Markwest Energy Partners L P 10K/A 2002 Annual report (amended)

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TABLE OF CONTENTS
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K/A
(Amendment No. 1)

ý	Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2002.
o	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from to .

Commission File Number 001-31239

MARKWEST ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)		27-0005456 (I.R.S. 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

Securities registered pursuant to Section 12(b) of the Act:Common Units, $0.01 par value, American Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:None

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 126-2 of the Act). Yes o No ý

The aggregate market value of Common Units held by non-affiliates of the registrant on June 30, 2002 was approximately $51,269,438.

The number of the registrant's Common Units as of February 28, 2003, was 2,384,625.

DOCUMENTS INCORPORATED BY REFERENCE

None.

MarkWest Energy Partners, L.P.
Form 10-K/A
Table of Contents


PART II
	Item 6. Selected Financial Data
	Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
	Item 8. Financial Statements and Supplementary Data
PART III
	Item 14. Controls and Procedures
PART IV
	Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
SIGNATURES

Explanatory Note

This Amendment No. 1 on Form 10-K/A (this "Amendment") amends the Annual Report on Form 10-K originally filed by MarkWest Energy Partners, L.P. (the "Partnership") on March 28, 2003 for the fiscal year ended December 31, 2002 (the "Original Annual Report"). The Partnership has filed this Amendment to:

•: Present our statements of operations and of cash flows for the year ended December 31, 2002 on a combined basis. Previously, the Partnership reported two separate statements of operations and of cash flows for the year ended December 31, 2002. One statement of operations and one statement of cash flows were presented for the period from January 1, 2002 through May 23, 2002 for the MarkWest Hydrocarbon Midstream Business prior to its conveyance to the Partnership on May 24, 2002. Another statement of operations and a statement of cash flows were presented for the period from May 24, 2002 through December 31, 2002. The conveyance of the MarkWest Hydrocarbon Midstream Business from MarkWest Hydrocarbon to the Partnership represented a reorganization of entities under common control and was recorded at historical cost. Consequently, the Partnership has now determined that it should have combined these statements and presented them for the full year ended December 31, 2002.
•: Restate net income per limited partner unit to report such amount for the year ended December 31, 2002, and report net income per limited partner unit for the years ended December 31, 2001 and 2000. The Partnership had previously only reported net income per limited partner unit for the period from May 24, 2002 through December 31, 2002. In its restated financial statements, the Partnership has restated net income per limited partner unit to report such amount for the year ended December 31, 2002.
•: Report the elimination of the deferred tax liability resulting from our conversion to partnership form in our statement of operations for the year ended December 31, 2002. Previously, the elimination of the deferred tax liability resulting from our conversion to partnership form had been credited to the partners' capital portion of the Partnership's balance sheet without impacting our statement of operations. In our revised presentation, the elimination of the deferred tax liability is reflected in the statement of operations as a part of the provision (benefit) for income taxes, increasing net income by $17.2 million and ultimately reflected in the partners' capital portion of the balance sheet. Accordingly, the adjustment results in no net change to the balance sheet of the Partnership.

The effects of the above described financial statement restatements are discussed in Note 15 to the Partnership's Consolidated and Combined Financial Statements included herein and have been reflected in Item 6. Selected Financial Data, Item 7. Management's Discussion and Analysis and in quarterly financial information included herein.

The information contained in the Original Annual Report, as amended by this Amendment, has not been updated to reflect events and circumstances occurring since its original filing. Such matters have been or will be addressed in reports filed with the Securities and Exchange Commission (other than this Amendment) subsequent to the date of the Original Annual Report. Pursuant to Rule 12b-15 under the Securities Exchange Act of 1934, as amended, the Partnership has restated in its entirety each item of its Original Annual Report affected by this Amendment.

PART II

ITEM 6. SELECTED FINANCIAL DATA

On May 24, 2002, the Partnership completed its initial public offering, the proceeds of which were used by the Partnership to acquire and become the successor to the MarkWest Hydrocarbon Midstream Business (Midstream Business). The selected financial information for the Partnership is derived from the audited consolidated and combined financial statements as of and for the year ended December 31, 2002. The selected historical financial statements of the Midstream Business as of and for the years ended December 31, 2001, 2000, and 1999 are derived from the audited financial statements of the Midstream Business. The selected historical financial statements of the Midstream Business as of and for the year ended December 31, 1998, are derived from the unaudited financial statements of the Midstream Business and, in our opinion, include all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of this information. The selected financial data should be read in conjunction with the combined and consolidated financial statements, including the notes thereto, and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations."

				Partnership			MarkWest Hydrocarbon Midstream Business
				Year Ended December 31,
				2002(4)			2001			2000			1999			1998
				(in thousands, except per unit and operating data)
Statement of Operations:
Revenues(1)				$	70,246		$	93,675		$	109,810		$	57,490		$	42,676
Operating Expenses:
	Purchased product costs(1)				38,906			65,483			71,341			33,549			26,260
	Plant operating expenses				15,101			13,138			13,224			10,514			8,918
	Selling, general and administrative expenses				5,283			5,047			4,733			3,971			3,094
	Depreciation				4,980			4,490			4,341			3,413			2,958

		Total operating expenses			64,270			88,158			93,639			51,447			41,230

		Income from operations			5,976			5,517			16,171			6,043			1,446
Other income/expenses:
	Interest expense				(1,414	)		(1,307	)		(1,697	)		(1,741	)		(824	)
	Miscellaneous income				52			—			—			—			—

Income before income taxes				$	4,614		$	4,210		$	14,474		$	4,302		$	622
	Provision for income taxes				61			1,624			5,693			1,631			235

Net income				$	4,553		$	2,586		$	8,781		$	2,671		$	387

Basic net income per limited partner unit				$	4.86		$	—		$	—		$	—		$	—
Distributions declared and paid				$	3,923		$	—		$	—		$	—		$	—
Balance Sheet Data (at period end):
Working capital				$	1,762		$	18,240		$	6,047		$	4,083		$	1,914
Property, plant and equipment, net				$	79,824		$	82,008		$	77,501		$	69,695		$	62,564
Total assets				$	87,709		$	104,891		$	95,520		$	80,776		$	69,540
Long-term debt				$	21,400		$	19,179		$	20,782		$	17,956		$	22,875
Net parent investment/partnership equity				$	60,863		$	65,429		$	50,751		$	46,646		$	35,288
Other Financial Data:
Sustaining capital expenditures				$	511		$	576		$	955		$	489		$	415
Expansion capital expenditures					1,634			9,075			11,192			10,055			9,048

			Total capital expenditures	$	2,145		$	9,651		$	12,147		$	10,544		$	9,463
Operating Data:
Appalachia:
			Natural gas processed for a fee (Mcf/d)(2)		202,000			192,000			196,000			171,000			170,000
			NGLs fractionated for a fee (gallons/day)(3)		476,000			423,000			406,000			310,000			282,000
Michigan:
			Natural gas processed for a fee (Mcf/d)		13,800			8,800			11,000			17,800			16,000

(1): At the closing of its IPO, the Partnership entered into contracts with MarkWest Hydrocarbon. These contracts were substantially different from those contracts in effect under the Midstream Business. The contractual differences materially affected the comparability of the information reflected in Revenues and Purchased product costs.
(2): Represents throughput at our Kenova, Cobb, and Boldman processing plants.
(3): Prior to May 24, 2002, this represents NGL product production through our Siloam fractionator.
(4): As Restated. See Note 15 to the Consolidated and Combined Financial Statements included herein.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Results of Operations

Overview

We are a Delaware limited partnership formed to own and operate a growing midstream business. We are engaged in the gathering and processing 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.

On March 24, 2003, we entered into an agreement to merge with Pinnacle Natural Gas Company and certain affiliates for approximately $38 million. The acquired assets, primarily located in Texas, are comprised of (a) three lateral natural gas pipelines transporting up to 1.1 Bcf/d of natural gas under firm contracts to power plants and (b) eighteen gathering systems gathering more than 44,000 Mcf/d. The acquisition complements and expands our core fee-based businesses, while providing geographic and customer diversification. The acquisition will be financed primarily through borrowings under our credit facility, which was recently expanded by $15 million.

The results of operations discussed below are those of MarkWest Energy Partners, L.P. on and after May 24, 2002, the closing date of our IPO and of our predecessor, the MarkWest Hydrocarbon Midstream Business (the Midstream Business), prior to May 24, 2002. Audited financial statements for the Partnership and the Midstream Business appear elsewhere in this annual report. The financial statements of the Midstream Business 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 stand-alone 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 Midstream Business generated revenues. Historically, the Midstream Business generated its revenues pursuant to two types of contracts:

•: "Keep-whole" contracts under which the 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; and
•: "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.

Currently, none of our revenues are generated pursuant to keep-whole contracts. 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. However, 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 gas 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; and
•: 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; and
•: 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 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 results of operations for the Midstream Business discussed below may be of limited use in evaluating the business to be 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 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, insurance and other corporate services.

MarkWest Energy Partners, L.P.

We generate the majority of our revenues from gas processing 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 Midstream Business's existing contracts and gather and process natural gas directly for the third parties who are parties to those contracts. 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.

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 obligation in our current arrangements.

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, 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.

Restatement

The Partnership previously reported two separate statements of operations and of cash flows for the year ended December 31, 2002. One statement of operations and one statement of cash flows was presented for the period from January 1, 2002 through May 23, 2002 for the MarkWest Hydrocarbon Midstream Business prior to its conveyance to the Partnership on May 24, 2002. Another statement of operations and statement of cash flows was presented for the period from May 24, 2002 through December 31, 2002.

The conveyance of the MarkWest Hydrocarbon Midstream Business from MarkWest Hydrocarbon to the Partnership represented a reorganization of entities under common control and was recorded at historical cost. Consequently, the Partnership has now determined that it should have combined these statements and presented them for the full year ended December 31, 2002.

In addition, the Partnership had previously reported net income per limited partner unit for the period from May 24, 2002 through December 31, 2002. In its restated financial statements, the Partnership has restated net income per limited partner unit to report such amount for the year ended December 31, 2002. Further, the Partnership has now reported net income per limited partner unit for the years ended December 31, 2001 and 2000. Finally, the elimination of the deferred tax liability resulting from our conversion to partnership form had previously been credited to the partners' capital portion of the Partnership's balance sheet without impacting our statement of operations. In our revised presentation, the elimination of the deferred tax liability is reflected in the statement of operations as a part of the provision (benefit) for income taxes, increasing net income and net income per limited partner unit and ultimately reflected in the partners' capital portion of the balance sheet. Accordingly, the adjustment results in no net change to the balance sheet of the Partnership. See Note 15 to our Consolidated and Combined Financial Statements included herein.

Operating Data

			Year Ended December 31,
			2002	2001
Appalachia:
	Natural gas processed for a fee (Mcf/d) under contracts in effect:
		Beginning May 24, 2002	255,000	—
		Prior to May 24, 2002	—	246,000
	NGLs fractionated for a fee (gallons/day) under contracts in effect:
		Beginning May 24, 2002	477,000	—
		Prior to May 24, 2002	462,000	423,000
	NGL product sales (gallons) under contracts in effect:
		Beginning May 24, 2002	23,414,000	—
		Prior to May 24, 2002	75,821,000	154,550,000
Michigan:
	Gas volumes processed for a fee (Mcf/d)		13,800	8,800
	NGL product sales (gallons)		11,075,000	8,000,000

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

Revenues. Our combined revenues were $70.2 million for the year ended December 31, 2002, compared to $93.7 million for the year ended December 31, 2001, a decrease of $23.4 million, or 25%. Revenues were lower in 2002 than in 2001 primarily due to the terms of the new contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of our initial public offering. On the percent-of-proceed contracts retained by the Partnership, average NGL product sales prices were lower in the 2002 period than in the comparable 2001 period.

Purchased Product Costs. Our combined purchased product costs were $38.9 million for the year ended December 31, 2002, compared to $65.5 million for the year ended December 31, 2001, a decrease of $26.6 million, or 41%. Purchased product costs were lower in 2002 primarily due to the terms of new contracts entered into by MarkWest Hydrocarbon and us concurrent with the closing of our initial public offering.

Facility Expenses. Our combined facility expenses were $15.1 million for the year ended December 31, 2002, compared to $13.1 million for the year ended December 31, 2001, an increase of $2.0 million, or 15%. Facility expenses increased due to increased throughput in our Michigan facilities and the expansion of our Kenova processing plant.

Selling, General and Administrative Expenses. Our combined selling, general and administrative expenses were $5.3 million for the year ended December 31, 2002, compared to $5.0 million for the year ended December 31, 2001, an increase of $0.2 million, or 5%. Selling, general and administrative expenses increased principally due to the Partnership's incremental costs associated with being a publicly traded company, as well as increased insurance costs.

Depreciation. Our combined depreciation expense was $5.0 million for the year ended December 31, 2002, compared to $4.5 million for the year ended December 31, 2001, an increase of $0.5 million, or 11%. The increase is principally attributable to additional fixed assets placed into service during the second half of 2001.

Interest Expense. Our combined interest expense was $1.4 million for the year ended December 31, 2002, compared to $1.3 million for the year ended December 31, 2001 an increase of $0.1 million, or 8%.

Income Taxes. The Partnership has not been subject to income taxes since its inception. The Midstream Business recorded a non-cash adjustment of $17.2 million to eliminate deferred income tax liabilities that existed at the date of conveyance of the MarkWest Hydrocarbon Midstream Business from MarkWest Hydrocarbon to the Partnership. Accordingly, the Midstream Business has recorded a benefit to the deferred tax provision for the year ended December 31, 2002, which increased net income by $17.2 million.

Year Ended December 31, 2001 Compared to the Year Ended December 31, 2000

Revenues. Revenues were $93.7 million for the year ended December 31, 2001 compared to $109.8 million for the year ended December 31, 2000, a decrease of $16.1 million, or 15%. Revenues were lower in 2001 than in 2000 primarily due to a decrease in the average Appalachian NGL sales price, which accounted for $14.9 million of the decrease. The average Appalachian NGL sales price was $0.53 per gallon for the year ended December 31, 2001, compared to $0.63 per gallon for the year ended December 31, 2000, a decrease of $0.10 per gallon, or 16%. Appalachian NGL sales volumes remained essentially flat from 2000 to 2001. Lower Michigan NGL sales volumes in 2001, a result of decreased pipeline throughput, accounted for the remainder of the decrease in revenues and were partially offset by a modest increase in average Michigan NGL sales price during 2001.

Purchased Product Costs. Purchased product costs were $65.5 million for the year ended December 31, 2001, compared to $71.3 million for the year ended December 31, 2000, a decrease of $5.9 million, or 8%. Purchased product costs were lower in 2001 primarily due to:

•: a decrease in the average Appalachian replacement natural gas cost, which accounted for an approximately $4.1 million decrease in purchased product costs. The average cost of Appalachian replacement natural gas was equivalent to $0.39 per NGL gallon for the year ended December 31, 2001, compared to $0.42 per gallon for the year ended December 31, 2000, a decrease of $0.03 per gallon, or 7%.
•: a decrease in our average Appalachian NGL prices, which accounted for $2.4 million of the decrease. Reduced average Appalachian NGL prices reduced the percent of proceeds remitted to an Appalachian producer.
•: increased transportation costs, a result of an increase in the number of our sales outlets, partially offset the decrease in the average Appalachian replacement natural gas cost.

Facility Expenses. Facility expenses were $13.1 million for the year ended December 31, 2001, compared to $13.2 million for the year ended December 31, 2000, a decrease of $0.1 million, or 1%.

Selling, General and Administrative Expenses. Selling, general and administrative expenses were $5.0 million for the year ended December 31, 2001, compared to $4.7 million for the year ended December 31, 2000, an increase of $0.3 million, or 7%.

Depreciation. Depreciation expense was $4.5 million for the year ended December 31, 2001, compared to $4.3 million for the year ended December 31, 2000, an increase of $0.1 million, or 3%.

Interest Expense. Interest expense was $1.3 million for the year ended December 31, 2001, compared to $1.7 million for the year ended December 31, 2000, a decrease of $0.4 million, or 23%. The decrease was principally caused by a reduction in interest rates throughout 2001.

Income Taxes. Income taxes for the year ended December 31, 2001, were $1.6 million, compared to $5.7 million for the year ended December 31, 2000, a decrease of $4.1 million, or 72%. Income taxes decreased principally due to lower income before income taxes.

Net Income. Net income for the year ended December 31, 2001, was $2.6 million, compared to $8.8 million for the year ended December 31, 2000, a decrease of $6.2 million, or 71%. Net income decreased principally as a result of decreased average Appalachian NGL sales prices.

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 accounted for approximately 15% of our gross margin (revenue less purchased product costs) as of December 31, 2002, 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

Cash generated from operations and borrowings under our credit facility are our primary sources of liquidity. At December 31, 2002, the Partnership had working capital of $1.8 million. As of December 31, 2002, the Partnership had borrowed $21.4 million of the $38.6 million available under its credit facility. In March 2003, the credit facility was amended to increase the aggregate committed sum to $75 million. 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, we have the ability to issue up to 1,207,500 additional common units without unitholder approval, to raise equity capital.

Our ability to pay distributions to our unitholders, to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance, and more broadly, on the availability of debt and equity financing 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, which accounted for 79% of our revenues since our IPO closed. 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.

Capital Requirements

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 be $0.5 million for the year ended December 31, 2003, exclusive of any acquisitions.

Cash Flow

Our combined net cash provided by operating activities was $33.5 million for the year ended December 31, 2002. Net cash used in operating activities was $0.5 million for the year ended December 31, 2001. Net cash provided by operating activities was higher in 2002 than in 2001 primarily due to new, ongoing contracts entered into by us with MarkWest Hydrocarbon concurrent with the closing of our initial public offering.

Our combined net cash used in investing activities was $2.1 million for the year ended December 31, 2002, compared to $9.0 million for the year ended December 31, 2001, for the

Midstream Business. The decrease was principally attributable to the level of construction in Appalachia during 2001, which has since been completed.

Our combined net cash used in financing activities was $28.7 million for the year ended December 31, 2002, compared to net cash provided by financing activities of $9.5 million for the year ended December 31, 2001, for the Midstream Business. The financing activities for the year ended December 31, 2002, reflect the Partnership's IPO and related transactions.

Total Contractual Cash Obligations

A summary of our total contractual cash obligations as of December 31, 2002, is as follows:

	Payment Due by Period
Type of Obligation	Total Obligation		Due in 2003		Due in 2004-2005		Due in 2006-2007		Due Thereafter
	(in thousands)
Long-term debt	$	21,400	$	—	$	21,400	$	—	$	—
Operating leases		2,495		527		1,054		590		324

Total contractual cash obligations	$	23,895	$	527	$	22,454	$	590	$	324

Credit Facility

You should read Note 4 of the accompanying Notes to Consolidated and Combined Financial Statements included in Item 8 of this annual report for a description of our credit facility.

Related Parties

We entered into various agreements with MarkWest Hydrocarbon at the closing of our IPO. Specifically, we entered into a:

•: Gas Processing Agreement
•: Pipeline Liquids Transportation Agreement
•: Fractionation, Storage and Loading Agreement
•: Natural Gas Liquids Purchase Agreement
•: Omnibus Agreement

These agreements were not the result of arm's-length negotiations. You should read Items 1. and 2., "Business and Properties—Our Contracts with MarkWest Hydrocarbon" for further information regarding these agreements.

Critical Accounting Policies

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment, to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical. Our critical accounting policy is discussed below. For further details on our accounting policies, you should read Note 2 of the accompanying Notes to Consolidated and Financial Statements included in Item 8 of this annual report. You should also read the "Recent Accounting Pronouncements" below.

Impairment of Long-Lived Assets

In accordance with Statement of Financial Accounting Standards (SFAS) No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, we evaluate the long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management's estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value determine the amount of the impairment recognized. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is recalculated when related events or circumstances change.

When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset or asset group. Our estimate of cash flows is based on assumptions regarding the volume of reserves behind the asset and future NGL product and natural gas prices. The amount of reserves and drilling activity are dependent in part on natural gas prices. Projections of reserves and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:

•: Changes in general economic conditions in regions in which our products are located;
•: The availability and prices of NGL products and competing commodities;
•: The availability and prices of raw natural gas supply;
•: Our ability to negotiate favorable marketing agreements;
•: The risks that third party or MarkWest Hydrocarbon's (in the case of Michigan) natural gas exploration and production activities will not occur or be successful;
•: Our dependence on certain significant customers, producers, gatherers, treaters, and transporters of natural gas; and
•: Competition from other NGL processors, including major energy companies.

Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.

Recent Accounting Pronouncements

In June 2001, the FASB issued SFAS No. 142,Goodwill and Other Intangible Assets, which is effective for fiscal years beginning after December 15, 2001, and applies to all goodwill and other intangibles recognized in the financial statements at that date. Under the provisions of this statement, goodwill will not be amortized, but will be tested for impairment on an annual basis. The adoption of SFAS No. 142 did not have a material impact on the Partnership's financial position or results of operations.

In June 2001, the FASB issued 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. The provisions of this statement are effective for fiscal years beginning after June 15, 2002. With respect to our midstream services, we have certain surface facilities with ground leases requiring us to dismantle and remove these facilities upon the termination of the applicable lease. We anticipate recording a liability, if one can be reasonably estimated, for such obligations in the first quarter of 2003.

In January 2002, the FASB Emerging Issues Task Force released Issue No. 02-3,Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The Task Force reached a consensus to rescind EITF Issue No. 98-10,Accounting for Contracts Involved in Energy Trading and Risk Management Activities, the impact of which is preclude mark-to-market accounting for all energy trading contracts not within the scope of FASB Statement No. 133,Accounting for Derivative Instruments and Hedging Activities. The Task Force also reached a consensus that gains and losses on derivative instruments within the scope of Statement 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. The consensus regarding the rescission of Issue 98-10 is applicable for fiscal periods beginning after December 15, 2002. We do not have any trading activities and did not account for any contracts as trading contracts in accordance with EITF Issue No. 98-10. Therefore, the EITF consensus to rescind EITF Issue No. 98-10 will not have an impact on our financial position or results of operations.

In April 2002, the FASB issued SFAS No. 145,Rescission of SFAS Nos. 4, 44 and 64; Amendment of SFAS Statement No. 13; and Technical Corrections, which is generally effective for transactions occurring after May 15, 2002. Through the rescission of SFAS Nos. 4 and 64, SFAS No. 145 eliminates the requirement that gains and losses from extinguishments of debt be aggregated and, if material, be classified as an extraordinary item net of any income tax effect. SFAS No. 145 made several other technical corrections to existing pronouncements that may change accounting practice. SFAS No. 145 did not impact on our results of operations or financial position.

In June 2002, the FASB issued SFAS No. 146,Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF Issue No. 94-3,Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). We do not believe that the adoption of SFAS No. 146 will have a material impact on our results of operations or financial position.

In November 2002, FASB Interpretation No. 45,Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (FIN 45), was issued. The accounting recognition provisions of FIN 45 are effective January 1, 2003 on a prospective basis. They require that a guarantor recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. Under prior accounting principles, a guarantee would not have been recognized as a liability until a loss was probable and reasonably estimable. As FIN 45 only applies to prospective transactions, we are unable to determine the impact, if any, that adoption of the accounting recognition provisions of FIN 45 would have on our future financial position or results of operations.

In January of 2003, the FASB issued Interpretation No. 46,Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (FIN 46), which requires the consolidation of certain variable interest entities, as defined. FIN 46 is effective immediately for variable interest entities created after January 31, 2003, and on July 1, 2003 for investments in variable interest entities acquired before February 1, 2003; however, disclosures are required currently if a company expects to consolidate any variable interest entities. We do not have investments in any variable interest entities, and therefore, the adoption of FIN 46 is not expected to have an impact on our results of operations, financial position or cash flows.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated and Combined Financial Statements


Report of Independent Auditors
Consolidated and Combined Balance Sheets at December 31, 2002 and 2001
Consolidated and Combined Statements of Operations for each of the three years in the period ended December 31, 2002
Consolidated and Combined Statements of Cash Flows for each of the three years in the period ended December 31, 2002
Consolidated Statements of Changes in Capital for each of the three years in the period ended December 31, 2002
Notes to Consolidated and Combined Financial Statements

REPORT OF INDEPENDENT AUDITORS

To the Board of Directors of MarkWest Energy GP, L.L.C.

In our opinion, the accompanying consolidated and combined balance sheets and the related consolidated and combined statements of operations, of cash flows and of changes in capital present fairly, in all material respects, the financial position of MarkWest Energy Partners, L.P., a Delaware partnership (the Partnership), and its subsidiaries at December 31, 2002 and the results of their operations and their cash flows for the year ended December 31, 2002 and the financial position of the MarkWest Hydrocarbon Midstream Business at December 31, 2001, and for each of the two years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in Note 15 to the consolidated and combined financial statements, the Partnership has restated its consolidated and combined statements of operations, of cash flows and of changes in capital for the year ended December 31, 2002 and the presentation of basic and diluted net income per limited partner unit for the years ended December 31, 2001 and 2000.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado
February 12, 2003, except for Note 14,
as to which the date is March 25, 2003 and, except for
Note 15, as to which the date is
January 10, 2004

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED BALANCE SHEETS

(in thousands)

			December 31, 2002 (Partnership)			December 31, 2001 (MarkWest Hydrocarbon Midstream Business)
ASSETS
Current assets:
	Cash and cash equivalents		$	2,776		$	—
	Receivables			976			8,538
	Receivables from affiliate			2,847			—
	Inventories			130			4,968
	Prepaid replacement natural gas			—			8,081
	Risk management asset			—			1,204
	Other assets			336			92

		Total current assets		7,065			22,883
Property, plant and equipment:
	Gas gathering facilities			34,398			34,386
	Gas processing plants			47,403			41,647
	Fractionation and storage facilities			22,076			18,730
	NGL transportation facilities			4,402			4,402
	Land, building and other equipment			3,021			2,977
	Construction in progress			348			6,758

				111,648			108,900
	Less: Accumulated depreciation			(31,824	)		(26,892	)

		Total property, plant and equipment, net		79,824			82,008
Deferred financing costs, net of amortization of $291				820			—

		Total assets	$	87,709		$	104,891

LIABILITIES AND CAPITAL
Current liabilities:
	Accounts payable		$	1,199		$	3,946
	Payables to affiliate			723			—
	Accrued liabilities			2,880			697
	Risk management liability			501			—

		Total current liabilities		5,303			4,643
Deferred income taxes				—			15,640
Debt due to parent				—			19,179
Long-term debt				21,400			—
Risk management liability				143			—
Commitments and contingencies (Note 10)
Capital:
	Partners' capital			61,574			—
	Net parent investment			—			64,461
	Accumulated other comprehensive income (loss)			(711	)		968

		Total capital		60,863			65,429

		Total liabilities and capital	$	87,709		$	104,891

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

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

			Year Ended December 31, 2002 (As Restated. See Note 15)			Year Ended December 31, 2001 (MarkWest Hydrocarbon Midstream Business)			Year Ended December 31, 2000 (MarkWest Hydrocarbon Midstream Business)
Revenues:
	Sales to affiliates		$	26,093		$	—		$	—
	Sales to unaffiliated parties			44,153			93,675			109,810

		Total revenues		70,246			93,675			109,810
Operating expenses:
	Purchased product costs			38,906			65,483			71,341
	Facility expenses			15,101			13,138			13,224
	Selling, general and administrative expenses			5,283			5,047			4,733
	Depreciation			4,980			4,490			4,341

		Total operating expenses		64,270			88,158			93,639

		Income from operations		5,976			5,517			16,171
Other income and (expenses):
	Interest expense, net			(1,414	)		(1,307	)		(1,697	)
	Miscellaneous income			52			—			—

	Income before income taxes			4,614			4,210			14,474

Provision (benefit) for income taxes:
	Current due to (from) parent			(1,535	)		(1,468	)		2,854
	Deferred			(15,640	)		3,092			2,839

		Provision (benefit) for income taxes		(17,175	)		1,624			5,693

		Net income	$	21,789		$	2,586		$	8,781

General partner's interest in net income			$	89		$	—		$	—

Limited partners' interest in net income			$	21,700		$	2,586		$	8,781

Basic net income per limited partner unit(1)			$	4.86		$	0.86		$	2.93

Diluted net income per limited partner unit(1)			$	4.83		$	0.86		$	2.93

Weighted average units outstanding:
		Basic(1)		4,469			3,000			3,000

		Diluted(1)		4,493			3,000			3,000

(1): As Restated. See Note 15.
The accompanying notes are an integral part of these financial statements.

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS

(in thousands)

				Year Ended December 31, 2002 (As Restated. See Note 15)			Year Ended December 31, 2001 (MarkWest Hydrocarbon Midstream Business)			Year Ended December 31, 2000 (MarkWest Hydrocarbon Midstream Business)
Cash flows from operating activities:
Net income				$	21,789		$	2,586		$	8,781
Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation			4,980			4,490			4,341
		Amortization of deferred financing costs included in interest expense			291			—			—
		Deferred income taxes			(15,640	)		3,092			2,839
		Other			(293	)		48			—
	Changes in operating assets and liabilities, net of working capital assumed:
		(Increase) decrease in receivables			(43	)		5,018			(7,183	)
		(Increase) decrease in inventories			2,333			(726	)		(1,492	)
		(Increase) decrease in prepaid replacement natural gas and other assets			4,933			(7,952	)		1,737
		Increase (decrease) in accounts payable and accrued liabilities			12,062			(7,080	)		4,974
		Increase in long-term replacement natural gas payable			3,090			—			—

			Net cash provided by (used in) operating activities		33,502			(524	)		13,997
Cash flows from investing activities:
		Capital expenditures			(2,145	)		(9,651	)		(12,147	)
		Proceeds from sale of assets			89			654			—

			Net cash used in investing activities		(2,056	)		(8,997	)		(12,147	)
Cash flows from financing activities:
		Proceeds from initial public offering, net			43,625			—			—
		Distribution to MarkWest Hydrocarbon			(63,476	)		—			—
		Distributions to unitholders			(3,923	)		—			—
		Payments for debt issuance costs			(1,111	)		—			—
		Proceeds from long-term debt			23,400			—			—
		Repayment of long-term debt			(2,000	)		—			—
		Net advances from (distributions to) parent			(24,218	)		11,124			(4,676	)
		Debt due to (from) parent			(967	)		(1,603	)		2,826

			Net cash provided by (used in) financing activities		(28,670	)		9,521			(1,850	)

Net increase (decrease) in cash					2,776			—			—
Cash and cash equivalents at beginning of period					—			—			—

Cash and cash equivalents at end of period				$	2,776		$	—		$	—

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

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN CAPITAL

(in thousands)

										PARTNERS' CAPITAL
																		General Partner
										Limited Partners
				Net Parent Investment			Accumulated Other Comprehensive Income			Limited Partners
				Net Parent Investment			Accumulated Other Comprehensive Income			Common				Subordinated
				$			$			Units	$			Units	$			$			Total
Balance, December 31, 1999				$	46,646		$	—		—	$	—		—	$	—		$	—		$	46,646
Net income					8,781			—		—		—		—		—			—			8,781
Net change in parent advances					(4,676	)		—		—		—		—		—			—			(4,676	)

Balance, December 31, 2000					50,751			—		—		—		—		—			—			50,751
Comprehensive income:
	Net income				2,586			—		—		—		—		—			—			2,586
	Other comprehensive income:
		Cumulative effect of change in accounting principle, net of tax			—			1,328		—		—		—		—			—			1,328
		Risk management activities, net of tax			—			(360	)	—		—		—		—			—			(360	)

			Ending accumulated derivative gain																			968

Comprehensive income																						3,554
Net change in parent advances					11,124			—		—		—		—		—			—			11,124

Balance, December 31, 2001					64,461			968		—		—		—		—			—			65,429
Net income applicable to the period from January 1 through May 23, 2002(1)					17,332			—		—		—		—		—			—			17,332
Net change in parent advances					(24,218	)		—		—		—		—		—			—			(24,218	)
Adjustment to reflect net liabilities not assumed by the Partnership(1)					23,316			—		—		—		—		—			—			23,316
Book value of net assets contributed by MarkWest Hydrocarbon to the Partnership(1)					(80,891	)		—		—		—		3,000		79,273			1,618			—
Distribution to MarkWest Hydrocarbon(1)					—			—		—		—		—		(62,206	)		(1,270	)		(63,476	)
Issuance of units to public (including underwriter over-allotment), net of offering and other costs					—			—		2,415		43,625		—		—			—			43,625
Distributions to unitholders					—			—		—		(1,715	)	—		(2,130	)		(78	)		(3,923	)
Net income applicable to the period from May 24 through December 31, 2002					—			—		—		1,948		—		2,420			89			4,457
Risk management activities					—			(1,679	)	—		—		—		—			—			(1,679	)

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

(1): As Restated. See Note 15.
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) was formed on January 25, 2002 as a Delaware limited partnership. The Partnership and its subsidiary, MarkWest Energy Operating Company, L.L.C. (the Operating Company), were formed to acquire, own and operate most of the assets, liabilities and operations of MarkWest Hydrocarbon Midstream Business.

On May 24, 2002, MarkWest Hydrocarbon, Inc. (MarkWest Hydrocarbon), through its subsidiaries, MarkWest Energy GP, L.L.C., the general partner of the Partnership, and MarkWest Michigan, Inc., conveyed the MarkWest Hydrocarbon Midstream Business to the Partnership in exchange for:

•: 3,000,000 subordinated units;
•: A 2% general partner interest in the Partnership;
•: Incentive distribution rights (as defined in the Partnership Agreement);
•: The direct and indirect assumption of certain liabilities by the Partnership, including $1.8 million in working capital liabilities and $19.4 million of indebtedness;
•: The right to be reimbursed by the Partnership for $15.6 million of capital expenditures; and
•: The right to receive $26.7 million in cash upon the closing of the Initial Public Offering ("IPO") and the Operating Company's new $60 million credit facility. The Operating Company is a wholly owned subsidiary of the Partnership.

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.

The Partnership concurrently issued 2,415,000 common units in its IPO (including 315,000 units issued pursuant to the underwriters' over-allotment option), representing a 43.7% limited partnership interest in the Partnership, at a price of $20.50 per unit. The Operating Company concurrently entered into a $60 million credit facility with various lenders.

A summary of the proceeds received and use of proceeds is as follows (in thousands):

Proceeds received:
	Sale of common units	$	49,508
	Borrowing under term loan facility		21,400
Use of proceeds:
	Underwriters' fees		3,466
	Professional fees and other offering costs		2,417
	Debt issuance costs		1,077
	Repayment of assumed working capital liabilities		1,800
	Repayment of debt due to parent		19,376
	Reimbursement of capital expenditures to MarkWest Hydrocarbon		15,600
	Distribution to MarkWest Hydrocarbon		26,700

	Net proceeds remaining	$	472

2. Summary of Significant Accounting Policies

Basis of Presentation

The consolidated and combined financial statements include the accounts of the Partnership and the MarkWest Hydrocarbon Midstream Business and have been prepared in accordance with accounting principles generally accepted in the United States. Intercompany balances and transactions within the Partnership and MarkWest Hydrocarbon Midstream Business have been eliminated.

Prior to May 24, 2002, the date on which the MarkWest Hydrocarbon Midstream Business was conveyed to the Partnership (see Note 1) the financial statements include charges from MarkWest Hydrocarbon for direct costs and allocations of indirect corporate overhead as well as federal and state income tax provisions. Selling, general and administrative expenses for the MarkWest Hydrocarbon Midstream Business in 2000 and 2001 are comprised entirely of allocations of indirect corporate overhead from MarkWest Hydrocarbon. Management of the Partnership believes that the allocation methods are reasonable. Commencing with the conveyance of the MarkWest Hydrocarbon Midstream Business to the Partnership on May 24, 2002, the consolidated financial statements do not reflect any amounts for federal and state income taxes as the Partnership is not a taxable entity (see Note 8). However, the consolidated financial statements of the Partnership subsequent to May 24, 2002 do include charges from MarkWest Hydrocarbon for direct costs and allocation of indirect corporate overhead as more fully described in Note 3.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Inventories

Product inventory consists primarily of finished energy products (propane, butane, isobutane, and natural gasoline) and is valued at the lower of weighted average cost or market. Materials and supplies are valued at the lower of average cost or estimated net realizable value.

Prepaid Replacement Natural Gas

Prepaid replacement natural gas consisted of natural gas purchased in advance of its actual use. It was valued using the first-in, first-out method.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of assets are capitalized. Repairs, maintenance and renewals that do not extend the useful lives of the assets are expensed as incurred. Interest costs for the construction or development of long-term assets are capitalized and amortized over the related asset's estimated useful life. Depreciation is provided principally on the straight-line method over the following estimated useful lives: gas gathering and processing and NGL transportation, fractionation and storage facilities—20 years or the number of

years reserves behind our facilities are contractually dedicated, whichever is longer; buildings—40 years; furniture, leasehold improvements and other—3 to 10 years.

Impairment of Long-Lived Assets

In accordance with Statement of Financial Accounting Standards (SFAS) No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, the Partnership evaluates its long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management's estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value determine the amount of the impairment recognized. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change. No impairment charges were recognized for any period presented.

Capitalization of Interest

We capitalize interest on major projects during construction. Interest is capitalized on borrowed funds. The interest rates used are based on the average interest rate on related debt.

Deferred Financing Costs

Deferred financing costs are amortized on a straight-line basis and charged to interest expense over the anticipated term of the associated agreement.

Commodity Price Risk Management Activities

Prior to January 1, 2001 and the implementation of SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities gains and losses on hedges of production were included in the carrying amount of the inventory and were ultimately recognized in purchased gas costs or sales when the related inventory was sold. Gains and losses related to qualifying hedges, as defined by SFAS No. 80, Accounting for Futures Contracts, of firm commitments or anticipated transactions (including hedges of equity production) were recognized in purchased gas costs or sales, as reported on the Consolidated Statement of Operations, when the hedged physical transaction occurred. For purposes of the Consolidated Statement of Cash Flows, all hedging gains and losses were classified in net cash provided by operating activities.

In June 1998, SFAS No. 133 was issued effective for fiscal years beginning after June 15, 2000. Under SFAS No. 133, which was subsequently amended by SFAS No. 138, we are required to recognize the change in the market value of all derivatives as either assets or liabilities in our Balance Sheet and measure those instruments at fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income depending upon the nature of the underlying transaction.

See also Notes 6 and 7.

Fair Value of Financial Instruments

Our financial instruments consist of receivables, accounts payable and other current liabilities and debt. Except for debt, the carrying amounts of financial instruments approximate fair value due to their short maturities. At December 31, 2002 and 2001, based on rates available for similar types of debt, the fair value of our debt was not materially different from its carrying amount.

Net Parent Investment

The net parent investment represents a net balance as the result of various transactions between the MarkWest Hydrocarbon Midstream Business and MarkWest Hydrocarbon. There were no terms of settlement or interest charges associated with this balance. The balance was the result of the MarkWest Hydrocarbon Midstream Business's participation in MarkWest Hydrocarbon's central cash management program, wherein all of the MarkWest Hydrocarbon Midstream Business's cash receipts were remitted to MarkWest Hydrocarbon and all cash disbursements were funded by MarkWest Hydrocarbon. Other transactions included intercompany transportation and terminating revenues and related expenses, administrative and support expenses incurred by MarkWest Hydrocarbon and allocated to the MarkWest Hydrocarbon Midstream Business, and accrued interest and income taxes.

Revenue Recognition

Gas gathering and processing and NGL fractionation, transportation and storage revenues are recognized as volumes are processed, fractionated, transported and stored in accordance with contractual terms. Revenue for NGL product sales is recognized at the time the title is transferred.

Income Taxes

The Partnership is not a taxable entity. The MarkWest Hydrocarbon Midstream Business's operations were included in MarkWest Hydrocarbon's consolidated federal and state income tax returns. The MarkWest Hydrocarbon Midstream Business's income tax provisions were computed as though separate returns were filed up to the date of the formation of the Partnership. The MarkWest Hydrocarbon Midstream Business accounted for income taxes in accordance with the provisions of SFAS No. 109,Accounting for Income Taxes. This statement requires a company to recognize deferred tax liabilities and assets for the expected future tax consequences of events that have been recognized in a company's financial statements or tax returns. Using this method, deferred tax liabilities and assets were determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates.

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. These plans are described more fully in Note 9. 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:

		Year Ended December 31, 2002 (As Restated. See Note 15)			Year Ended December 31, 2001 (MarkWest Hydrocarbon Midstream Business)			Year Ended December 31, 2000 (MarkWest Hydrocarbon Midstream Business)
		(in thousands)
Net income, as reported		$	21,789		$	2,586		$	8,781
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects			(184	)		(248	)		(218	)

Pro forma net income		$	21,605		$	2,338		$	8,563

Net income per limited partner unit:(1)
	Basic—as reported	$	4.86		$	0.86		$	2.93
	Basic—pro forma	$	4.81		$	0.78		$	2.85
	Diluted—as reported	$	4.83		$	0.86		$	2.93
	Diluted—pro forma	$	4.79		$	0.78		$	2.85

(1): As Restated. See Note 15.

Segment Reporting

We operate in only one segment, the midstream services segment of the oil and gas industry.

Recent Accounting Pronouncements

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. The provisions of this statement are effective for fiscal years beginning after June 15, 2002. With respect to our midstream services, we have certain surface facilities with ground leases requiring us to dismantle and remove these facilities upon the termination of the applicable lease. We anticipate recording a liability, if one can be reasonably estimated, for such obligations in the first quarter of 2003.

guarantee would not have been recognized as a liability until a loss was probable and reasonably estimable. As FIN 45 only applies to prospective transactions, we are unable to determine the impact, if any, that adoption of the accounting recognition provisions of FIN 45 would have on our future financial position or results of operations.

3. Related Party Transactions

Prior to the conveyance of the MarkWest Hydrocarbon Midstream Business to the Partnership, substantially all transactions with MarkWest Hydrocarbon and its subsidiaries were settled immediately through the net parent investment account. Subsequent to the conveyance, normal trade terms apply to transactions with MarkWest Hydrocarbon as contained in various agreements discussed below which were entered into concurrent with the conveyance.

Receivable from Affiliate

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

•: A gas processing agreement pursuant to which MarkWest Hydrocarbon delivers to us all natural gas it receives from Columbia Gas Transmission Corporation for processing at our processing plants. MarkWest Hydrocarbon pays us a monthly fee based on the natural gas volumes delivered to us for processing.
•: A transportation agreement pursuant to which MarkWest Hydrocarbon delivers all of its NGLs to us for transportation through our pipelines to our Siloam fractionator. MarkWest Hydrocarbon pays us a monthly fee based on the number of gallons delivered to us for transportation.
•: A fractionation agreement pursuant to which MarkWest Hydrocarbon delivers all of its NGLs to us for unloading, fractionation, loading and storage at our Siloam facility. MarkWest Hydrocarbon pays us a monthly fee based on the number of gallons delivered to us for fractionation, a percentage of the proceeds from the sale of a portion of the NGL products produced, an annual storage fee, and a monthly fee based on the number of gallons of NGLs unloaded; and
•: A natural gas liquids purchase agreement pursuant to which MarkWest Hydrocarbon receives and purchases, and we deliver and sell, all of the NGL products we produce pursuant to our gas processing agreement with a third party. Under the terms of this agreement, MarkWest

Hydrocarbon pays us a purchase price equal to the proceeds it receives from the resale to third parties of such NGL products. This contract also applies to any other NGL products we acquire. We retain a percentage of the proceeds attributable to the sale of the NGL products we produce pursuant to our agreement with a third party, and remit the balance from such NGL products sale proceeds to this third party.

Payable to Affiliate

MarkWest Hydrocarbon provides centralized corporate functions such as accounting, treasury, engineering, information technology, insurance and other corporate services, which are included in selling, general and administrative expenses. We reimburse MarkWest Hydrocarbon monthly for the selling, general and administrative support MarkWest Hydrocarbon allocates to us. MarkWest Hydrocarbon has allocated to the Partnership approximately $2.2 million (during the period from January 1, 2002 to May 23, 2002) and $1.9 million (during the period from May 24, 2002 to December 31, 2002) of these costs which are included in selling, general and administrative expenses.

The Partnership is also reimbursing MarkWest Hydrocarbon for the salaries and employee benefits, such as 401(k), pension, and health insurance, of plant operating personnel as well as other direct operating expenses. For the year ended December 31, 2002, these costs totaled $2.6 million and appear in plant operating expenses. The Partnership has no employees.

In Michigan, we assumed the MarkWest Hydrocarbon Midstream Business's existing contracts and gather and process gas directly for those third parties. We receive 100% of all fee and percent-of-proceeds consideration for the first 10 MMcf/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 MMcf/d. For year ended December 31, 2002, MarkWest Hydrocarbon's net profit interest was $0.4 million and is included in plant operating and other expenses.

Debt Due to Affiliate

Prior to the IPO, the MarkWest Hydrocarbon Midstream Business financed its working capital requirements and its capital expenditures through intercompany accounts between the MarkWest Hydrocarbon Midstream Business and MarkWest Hydrocarbon. Effective October 12, 2001, MarkWest Hydrocarbon formalized the terms under which certain intercompany accounts would be settled between the MarkWest Hydrocarbon Midstream Business and MarkWest Hydrocarbon. Interest on the outstanding balance was charged annually based on MarkWest Hydrocarbon's average borrowing rate from a third party. Interest charges were settled through the net parent investment account. Interest was charged at a weighted average rate of 6.3% and 6.5% for the period from January 1, 2002 through May 23, 2002, and the year ended December 31, 2001, respectively. On May 24, 2002, debt due to MarkWest Hydrocarbon was assumed by the Partnership and paid in full with proceeds from the IPO.

4. Debt

In connection with our IPO, the Operating Company, a wholly owned subsidiary of the Partnership, entered into a $60 million credit facility (the Partnership Credit Facility) with various financial institutions. The Partnership Credit Facility was expanded by $15 million in March 2003. The

Partnership Credit Facility is comprised of both a revolving and term loan credit facility. On December 1, we amended and restated the Partnership Credit Facility to increase the revolving credit facility, to eliminate the term loan facility and to extend the expiration date to November 30, 2006.

Under the revolving credit facility, up to $28.6 million is available to fund capital expenditures and acquisitions and up to $10 million is available for working capital purposes (including letters of credit) and to fund distributions to unitholders. However, not more than $2.25 million may be used in any four-quarter period to fund distributions to unitholders. At December 31, 2002, $21.4 million was outstanding under the Partnership Credit Facility. Total credit available to be drawn at December 31, 2002 was approximately $38.6 million.

The Operating Company may prepay all loans at any time without penalty. The Operating Partnership will be required to reduce all working capital borrowings under the revolving credit facility to zero for a period of at least 15 consecutive days once each calendar year.

Indebtedness under the credit facility bears interest, at the Operating Company's option, at either (i) the higher of the federal funds rate plus 0.50% or the prime rate as announced by lender plus an applicable margin of 0.375% to 1.375% or (ii) at a rate equal to LIBOR plus an applicable margin ranging from 1.75% per annum to 2.75% per annum depending on the Partnership's ratio of Funded Debt (as defined in the Partnership Credit Facility) to EBITDA (as defined in the Partnership Credit Facility) for the four most recently completed fiscal quarters. For the year ended December 31, 2002, the weighted average interest rate was 3.58%.

The Operating Company incurs a commitment fee on the unused portion of the credit facility at a rate ranging from 25.0 to 50.0 basis points based upon the ratio of our Funded Debt (as defined in the Partnership Credit Facility) to EBITDA (as defined in the Partnership Credit Facility) for the four most recently completed fiscal quarters. The Partnership Credit Facility matures in May 2005. At that time, both the revolving and term loan credit facilities will terminate and all outstanding amounts thereunder will be due and payable.

The Partnership Credit Facility contains various covenants limiting the Partnership's ability to:

•: Incur indebtedness;
•: Grant certain liens;
•: Make certain loans, acquisitions and investments;
•: Amend our material agreements, including agreements with MarkWest Hydrocarbon;
•: Acquire another company;
•: Enter into a merger, consolidation or sale of assets; or
•: Make distributions in excess of Available Cash (as defined in the Partnership Agreement) for the preceding fiscal quarter.

The Partnership Credit Facility also contains covenants requiring the Operating Company to maintain:

•: A ratio of not less than 3.50:1.00 of EBITDA to interest expense for the prior fiscal quarter;

•: A ratio of not more than 3.50:1.00 of total debt to EBITDA for the prior fiscal quarter; and
•: A minimum net worth of $40 million, subject to adjustment for equity issuances.

The Partnership and the subsidiaries of the Operating Company serve as joint and several guarantors of any obligations under the Partnership Credit Facility. The guarantees are full and unconditional. The Partnership Credit Facility is secured by substantially all the assets of the Partnership and its subsidiaries.

Scheduled Debt Maturities

Scheduled debt maturities as of December 31, 2002, were as follows (in thousands):

2003	$	—
2004		—
2005		21,400
2006		—
2007		—
2008 and thereafter		—

Total debt outstanding	$	21,400

5. Significant Customers and Concentration of Credit Risk

For the year ended December 31, 2002, sales to MarkWest Hydrocarbon accounted for 37% of total revenues. For the year ended December 31, 2001, sales to two customers accounted for 16% and 10%, respectively, of total revenues. For the year ended December 31, 2000, sales to two customers accounted for 14% and 12%, respectively, of total revenues.

Financial instruments that potentially subject us to concentrations of credit risk consist principally of trade accounts receivable. Our primary customer is MarkWest Hydrocarbon. Consequently, matters affecting the business and financial condition of MarkWest Hydrocarbon—including its operations, management, customers, vendors and the like—have the potential to impact, both positively and negatively, our credit exposure. Outside of MarkWest Hydrocarbon, our customers are concentrated within the Appalachian basin and Michigan geographic areas and the retail propane, refining and petrochemical industries. Consequently, changes within these regions and/or industries also have the potential to impact, both positively and negatively, our credit exposure.

6. Commodity Price Risk Management

Commodity Price

Our primary risk management objective is to reduce volatility in our cash flows. Our hedging approach uses a statistical method that analyzes momentum and average pricing over time, and various fundamental data such as industry inventories, industry production, demand and weather. A committee, which includes members of senior management of our general partner, oversees all of our hedging activity.

We 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, but only occasionally used. 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 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 are similarly insulated against unfavorable changes in such prices.

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 are generally unable to hedge our basis risk for NGL products. 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 hedge our NGL product sales by selling forward propane or crude oil. As of December 31, 2002, we have hedged NGL product sales as follows:

		Year Ending December 31, 2003
NGL Volumes Hedged Using Crude Oil
	NGL gallons		3,731,000
	NGL sales price per gallon	$	0.47
NGL Volumes Hedged Using Propane
	NGL gallons		1,260,000
	NGL sales price per gallon	$	0.40
Total NGL Volumes Hedged
	NGL gallons		4,991,000
	NGL sales price per gallon	$	0.45

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.

Interest Rate

We are exposed to changes in interest rates, primarily as a result of our long-term debt with floating interest rates. We may 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 December 31, 2002, 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.

7. Adoption of SFAS No. 133

The MarkWest Hydrocarbon Midstream Business adopted SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended, on January 1, 2001. In accordance with the transition provisions of SFAS No. 133, the MarkWest Hydrocarbon Midstream Business recorded on that date a $1.3 million net-of-tax cumulative effect gain to other comprehensive income to recognize at fair value all derivatives that are designated as cash-flow hedging instruments.

SFAS No. 133 establishes accounting and reporting standards requiring derivative instruments to be recorded in the balance sheet as either an asset or liability measured at fair value. Changes in the derivative instruments' fair value are recognized in earnings unless specific hedge accounting criteria are met.

SFAS No. 133 allows hedge accounting for fair-value and cash-flow hedges. A fair-value hedge applies to a recognized asset or liability or an unrecognized firm commitment. A cash-flow hedge applies to a forecasted transaction or a variable cash flow of a recognized asset or liability. SFAS No. 133 provides that the gain or loss on a derivative instrument designated and qualifying as a fair-value hedging instrument as well as the offsetting loss or gain on the hedged item be recognized currently in earnings in the same accounting period. SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash-flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. (The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings.) Effectiveness is evaluated by the derivative instrument's ability to generate offsetting changes in fair value or cash flows to the hedged item. The MarkWest Hydrocarbon Midstream Business formally documents, designates and assesses the effectiveness of transactions receiving hedge accounting treatment.

The MarkWest Hydrocarbon Midstream Business entered into fixed-price contracts for the sale of NGL products and fixed-price contracts for the purchase of natural gas (designated as cash flow hedges) and NGL products (designated as fair value hedges). At January 1, 2001, the MarkWest Hydrocarbon Midstream Business recorded a risk management asset of $2.1 million and a deferred tax liability of $0.7 million, resulting in a $1.3 million gain reported in other comprehensive income.

8. Income Taxes

The provision for income taxes is comprised of the following:

		Years Ended December 31,
		2002 (As Restated. See Note 15)			2001			2000
		(in thousands)
Current taxes due to (from) parent:
	Federal	$	(1,252	)	$	(1,197	)	$	2,345
	State		(283	)		(271	)		509

	Total current due to (from) parent	$	(1,535	)	$	(1,468	)	$	2,854

Deferred:
	Federal	$	1,406		$	2,722		$	2,390
	State		190			370			449
	Change in tax status		(17,236	)

	Total deferred		(15,640	)		3,092			2,839

	Total provision (benefit) for income taxes	$	(17,175	)	$	1,624		$	5,693

The deferred tax liabilities (assets) are comprised of the tax effect of the following at:

		Years Ended December 31,
		2001			2000
		(in thousands)
Property and equipment		$	15,158		$	12,015
Accrued liabilities			534			—

	Total deferred tax liability		15,692			12,015

Alternative minimum tax credit carry forward			(52	)		—

	Total deferred tax asset		(52	)		—

Net deferred tax liability		$	15,640		$	12,015

As further described in Note 15, the Midstream Business recorded a non-cash adjustment of $17.2 million to eliminate deferred income tax liabilities that existed at the date of conveyance of the Midstream Business from MarkWest Hydrocarbon to the Partnership. Accordingly, the Midstream Business has recorded a benefit to the deferred tax provision for the year ended December 31, 2002, which increased net income by $17.2 million.

The differences between the provision for income taxes at the statutory rate and the actual provision for income taxes are summarized as follows:

		Year Ended December 31,
		2002 (As Restated. See Note 15)			2001		2000
		(in thousands)
Income tax at statutory rate		$	53		$	1,432	$	4,921
State income taxes, net of federal benefit			8			192		772
	Change in tax status		(17,236	)		—		—

	Total provision (benefit) for income taxes	$	(17,175	)	$	1,624	$	5,693

9. Long-Term Incentive Plan and Stock Compensation Plan

Long-Term Incentive Plan

Our general partner has adopted the MarkWest Energy Partners, L.P. Long-Term Incentive Plan for employees and directors of our general partner and its affiliates. The long-term incentive plan consists of two components, restricted units and unit options. The long-term incentive plan currently permits the grant of awards covering an aggregate of 500,000 common units, 200,000 of which may be awarded in the form of restricted units and 300,000 of which may be awarded in the form of unit options. The compensation committee of our general partner's board of directors administers the plan.

Restricted Units

A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit, or in the discretion of the compensation committee, cash equivalent to the value of a common unit. These restricted units are entitled to receive distribution equivalents, which represent cash equal to the amount of cash distributions made on common units during the vesting period, from the date of grant and will vest over a period of four years, with 25% of the grant vesting at the end of each of the second and third years and 50% vesting at the end of the fourth year. The restricted units will vest upon a change of control of our general partner, MarkWest Hydrocarbon or us.

If a grantee's employment or membership on the board of directors terminates for any reason, the grantee's restricted units will be automatically forfeited unless, and to the extent, the compensation committee provides otherwise. Common units to be delivered upon the vesting of restricted units may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units, the total number of common units outstanding will increase. The compensation committee, in its discretion, may grant distribution rights with respect to any additional restricted unit grants.

For the year ended December 31, 2002, 55,587 phantom units had been granted to officers, employees and directors of our general partner and its affiliates. Of the amount granted, 5,357 units had subsequently been forfeited leaving 50,230 restricted units outstanding as of December 31, 2002. The Partnership recognized $0.1 million in compensation expense associated with these grants in 2002. The fair market value associated with these grants was $1.2 million on December 31, 2002.

Unit Options

The long-term incentive plan currently permits the grant of options covering common units. The compensation committee may determine to make grants under the plan to employees and directors containing such terms as the committee shall determine. Unit options will have an exercise price that, in the discretion of the committee, may be less than, equal to or more than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the compensation committee. In addition, the unit options will become exercisable upon a change in control of us, our general partner, MarkWest Hydrocarbon or upon the achievement of specified financial objectives.

Upon exercise of a unit option, our general partner will acquire common units in the open market or directly from us or any other person or use common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring these common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.

As of December 31, 2002, no options had been granted under the long-term incentive plan.

Stock-Based Compensation Plan

Certain employees of MarkWest Hydrocarbon dedicated to or otherwise principally supporting MarkWest Energy Partners, L.P. receive stock-based compensation awards from MarkWest Hydrocarbon. We apply APB Opinion No. 25,Accounting for Stock Issued to Employees, and related Interpretations in accounting for those employees principally supporting the Partnership who participate in MarkWest Hydrocarbon's plan. Accordingly, no compensation cost has been recognized for the fixed stock option plan.

Under its 1996 Stock Incentive Plan, MarkWest Hydrocarbon may grant options to its employees for up to 925,000 shares of common stock in the aggregate. Under this plan, the exercise price of each option equals the market price of MarkWest Hydrocarbon's stock on the date of the grant, and an option's maximum term is ten years. Options are granted periodically throughout the year and vest at the rate of 25% per year for options granted in 1999 and after and 20% per year for options granted prior to 1999.

The fair value of each option granted in 2002, 2001, and 2000 was estimated using the Black-Scholes option pricing model. The following assumptions were used to compute the weighted average fair market value of options granted.

	2002		2001		2000
Expected life options	6 years		6 years		6 years
Risk free interest rates	3.54	%	4.84	%	5.93	%
Estimated volatility	52	%	52	%	43	%
Dividend yield	0.0	%	0.0	%	0.0	%

A summary of the plan activity of those employees principally supporting the Partnership who participated in MarkWest Hydrocarbon's fixed stock option plan as of December 31, 2002, 2001 and 2000, and, changes during the years ended on those dates are presented below:

	2002				2001				2000
	Options		Weighted- Average Exercise Price		Options		Weighted- Average Exercise Price		Options	Weighted- Average Exercise Price
Fixed Options
Outstanding at beginning of year	343,849		$	9.21	325,374		$	9.29	270,721	$	9.14
Change in employees considered to be primarily supporting the Partnership	(25,237	)		9.21	—			—	—		—
Granted	—			—	19,778			7.84	54,653		10.08
Exercised	—			—	—			—	—		—
Cancelled	—			—	(1,303	)		8.34	—		—

Outstanding at end of year	318,612		$	9.21	343,849		$	9.21	325,374	$	9.29

Options exercisable at December 31, 2002, 2001 and 2000, respectively	256,886				218,482				156,516
Weighted-average fair value of options granted during the year			$	0.00			$	3.84		$	4.94

The following table summarizes information about outstanding and exercisable MarkWest Hydrocarbon fixed stock options, held by employees principally supporting the Partnership, at December 31, 2002:

	Options Outstanding
	Options Outstanding				Options Exercisable
		Weighted- Average Remaining Contractual Life			Options Exercisable
Range of Exercise Prices	Number Outstanding at 12/31/02	Weighted- Average Remaining Contractual Life	Weighted- Average Exercise Price		Number Exercisable At 12/31/02	Weighted- Average Exercise Price
$ 5.38 to $ 7.65	86,453	4.23	$	6.68	66,421	$	6.63
$ 7.86 to $10.00	89,597	4.73		9.14	70,901		9.25
$10.50 to $10.50	28,318	5.94		10.50	22,657		10.50
$10.75 to $10.75	88,266	4.94		10.75	83,887		10.75
$11.25 to $11.38	25,978	7.93		11.25	13,020		11.25

$ 5.38 to $11.38	318,612	5.02	$	9.21	256,886	$	9.27

10. Commitments and Contingencies

Legal

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

Lease Obligations

We have various non-cancelable operating lease agreements for equipment expiring at various times through fiscal 2015. Annual rent expense under these operating leases was $0.6 million for each period presented. Our minimum future lease payments under these operating leases as of December 31, 2002, are as follows (in thousands):

2003	$	527
2004		527
2005		527
2006		411
2007		179
2008 and thereafter		324

Total	$	2,495

11. Partners' Capital

As of December 31, 2002, partners' capital consisted of 2,415,000 common units representing a 43.7% limited partner interest, 3,000,000 subordinated units representing a 54.3% limited partner interest and a 2% general partner interest. Affiliates of MarkWest Hydrocarbon, in the aggregate, owned a 46.7% interest in the Partnership consisting of 2,479,762 subordinated units and a 2% general partner interest.

The Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P. (the Partnership Agreement) contains specific provisions for the allocation of net income and losses to each of the partners for the purposes of maintaining the partner capital accounts.

Cash distributions

The Partnership will distribute 100% of its Available Cash (as defined in the Partnership Agreement) within 45 days after the end of each quarter to unitholders of record and to the general partner. Available Cash is generally defined as all cash and cash equivalents of the Partnership on hand at the end of each quarter less reserves established by the general partner for future requirements plus all cash on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. The general partner has the discretion to establish cash reserves that are necessary or appropriate to (i) provide for the proper conduct of our business; (ii) comply with applicable law, any of our debt instruments or other agreements; or (iii) provide funds for distributions to unitholders and the general partner for any one or more of the next four quarters. Working capital borrowings are generally borrowings that are made under our working capital facility and in all cases are used solely for working capital purposes such as to pay distributions to partners.

During the subordination period (as defined in the Partnership Agreement and discussed further below), our quarterly distributions of available cash will be made in the following manner:

•: First, 98% to the common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.50 plus any arrearages from prior quarters;
•: Second, 98% to the subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.50 plus any arrearages from prior quarters; and
•: Third, 98% to all units, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.55 per quarter.

Our general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:

		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	Unitholders		General Partner
Minimum Quarterly Distribution	$0.50	98	%	2	%
First Target Distribution	up to $0.55	98	%	2	%
Second Target Distribution	above $0.55 up to $0.625	85	%	15	%
Third Target Distribution	above $0.625 up to $0.75	75	%	25	%
Thereafter	above $0.75	50	%	50	%

The quarterly cash distributions applicable to 2002 were as follows:

Quarter Ended	Record Date	Payment Date	Amount Per Unit
June 30, 2002	August 13, 2002	August 15, 2002	$	0.21
September 30, 2002	October 31, 2002	November 14, 2002	$	0.50
December 31, 2002	January 31, 2003	February 14, 2003	$	0.52

Subordination period

During the subordination period, the common units have the right to receive distributions of available cash in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. The subordination period ends on the first day of any quarter beginning after June 30, 2009 when certain financial tests (defined in the Partnership Agreement) are met. Additionally, a portion of the subordinated units may convert earlier into common units on a one-for-one basis if additional financial tests (defined in the Partnership Agreement) are met. Generally, the earliest possible date by which all subordinated units may be converted into common units is June 30, 2007. When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages.

12. Employee Benefit Plan

All employees dedicated to, or otherwise principally supporting, MarkWest Energy Partners are employees of MarkWest Hydrocarbon and substantially all of these employees are participants in MarkWest Hydrocarbon's defined contribution plan. MarkWest Energy Partners' costs related to this plan were $0.1 million, $0.1 million and $0.2 million for the years ended December 31, 2002, 2001 and 2000, respectively. The plan is discretionary, with annual contributions determined by MarkWest Hydrocarbon's Board of Directors.

13. Quarterly Results of Operations (Unaudited)

The following summarizes certain quarterly results of operations:

	Three Months Ended
	March 31		June 30(1)		September 30		December 31
	(in thousands, except per unit amounts)
*2002*
Revenue	$	27,440	$	14,463	$	13,868	$	14,475
Income (loss) from operations	$	1,422	$	137	$	2,906	$	1,511
Net income (loss)	$	690	$	17,452	$	2,526	$	1,121
Net income per limited partner unit(1)	$	0.23	$	4.35	$	0.46	$	0.20
Net income per limited partner unit assuming dilution(1)	$	0.23	$	4.34	$	0.45	$	0.20

	MarkWest Hydrocarbon Midstream Business
	Three Months Ended
	March 31		June 30			September 30			December 31
	(in thousands, except per unit amounts)
*2001*
Revenue	$	35,959	$	16,903		$	19,223		$	21,590
Income (loss) from operations	$	3,053	$	(306	)	$	(191	)	$	2,961
Net income (loss)	$	1,690	$	(420	)	$	(382	)	$	1,698
Net income (loss) per limited partner unit(1)	$	0.56	$	(0.14	)	$	(0.13	)	$	0.57
Net income (loss) per limited partner unit assuming dilution(1)	$	0.56	$	(0.14	)	$	(0.13	)	$	0.57

(1): As Restated and adjusted to reflect the $17.2 million deferred tax adjustment in the three months ended June 30, 2002, as discussed in Note 15. Amounts as previously reported were as follows:

	MarkWest Hydrocarbon Midstream Business(1)					Partnership
	MarkWest Hydrocarbon Midstream Business(1)							Three Months Ended
	January 1 through March 31		April 1 through May 23			May 24 through June 30		Three Months Ended
	January 1 through March 31		April 1 through May 23			May 24 through June 30		September 30		December 31
	(in thousands, except per unit amounts)
*2002*
Revenue	$	27,440	$	9,603		$	4,860	$	13,868	$	14,475
Income (loss) from operations	$	1,422	$	(803	)	$	940	$	2,906	$	1,512
Net income (loss)	$	690	$	(594	)	$	810	$	2,526	$	1,121
Net income per limited partner unit		NA		NA		$	0.15	$	0.46	$	0.20
Net income per limited partner unit assuming dilution		NA		NA		$	0.15	$	0.46	$	0.20

	MarkWest Hydrocarbon Midstream Business(1)
	Three Months Ended
	March 31		June 30			September 30			December 31
	(in thousands, except per unit amounts)
*2001*
Revenue	$	35,959	$	16,903		$	19,223		$	21,590
Income (loss) from operations	$	3,053	$	(306	)	$	(191	)	$	2,961
Net income (loss)	$	1,690	$	(420	)	$	(382	)	$	1,698
Net income per limited partner unit		NA		NA			NA			NA
Net income per limited partner unit assuming dilution		NA		NA			NA			NA

NA—Not applicable

(1): The MarkWest Hydrocarbon Midstream Business did not issue any units. Accordingly, no information on a per unit basis is available.

14. Subsequent Event

On March 24, 2003, we entered into an agreement to merge with Pinnacle Natural Gas Company and certain affiliates for approximately $38 million. The acquired assets, primarily located in Texas, are comprised of three lateral natural gas pipelines and eighteen gathering systems. The acquisition will be financed primarily through borrowings under our credit facility, which was recently expanded by $15 million.

15. Restatement

statement of operations and statement of cash flows was presented for the period from May 24, 2002 (the date the MarkWest Hydrocarbon Midstream Business was conveyed to the Partnership) through December 31, 2002.

As indicated in Note 1, the conveyance of the MarkWest Hydrocarbon Midstream Business from MarkWest Hydrocarbon to the Partnership represented a reorganization of entities under common control and was recorded at historical cost. Consequently, the Partnership has concluded these statements should be presented on a combined basis for the year ended December 31, 2002.

In addition, the Partnership had previously reported net income per limited partner unit for the period from May 24, 2002 through December 31, 2002. In its restated financial statements, the Partnership has restated net income per limited partner unit to report such amount for the year ended December 31, 2002. In addition, the Partnership has now reported net income per limited partner unit for the years ended December 21, 2001 and 2000. The weighted average amounts outstanding used in the calculation of net income per limited partner unit for the years ended December 31, 2001 and 2000 retroactively reflect the 3,000,000 subordinated units issued by the Partnership in connection with the conveyance of the MarkWest Hydrocarbon Midstream Business to the Partnership. The units used in the 2002 calculation represent the weighted average of the aforementioned 3,000,000 subordinated units and the 2,415,000 common units issued in the May 24, 2002 initial public offering. Net income used in the 2002 calculation has been reduced by the General Partner's interest in net income.

In its restated financial statements for the year ended December 31, 2002, the Midstream Business recorded a non-cash adjustment of $17.2 million to eliminate deferred income tax liabilities that existed at the date of conveyance of the MarkWest Hydrocarbon Midstream Business from MarkWest Hydrocarbon to the Partnership. Accordingly, the Midstream Business has recorded a benefit to the deferred tax provision for the year ended December 31, 2002 which increased net income by $17.2 million. This adjustment resulted from the change in the tax status of the MarkWest Hydrocarbon Midstream Business from a taxable entity to a Partnership, which is not subject to taxation.

In addition, the Partnership had previously reported certain captions in the consolidated and combined statements of changes in capital net of the following: (i) distribution of cash to MarkWest Hydrocarbon in connection with the conveyance, (ii) change in parent advances, and (iii) the net liabilities not assumed by the partnership. The Partnership has now reported these captions on a gross basis and separately disclosed the amounts.

The following sets forth the effects of the restatements discussed above.

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

			As Previously Reported
			Period From Commencement of Operations (May 24, 2002) Through December 31, 2002 Partnership			Period From January 1, 2002 Through May 23, 2002 (MarkWest Hydrocarbon Midstream Business)			Adjustments			Total Year Ended December 31, 2002 (As Restated)
Revenues:
	Sales to affiliates		$	26,093		$	—		$	—		$	26,093
	Sales to unaffiliated parties			7,110			37,043						44,153

		Total revenues		33,203			37,043						70,246
Operating expenses:
	Purchased product costs			12,308			26,598						38,906
	Facility expenses			9,396			5,705						15,101
	Selling, general and administrative expenses			3,077			2,206						5,283
	Depreciation			3,064			1,916						4,980

		Total operating expenses		27,845			36,425						64,270

		Income from operations		5,358			618						5,976
Other income and (expenses):
	Interest expense, net			(953	)		(461	)					(1,414	)
	Miscellaneous income			52			—						52

	Income before income taxes			4,457			157						4,614

Provision (benefit) for income taxes:
	Current due to (from) parent			—			(1,535	)					(1,535	)
	Deferred			—			1,596			(17,236	)		(15,640	)

		Provision for income taxes		—			61			(17,236	)		(17,175	)

		Net income	$	4,457		$	96		$	17,236		$	21,789

General partner's interest in net income			$	89								$	89

Limited partners' interest in net income			$	4,368								$	21,700

Net income per limited partner unit			$	0.81								$	4.86

Weighted average units outstanding				5,415									4,469

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS

(in thousands)

				As Previously Reported
				Period From Commencement of Operations (May 24, 2002) Through December 31, 2002 Partnership			Period From January 1, 2002 Through May 23, 2002 (MarkWest Hydrocarbon Midstream Business)			Adjustments			Total Year Ended December 31, 2002 (As Restated)
Cash flows from operating activities:
Net income				$	4,457		$	96		$	17,236		$	21,789
Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation			3,064			1,916						4,980
		Amortization of deferred financing costs included in interest expense			291			—						291
		Deferred income taxes			—			1,596			(17,236	)		(15,640	)
		Other			(41	)		(252	)					(293	)
	Changes in operating assets and liabilities, net of working capital assumed:
		(Increase) decrease in receivables			(3,808	)		3,765						(43	)
		(Increase) decrease in inventories			(116	)		2,449						2,333
		(Increase) decrease in prepaid replacement natural gas and other assets			(320	)		5,253						4,933
		Increase in accounts payable and accrued liabilities			4,292			7,770						12,062
		Increase in long-term replacement natural gas payable			—			3,090						3,090

			Net cash provided by operating activities		7,819			25,683			—			33,502
Cash flows from investing activities:
		Capital expenditures			(1,647	)		(498	)					(2,145	)
		Proceeds from sale of assets			89			—						89

			Net cash used in investing activities		(1,558	)		(498	)		—			(2,056	)
Cash flows from financing activities:
		Proceeds from initial public offering, net			43,625			—						43,625
		Distribution to MarkWest Hydrocarbon			(63,476	)		—						(63,476	)
		Distributions to unitholders			(3,923	)		—						(3,923	)
		Payments for debt issuance costs			(1,111	)		—						(1,111	)
		Proceeds from long-term debt			23,400			—						23,400
		Repayment of long-term debt			(2,000	)		—						(2,000	)
		Net distributions to parent			—			(24,218	)					(24,218	)
		Debt from parent			—			(967	)					(967	)

			Net cash used in financing activities		(3,485	)		(25,185	)		—			(28,670	)

Net increase in cash					2,776			—			—			2,776
Cash and cash equivalents at beginning of period					—			—			—			—

Cash and cash equivalents at end of period				$	2,776		$	—		$	—		$	2,776

The following sets forth the restated net income per limited partner unit for the years ended December 31, 2002, 2001 and 2000.

	2002		2001		2000
	(in thousands, except per unit amounts)
Limited partners' interest in net income as previously reported	$	4,368	$	—	$	—

Limited partners' interest in net income as restated	$	21,700	$	2,586	$	8,781

Basic weighted average units outstanding as previously reported		5,415		—		—

Basic weighted average units outstanding as restated		4,469		3,000		3,000

Diluted weighted average units outstanding, as previously reported		—		—		—

Diluted weighted average units outstanding, as restated		4,493		3,000		3,000

Basic net income per limited partner unit as previously reported	$	0.81	$	—	$	—

Basic net income per limited partner unit as restated	$	4.86	$	0.86	$	2.93

Diluted net income as previously reported	$	—	$	—	$	—

Diluted net income as restated	$	4.83	$	0.86	$	2.93

The following sets forth the restated captions in the consolidated statement of changes in capital for the year ended December 31, 2002:

		As Previously Reported			As Restated
		(in thousands)
Net Parent Investment:
	Net income applicable to the period from January 1 to May 23, 2002	$	96		$	17,332
	Net change in parent advances		—			(24,218	)
	Adjustment to reflect net liabilities not assumed by the Partnership		(47,142	)		23,316
	Book value of net assets contributed by MarkWest Hydrocarbon to the Partnership		(17,415	)		(80,891	)

	Adjustments to net parent investment	$	(64,461	)	$	(64,461	)

Limited Partners' Subordinated Units:
	Book value of net assets contributed by MarkWest Hydrocarbon to the Partnership	$	17,067		$	79,273
	Distribution to MarkWest Hydrocarbon		—			(62,206	)

	Adjustments to Limited Partners' Subordinated Units	$	17,067		$	17,067

General Partner Interest:
	Book value of net assets contributed by MarkWest Hydrocarbon to the Partnership	$	348		$	1,618
	Distribution to MarkWest Hydrocarbon		—			(1,270	)

	Adjustments to General Partner Interest	$	348		$	348

Total Partners' Capital:
	Net income applicable to the period from January 1 through May 23, 2002	$	96		$	17,332
	Net change in parent advances		—			(24,218	)
	Adjustment to reflect net liabilities not assumed by the Partnership		(47,142	)		23,316
	Distribution to MarkWest Hydrocarbon		—			(63,476	)

	Adjustments to Total Partners' Capital	$	(47,046	)	$	(47,046	)

PART III

ITEM 14. 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 (whom 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 December 31, 2002, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of December 31, 2002, our disclosure controls and procedures were effective.

There were no changes in our internal control over financial reporting that occurred during our fiscal quarter ended December 31, 2002 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

As discussed in Note 15 to the Consolidated and Combined Financial Statements included herein, we restated our 2002 financial statements. The circumstances causing the restatement arose due to the complex nature of the conveyance transaction as described in Note 1 to the Consolidated and Combined Financial Statements. As a result of such restatement, we reevaluated the effectiveness of our disclosure controls and procedures. Based upon such reevaluation, and despite such restatement, we do not believe that our disclosure controls and procedures are ineffective or that any changes to our disclosure controls and procedures or our internal controls over financial reporting are necessary or appropriate.

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a)

The following documents are filed as part of this report:

(1): Financial Statements:

You should read the Index to Consolidated and Combined Financial Statements included in Item 8 of this Form 10-K for a list of all financial statements filed as a part of this report.

(2): Financial Statement Schedules: None required.
(3): Exhibits:

Exhibit Number		Description
3.1(1)		Certificate of Limited Partnership of MarkWest Energy Partners, L.P.
3.2(6)		Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P. dated as of May 24, 2002
3.3(1)		Certificate of Formation of MarkWest Energy Operating Company, L.L.C.
3.4(2)		Amended and Restated Limited Liability Company Agreement of MarkWest Energy Operating Company, L.L.C. dated as of May 24, 2002
3.5(1)		Certificate of Formation of MarkWest Energy GP, L.L.C.
3.6(4)		Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C. dated as of May 24, 2002
10.1(7)		Credit Agreement dated as of May 20, 2002 among MarkWest Energy Operating Company, L.L.C (as the Borrower), MarkWest Energy Partners, L.P. (as a Guarantor) and various lenders
10.3(5)		Contribution, Conveyance and Assumption Agreement dated as of May 24, 2002 among MarkWest Energy Partners, L.P.; MarkWest Energy Operating Company, L.L.C.; MarkWest Energy GP, L.L.C.; MarkWest Michigan, Inc.; MarkWest Energy Appalachia, L.L.C.; West Shore Processing Company, L.L.C.; Basin Pipeline, L.L.C.; and MarkWest Hydrocarbon, Inc.
10.4(2)		MarkWest Energy GP, L.L.C. Long-Term Incentive Plan
10.5(4)		Omnibus Agreement dated of May 24, 2002 among MarkWest Hydrocarbon, Inc., MarkWest Energy GP, L.L.C; MarkWest Energy Partners, L.P. and MarkWest Energy Operating Company, L.L.C.
10.6(5)+		Fractionation, Storage and Loading Agreement dated as of May 24, 2002 between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
10.7(5)+		Gas Processing Agreement dated as of May 24, 2002 between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
10.8(5)+		Pipeline Liquids Transportation Agreement dated as of May 24, 2002 between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
10.9(4)		Natural Gas Liquids Purchase Agreement dated as of May 24, 2002 between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
10.10(7)+		Gas Processing Agreement (Maytown) dated as of May 28, 2002 between Equitable Production Company and MarkWest Hydrocarbon, Inc.

10.11(7)		Amendment to Gas Processing Agreement (Maytown) dated as of March 26, 2002 between Equitable Production Company and MarkWest Hydrocarbon, Inc.
21.1(2)		List of subsidiaries
23.1*		Consent of PricewaterhouseCoopers LLP
31.1*		Rule 13a-14(a) Certification of Chief Executive Officer of MarkWest Energy Partners' General Partner
31.2*		Rule 13a-14(a) Certification of Chief Financial Officer of MarkWest Energy Partners' General Partner
32.1*		Section 1350 Certification of Chief Executive Officer of MarkWest Energy Partners' General Partner
32.2*		Section 1350 Certification of Chief Financial Officer of MarkWest Energy Partners' General Partner

(1): Incorporated by reference to Form S-1 Registration Statement, filed January 31, 2002.
(2): Incorporated by reference to Amendment No. 1 to Form S-1 Registration Statement, filed March 22, 2002.
(3): Incorporated by reference to Amendment No. 2 to Form S-1 Registration Statement, filed April 16, 2002.
(4): Incorporated by reference to Amendment No. 3 to Form S-1 Registration Statement, filed April 25, 2002.
(5): Incorporated by reference to Amendment No. 4 to Form S-1 Registration Statement, filed May 1, 2002.
(6): Incorporated by reference to Amendment No. 5 to Form S-1 Registration Statement, filed May 8, 2002.
(7): Incorporated by reference to Amendment No. 6 to Form S-1 Registration Statement, filed May 14, 2002.
+: Application has been made to the Securities and Exchange Commission for confidential treatment of certain provisions of these exhibits. Omitted material for which confidential treatment has been requested and has been filed separately with the Securities and Exchange Commission.
*: Filed herewith.
(b): Reports on Form 8-K

None.

SIGNATURES

Pursuant to the requirements of section 13 or 15(d) 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, in the City of Englewood, State of Colorado, on January 21, 2004.

		MARKWEST ENERGY PARTNERS, L.P. (Registrant)
		By:MARKWEST ENERGY GP, L.L.C., Its General Partner
		By:	/s/ DONALD C. HEPPERMANN Donald C. Heppermann Senior Executive Vice President, Chief Financial Officer, Secretary and Director

Exhibit Index

Exhibit Number		Description
3.1(1)		Certificate of Limited Partnership of MarkWest Energy Partners, L.P.
3.2(6)		Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P. dated as of May 24, 2002
3.3(1)		Certificate of Formation of MarkWest Energy Operating Company, L.L.C.
3.4(2)		Amended and Restated Limited Liability Company Agreement of MarkWest Energy Operating Company, L.L.C. dated as of May 24, 2002
3.5(1)		Certificate of Formation of MarkWest Energy GP, L.L.C.
3.6(4)		Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C. dated as of May 24, 2002
10.1(7)		Credit Agreement dated as of May 20, 2002 among MarkWest Energy Operating Company, L.L.C (as the Borrower), MarkWest Energy Partners, L.P. (as a Guarantor) and various lenders
10.3(5)		Contribution, Conveyance and Assumption Agreement dated as of May 24, 2002 among MarkWest Energy Partners, L.P.; MarkWest Energy Operating Company, L.L.C.; MarkWest Energy GP, L.L.C.; MarkWest Michigan, Inc.; MarkWest Energy Appalachia, L.L.C.; West Shore Processing Company, L.L.C.; Basin Pipeline, L.L.C.; and MarkWest Hydrocarbon, Inc.
10.4(2)		MarkWest Energy GP, L.L.C. Long-Term Incentive Plan
10.5(4)		Omnibus Agreement dated of May 24, 2002 among MarkWest Hydrocarbon, Inc., MarkWest Energy GP, L.L.C; MarkWest Energy Partners, L.P. and MarkWest Energy Operating Company, L.L.C.
10.6(5)+		Fractionation, Storage and Loading Agreement dated as of May 24, 2002 between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
10.7(5)+		Gas Processing Agreement dated as of May 24, 2002 between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
10.8(5)+		Pipeline Liquids Transportation Agreement dated as of May 24, 2002 between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
10.9(4)		Natural Gas Liquids Purchase Agreement dated as of May 24, 2002 between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
10.10(7)+		Gas Processing Agreement (Maytown) dated as of May 28, 2002 between Equitable Production Company and MarkWest Hydrocarbon, Inc.
10.11(7)		Amendment to Gas Processing Agreement (Maytown) dated as of March 26, 2002 between Equitable Production Company and MarkWest Hydrocarbon, Inc.
21.1(2)		List of subsidiaries
23.1*		Consent of PricewaterhouseCoopers LLP
31.1*		Rule 13a-14(a) Certification of Chief Executive Officer of MarkWest Energy Partners' General Partner
31.2*		Rule 13a-14(a) Certification of Chief Financial Officer of MarkWest Energy Partners' General Partner

32.1*		Section 1350 Certification of Chief Executive Officer of MarkWest Energy Partners' General Partner
32.2*		Section 1350 Certification of Chief Financial Officer of MarkWest Energy Partners' General Partner

(1): Incorporated by reference to Form S-1 Registration Statement, filed January 31, 2002.
(2): Incorporated by reference to Amendment No. 1 to Form S-1 Registration Statement, filed March 22, 2002.
(3): Incorporated by reference to Amendment No. 2 to Form S-1 Registration Statement, filed April 16, 2002.
(4): Incorporated by reference to Amendment No. 3 to Form S-1 Registration Statement, filed April 25, 2002.
(5): Incorporated by reference to Amendment No. 4 to Form S-1 Registration Statement, filed May 1, 2002.
(6): Incorporated by reference to Amendment No. 5 to Form S-1 Registration Statement, filed May 8, 2002.
(7): Incorporated by reference to Amendment No. 6 to Form S-1 Registration Statement, filed May 14, 2002.
+: Application has been made to the Securities and Exchange Commission for confidential treatment of certain provisions of these exhibits. Omitted material for which confidential treatment has been requested and has been filed separately with the Securities and Exchange Commission.
*: Filed herewith.

Markwest Energy Partners L P Inactive 10-K/A2002 FY Annual report (amended)