and Administrative Expenses. Selling, general and administrative expenses (“SG&A”) were $1.9 million for the three months ended September 30, 2003, compared to $0.9 million for the three months ended September 30, 2002, an increase of $1.0 million, or 110%. SG&A increased $0.3 million due to the Pinnacle Acquisition. Additionally, reimbursable SG&A expenses were capped under our omnibus agreement with MarkWest Hydrocarbon at $4.9 million annually during the first year after our May 2002 initial pubic offering. No such cap existed during the third quarter in 2003.

Depreciation. Depreciation expense was $2.0 million for the three months ended September 30, 2003, compared to $1.3 million for the three months ended September 30, 2002, an increase of $0.8 million, or 59%. The increase is principally due to the Pinnacle Acquisition.

Interest Expense. Interest expense was $0.8 million for the three months ended September 30, 2003, compared to $0.4 million for the three months ended September 30, 2002, an increase of $0.5 million, or 116%. The increase in interest expense is primarily a result of the additional debt used to finance the Pinnacle Acquisition and, to a lesser extent, the Lubbock Pipeline Acquisition.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September 30, 2002

Operating Data

	Nine Months Ended September 30, 2003 (Partnership)	Period From Commencement of Operations (May 24, 2002) Through September 30, 2002 (Partnership)	Period From January 1, 2002 Through May 23, 2002 (MarkWest Hydrocarbon Midstream Business)
Appalachia:
Natural gas processed for a fee(1) (Mcf/d) under contracts in effect:
Beginning May 24, 2002	198,000	219,000	—
Prior to May 24, 2002	—	—	195,000
NGLs fractionated for a fee (gallons/day) under contracts in effect:
Beginning May 24, 2002	449,000	474,000	—
Prior to May 24, 2002	—	—	462,000
NGL product sales (gallons) under contracts in effect:
Beginning May 24, 2002	29,142,000	13,391,000	—
Prior to May 24, 2002	—	—	75,821,000
Southwest(2):
Pipeline throughput (Mcf/d)	51,000	—	—
Michigan:
Natural gas processed for a fee (Mcf/d)	15,700	15,900	11,900
NGL product sales (gallons)	9,112,000	4,334,000	3,747,000

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

(2) Represents throughput since March 28, 2003. Our Southwest assets are located primarily in Texas and four surrounding states and were acquired March 28, 2003, and September 2, 2003.

Revenues. Revenues were $78.7 million for the nine months ended September 30, 2003, compared to our combined revenues of $55.8 million for the nine months ended September 30, 2002, an increase of $23.0 million, or 41%. Revenues were higher in 2003 than in 2002 primarily due to the Pinnacle Acquisition and, to a lesser extent, the Lubbock Pipeline Acquisition, which collectively added $32.8 million in revenues. The acquisition-related revenue additions were partially offset by the impact of contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of our initial public offering. 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 item differences between the Partnership and the Midstream Business.

Purchased Product Costs. Purchased product costs were $45.3 million for the nine months ended September 30, 2003, compared to our combined purchased product costs of $33.0 million for the nine months ended September 30, 2002, an increase of $12.3 million, or 37%. Purchased product costs were higher in 2003 than in 2002 primarily due to the Pinnacle Acquisition, which increased purchased product costs $26.7 million. The Pinnacle Acquisition impact was partially offset by the effect of new contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of our initial public offering.

Facility Expenses. Facility expenses were $14.9 million for the nine months ended September 30, 2003, compared to our combined facility expenses of $10.9 million for the nine months ended September 30, 2002, an increase of $4.0 million, or 36%. The Pinnacle Acquisition and the Lubbock Pipeline Acquisition collectively increased facility expenses by $1.9 million. The remainder of the increase is principally attributable to higher fuel and repair costs in Appalachia and increased throughput in Michigan.

Selling, General and Administrative Expenses. Selling, general and administrative expenses were $4.8 million for the nine months ended September 30, 2003, compared to our combined selling, general and administrative expenses of $3.6 million for the nine months ended September 30, 2002, an increase of $1.2 million, or 33%. SG&A expenses increased principally due to the Pinnacle Acquisition and non-cash compensation expense related to employee grants of restricted units.

Depreciation. Depreciation expense was $5.2 million for the nine months ended September 30, 2003, compared to $3.7 million for the nine months ended September 30, 2002, an increase of $1.5 million, or 41%. Depreciation expense increased primarily due to the Pinnacle Acquisition.

Interest Expense. Interest expense was $2.6 million for the nine months ended September 30, 2003, compared to $1.0 million for the nine months ended September 30, 2002, an increase of $1.6 million, or 162%. Interest expense increased due to additional debt used for the financing of the Pinnacle Acquisition and the Lubbock Pipeline Acquisition.

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 and percent-of-index contracts, which account for approximately 62% of our revenues for the nine months ended September 30, 2003, we are dependent upon the sales prices of natural gas and NGL products, particularly propane, which fluctuates with the winter weather conditions, and other supply and demand determinants.

Liquidity and Capital Resources

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. Over a two-week period ended July 10, 2003, we issued an additional 375,000 common units in a private placement to accredited investors raising approximately $9.7 million after transaction costs. The $12.2 million Lubbock Pipeline Acquisition closed September 2, 2003, and was financed through borrowings under our credit facility. Our ability to fund additional acquisitions will likely require the issuance of additional common units, the expansion of our credit facility, the issuance of additional debt instruments or a combination thereof.

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. For the three and nine months ended September 30, 2003, MarkWest Hydrocarbon accounted for 40% and 45%, respectively, of our revenues. 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. For a full discussion of matters affecting MarkWest Hydrocarbon, you should read MarkWest Hydrocarbon’s most recent Forms 10-Q and Form 10-K.

Sustaining capital expenditures, which are capital expenditures to maintain the existing operating capacity of our assets and to extend their useful lives, are estimated to approximate $0.1 million for the remainder of 2003. Additionally, our budget for pipeline connections and other system improvements related to the Pinnacle Acquisition for the remainder of 2003 is $0.5 million. Under certain circumstances, the party from which we acquired the

Pinnacle companies has the right to require the Partnership to purchase an additional lateral pipeline for up to $2.5 million.

Cash Flows. Net cash provided by operating activities was $16.4 million for the nine months ended September 30, 2003, compared to our combined cash flow of $29.1 million for the nine months ended September 30, 2002. The difference in net cash provided by operating activities is attributable to the inherent differences in the businesses and contracts of the Partnership and the Midstream Business. You should read the Overview section appearing under “Results of Operations” earlier in this Form 10-Q for a detailed discussion of the differences between the Partnership and the Midstream Business.

Net cash used in investing activities was $52.4 million for the nine months ended September 30, 2003, compared to our combined net cash used of $1.9 million for the nine months ended September 30, 2002. The Pinnacle Acquisition and the Lubbock Pipeline Acquisition primarily caused the increase.

Net cash provided by financing activities was $39.5 million for the nine months ended September 30, 2003. Our combined net cash used in investing activities was $25.8 million for the nine months ended September 30, 2002. Net cash provided by financing activities for 2003 was caused by borrowings used to finance the Pinnacle Acquisition and the Lubbock Pipeline Acquisition and proceeds from the private placement of common units.

Retirement of President and Chief Executive Officer and Appointment of Successor

The Boards of Directors of MarkWest Hydrocarbon, Inc. and our general partner announced on October 23, 2003, that John M. Fox, the current Chairman, President and Chief Executive Officer of MarkWest Hydrocarbon and our general partner, has advised them he will retire as Chief Executive Officer effective December 31, 2003. As part of the management transition, the Boards also announced the resignation of Mr. Fox as President effective November 1, 2003, and the appointment of Frank M. Semple as President as of such date. To facilitate an orderly transition, Mr. Fox will continue in his role as Chief Executive Officer during the remainder of the calendar year, after which time Mr. Semple will also assume the position of Chief Executive Officer.

Mr. Fox will remain a Director and Chairman of the Board of both MarkWest Hydrocarbon and our general partner. Mr. Fox founded MarkWest Hydrocarbon and has served as its President, Chief Executive Officer and Chairman of the Board since its inception in April 1988. Mr. Fox has served in the same capacities for our general partner since May 2002.

Prior to accepting his appointment to MarkWest, Mr. Semple served as Chief Operating Officer of WilTel Communications, formerly Williams Communications, a $1.5 billion revenue, 2,500-employee telecommunications company based in Tulsa, Oklahoma. Preceding that, he held the position of Senior Vice President/General Manager of Williams Natural Gas from 1995 to 1997 as well as Vice President of Marketing and Vice President of Operations and Engineering for Northwest Pipeline and Director of Product Movements and Division Manager for Williams Pipeline during his 22-year career with the Williams Companies. During his tenure at Williams Communications, he served on the board of directors for PowerTel Communications and the Competitive Telecommunications Association. He currently serves on the board of directors for the Tulsa Zoo and Children’s Medical Center. Mr. Semple holds a bachelor’s degree in mechanical engineering from the United States Naval Academy. He also successfully completed the Program for Management Development at Harvard University.

Shell Crude Pipeline Purchase and Sale Agreement

On November 7, 2003, MarkWest Energy Partners announced it had entered into a Purchase and Sale Agreement with Shell Pipeline Company LP and other Shell subsidiaries, for the acquisition of Shell’s Michigan Crude Gathering Pipeline assets for approximately $21 million. The acquisition will be financed utilizing our existing credit facility, which we anticipate expanding in conjunction with this acquisition.

Michigan intrastate pipeline and gathers approximately 16,000 barrels per day of light crude oil from wells throughout Michigan. The oil is transported for a fee to the Lewiston station where it is batch injected into the Enbridge Lakehead Pipeline, which then transports the oil to refineries in Sarnia Ontario, Canada. The pipeline provides the producers in Michigan an alternative to trucking the crude to the Sarnia refinery complex.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

For the nine months ended September 30, 2003, approximately 62% of our revenues were directly subject to NGL product price or natural gas 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 the Pinnacle Acquisition. The Partnership gathers and transports natural gas for producers behind our gathering systems in the Southwest, many under percent-of-proceeds or percent-of-index contracts. Under these contracts the Partnership 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 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 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, crude oil or natural gas 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. It is generally not cost effective 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 September 30, 2003, we have hedged NGL product sales as follows:

	Year Ending December 31, 2003
Butanes and Natural Gasoline Volumes Hedged Using Crude Oil
NGL gallons	869,000
NGL sales price per gallon	$	0.50

Propane Volumes Hedged Using Propane
NGL gallons	315,000
NGL sales price per gallon	$	0.41

Total NGL Volumes Hedged
NGL gallons	1,184,000
NGL sales price per gallon	$	0.48

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 the Southwest by entering into fixed-for-float swaps or by purchasing puts. As of September 30, 2003, we had hedged our Southwest natural gas price risk via swaps as follows:

	Year Ending December 31,
	2003		2004		2005

MMBtu	46,000		183,000		182,500
$ /MMBtu	$	5.09	$	4.57	$	4.26

As of September 30, 2003, we had hedged our Southwest natural gas price risk via puts as follows:

	Year Ending December 31,
	2003		2004		2005

MMBtu	92,000		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 September 30, 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

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 principal executive and principal financial officers (who we refer to in this periodic report as our Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. Our management evaluated, with the participation of our Certifying Officers, the effectiveness of our disclosure controls and procedures as of September 30, 2003, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, our Certifying Officers concluded that as of September 30, 2003, our disclosure controls and procedures were effective.

There were no changes in our internal control over financial reporting that occurred during our most recently completed fiscal quarter that have materially affected, or are reasonably like to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 2. Changes in Securities and Use of Proceeds

(a) N/A

(b) N/A

(c) On July 10, 2003, the Partnership completed a non-underwritten private placement transaction in which it sold only to accredited investors an aggregate of 375,000 common units at an aggregate offering price of $9,836,250. The common units were sold in transactions not involving any public offering within the meaning of Section 4(2) of the Securities Act of 1933, as amended, pursuant to Rule 506 of Regulation D promulgated under the Securities Act. The Partnership filed a Form D with the Securities and Exchange Commission with respect to the transactions on or about July 2, 2003.

(d) N/A

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

2.1 Purchase and Sale Agreement dated as of July 31, 2003, among Raptor Natural Plains Marketing LLC, Raptor Gas Transmission LLC, Power-Tex Joint Venture and MarkWest Pinnacle L.P. (incorporated by reference to Exhibit 2.1 to the Partnership’s current report on Form 8-K filed with the SEC on September 17, 2003)

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

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

32.1 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.

32.2 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.

(b) Reports on Form 8-K

A current report on Form 8-K was filed with the SEC under item 5 of Form 8-K on August 4, 2003, announcing the Partnership, through its subsidiary, MarkWest Pinnacle L.P., had entered into a Purchase and Sale Agreement with Power-Tex Joint Venture, a subsidiary of ConocoPhillips, to acquire an intrastate gas transmission pipeline near Lubbock, Texas, for approximately $12 million.

A current report on Form 8-K was furnished with the SEC under items 7 and 12 of Form 8-K on August 13, 2003, concerning the Partnership’s second quarter 2003 earnings release dated August 13, 2003.

An amended current report on Form 8-K/A was filed with the SEC under items 2 and 7 of Form 8-K on August 26, 2003, announcing that MarkWest Energy Partners, L.P. completed its acquisition of Pinnacle Natural Gas Company and certain affiliates on March 28, 2003. The amended report included the audited financial statements of PNG Corporation and Subsidiaries.

A current report on Form 8-K was filed with the SEC under items 2 and 7 of Form 8-K on September 17, 2003, announcing the Partnership, through its subsidiary, MarkWest Pinnacle L.P., completed its acquisition of an intrastate gas transmission pipeline near Lubbock, Texas, from Power-Tex Joint Venture, a subsidiary of ConocoPhillips, for approximately $12 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:	November 13, 2003	By:		/s/ Donald C. Heppermann

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

EXHIBIT INDEX

Exhibit No.		Exhibit Description

2.1		Purchase and Sale Agreement dated as of July 31, 2003, among Raptor Natural Plains Marketing LLC, Raptor Gas Transmission LLC, Power-Tex Joint Venture and MarkWest Pinnacle L.P. (incorporated by reference to Exhibit 2.1 to the Partnership’s current report on Form 8-K filed with the SEC on September 17, 2003)
31.1		Chief Executive Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act
31.2		Chief Financial Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act
32.1		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.
32.2		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.