10-K 1 a2132402z10-k.htm FORM 10-K

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MarkWest Hydrocarbon, Inc. Form 10-K Table of Contents
Index to Consolidated Financial Statements

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

FORM 10-K

ý	Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2003.
o	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from to .

Commission File Number 1-11566

MARKWEST HYDROCARBON, INC.
(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)		84-1352233 (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 Stock, $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.

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

The aggregate market value of voting common stock held by non-affiliates of the registrant on June 30, 2003 was approximately $30.4 million.

The number of shares outstanding of the registrant's common stock as of February 29, 2004, was 9,706,401.

DOCUMENTS INCORPORATED BY REFERENCE

Information required by Part III, Items 10 through 14, of this Report, is incorporated by reference from the registrant's proxy statement, to be filed with the Commission not later than 120 days after the end of the fiscal year covered by this Form 10-K, pursuant to Regulation 14A with respect to the 2004 annual meeting of stockholders.

MarkWest Hydrocarbon, Inc.
Form 10-K
Table of Contents


PART I
	Items 1. and 2.	Business and Properties
	Item 3.	Legal Proceedings
	Item 4.	Submission of Matters to a Vote of Security Holders
PART II
	Item 5.	Market for the Registrant's Common Equity and Related Stockholder Matters
	Item 6.	Selected Financial Data
	Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk
	Item 8.	Financial Statements and Supplementary Data
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
	Item 9A.	Controls and Procedures
PART III
	Item 10.	Directors and Executive Officers of the Registrant
	Item 11.	Executive Compensation
	Item 12.	Security Ownership of Certain Beneficial Owners and Management
	Item 13.	Certain Relationships and Related Transactions
	Item 14.	Principal Accounting Fees and Services
PART IV
	Item 15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K

In this document, unless the context requires otherwise, references to "we," "us," "our," "MarkWest Hydrocarbon" or the "Company" are intended to mean MarkWest Hydrocarbon, Inc., and its consolidated subsidiaries.

Glossary of Terms

In addition, the following is a list of certain acronyms and terms used throughout the document:

Bbls		barrels
Btu		one British thermal unit, an energy measurement
Gal/d		gallons per day
MBbl		one thousand barrels
Mcf		one thousand cubic feet of natural gas
Mcfe		one thousand cubic feet of natural gas equivalent(1)
Mcf/d		one thousand cubic feet of natural gas per day
Mcfe/d		one thousand cubic feet of natural gas equivalent per day
MMBtu		one million British thermal units, an energy measurement
MMcf		one million cubic feet of natural gas
MMcfe		one million cubic feet of natural gas equivalent
MMcf/d		one million cubic feet of natural gas per day
NGLs		natural gas liquids, such as propane, butanes and natural gasoline
NA		not applicable

(1): One barrel of oil or NGLs is the energy equivalent of six Mcf of natural gas.

Forward-Looking Information

Statements included in this Annual Report on Form 10-K and documents incorporated by reference to this report that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. We use words such as "may," "believe," "estimate," "expect," "plan," "intend," "project," "anticipate," and similar expressions to identify forward-looking statements. We have based these forward-looking statements on our current expectations and projections about future events, activities or developments. Our actual results could differ materially from those discussed in our forward-looking statements. Forward-looking statements include statements relating to, among other things:

•: Our expectations regarding MarkWest Energy Partners, L.P.
•: Our ability to grow MarkWest Energy Partners, L.P.
•: Our ability to amend certain producer contracts.
•: Our expectations regarding natural gas, NGL product and prices.
•: Our efforts to increase fee-based contract volumes.
•: Our ability to manage our commodity price risk.
•: Our ability to maximize the value of our NGL output.
•: The adequacy of our general public liability, property, and business interruption insurance.
•: Our ability to comply with environmental and governmental regulations.

Important factors that could cause our actual results of operations or our actual financial condition to differ include, but are not necessarily limited to:

•: Changes in general economic conditions in regions in which our products are located.
•: The availability and prices of NGL and competing commodities.
•: The availability and prices of raw natural gas supply.
•: Our ability to negotiate favorable marketing agreements.
•: The risks that third party 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.
•: Competition from other NGL processors, including major energy companies.
•: Our ability to identify and consummate grass-roots projects or acquisitions complementary to our business.
•: Winter weather conditions.

Forward-looking statements involve many uncertainties that are beyond our ability to control. In many cases, we cannot predict what factors would cause actual results to differ materially from those indicated by the forward-looking statements.

PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General

We are an energy company primarily focused on growing MarkWest Energy Partners, L.P. (MarkWest Energy Partners or the Partnership), a publicly-traded limited partnership engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids; and the gathering and transportation of crude oil. We also market natural gas and natural gas liquids (NGLs).

Our assets consist almost exclusively of partnership interests in MarkWest Energy Partners. As of February 29, 2004, our partnership interests consisted of the following:

•: 2,469,496 subordinated units, representing a 34.6% limited partner interest in the Partnership; and a
•: 90.2% ownership interest in MarkWest Energy GP, L.L.C., the general partner of the Partnership, which owns a 2.0% general partner interest and all of the incentive distribution rights in the Partnership.

We were founded in 1988 as a partnership and later incorporated in Delaware. We completed our initial public offering in 1996.

Our common stock is traded on the American Stock Exchange under the symbol "MWP." Our executive offices are located at 155 Inverness Drive West, Suite 200, Englewood, Colorado 80112-5000.

Recent Developments

During the year ended December 31, 2003, we completed several important initiatives that accomplished the transformation of MarkWest Hydrocarbon into a company focused on increasing shareholder value through our ownership in MarkWest Energy Partners. Specifically, we discontinued our exploration and production business and MarkWest Energy Partners grew primarily through the acquisition of third-party midstream assets.

MarkWest Hydrocarbon Dispositions

Our three primary dispositions were the following:

•: We sold our San Juan Basin oil and gas producing properties in two separate sales during the second and third quarters of 2003. The San Juan Basin properties represented substantially all of our exploration and production business located in the United States. Net proceeds from the sales were approximately $55.3 million. We recognized a net pretax gain on the sales of approximately $23.3 million.
•: We sold our entire Canadian exploration and production business in two separate transactions during December 2003. Net proceeds from the sales were approximately $49.1 million. We recognized a net pretax loss on the sales of approximately $4.8 million.
•: We sold two of our three NGL terminals during the third quarter of 2003. Net proceeds were approximately $2.3 million. We recognized a net pretax loss on the sales of less than $0.1 million.

MarkWest Energy Partners Acquisitions

During 2003, MarkWest Energy Partners completed the following four acquisitions:

•: In March 2003, the Partnership completed the acquisition of $39.9 million of midstream assets in the Southwest. The acquired assets, primarily located in Texas, were comprised of (i) three lateral natural gas pipelines transporting natural gas under firm contracts to power plants and (ii) twenty gathering systems gathering more than 44 MMcf/d. One of the smaller gathering systems acquired was subsequently disposed of in December 2003 for an immaterial amount.
•: In September 2003, MarkWest Energy Partners acquired a 68-mile intrastate gas transmission pipeline near Lubbock, Texas for approximately $12.2 million.
•: In December 2003, the Partnership acquired a 167-mile gathering system, a processing plant and related compression facilities located in Oklahoma for approximately $38.0 million.
•: Also in December 2003, MarkWest Energy Partners acquired an intrastate crude oil pipeline in Michigan for approximately $21.3 million.

Reduction in Debt

Primarily as a result of the dispositions discussed above, we strengthened our balance sheet during 2003 by paying off our credit facility in its entirety in December 2003 and by aggregating $33.4 million in unrestricted on-hand cash (exclusive of MarkWest Energy Partners' cash balance) as of December 31, 2003. The debt on our balance sheet at December 31, 2003, is comprised entirely of MarkWest Energy Partners' outstanding debt.

Strategy

Our two-part strategy is to increase shareholder value by growing MarkWest Energy Partners and its cash distributions, and to improve the stability of our operating margins in our marketing segment.

We believe the primary opportunity to increase shareholder value is tied to our ability to successfully grow MarkWest Energy Partners. The Partnership's strategy is to increase distributable cash flow per unit by increasing utilization of its facilities, expanding existing operations through new construction, expanding operations through accretive acquisitions, and securing additional long-term fee-based contracts. If the Partnership is successful in implementing this strategy, we believe the total amount of cash distributions it makes will increase and our share of those distributions will also increase. The Partnership has announced multiple increases in its quarterly distribution since its initial public offering in May 2002. During that time, the Partnership increased the quarterly per unit cash distribution on its common and subordinated units by 34%, from $0.50 to $0.67.

Financial Information About Segments

Our business activities are segregated into two segments:

•: Managing MarkWest Energy Partners
•: Marketing of natural gas and NGLs

During fiscal 2003, we discontinued our exploration and production business.

You should read Note 17 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K, which is incorporated herein by reference, for financial information about our business segments.

Narrative Description of Business

Our Relationship with MarkWest Energy Partners

We spun off the majority of our then-existing natural gas gathering and processing and NGL transportation, fractionation and storage assets into MarkWest Energy Partners in May 2002, just before the Partnership completed its initial public offering. At the time of its formation and initial public offering, we entered into four contracts with MarkWest Energy Partners whereby MarkWest Energy Partners provides midstream services for us in exchange for a fee. In accordance with generally accepted accounting principles, MarkWest Energy Partners' financial results are included in our consolidated financial statements. All intercompany accounts and transaction are eliminated during consolidation.

As a result of the contracts between MarkWest Energy Partners and us mentioned above, we are the Partnership's largest customer, accounting for 42% of its revenues and 59% of its gross margin (revenues less purchased product costs) for the year ended December 31, 2003. We expect we will account for less of MarkWest Energy Partners' business in the future as it continues to acquire assets and increase its customer and business diversification.

Also at the time of MarkWest Energy Partners' initial public offering, we entered into an omnibus agreement with MarkWest Energy Partners and related parties that governs potential competition and indemnification obligations among the involved parties.

Through our majority ownership in the Partnership's general partner, we control and operate MarkWest Energy Partners. Our employees are responsible for conducting the Partnership's business and operating its assets pursuant to a Services Agreement, which was formalized effective January 1, 2004.

MarkWest Energy Partners' Assets

The following discussion outlines MarkWest Energy Partners' business and assets. Discussion of the marketing assets we own that are unrelated to MarkWest Energy Partners follows the discussion of MarkWest Energy Partners' assets.

The Partnership has three primary geographic areas of operation:

•: Appalachia. The Partnership is the largest processor of natural gas in the Appalachian basin, one of the country's oldest natural gas producing regions. MarkWest Energy Partners' Appalachian assets include five natural gas processing plants, 136 miles of NGL pipeline, a NGL fractionation plant and an 11 million-gallon underground NGL storage facility.
•: Southwest. The Partnership owns an aggregate of 302 miles of natural gas gathering pipelines in 19 gathering systems in Texas, Oklahoma, Louisiana, Mississippi and New Mexico. MarkWest Energy Partners also owns a gas processing plant and four Texas intrastate gas transmission pipelines that transmit natural gas to power plants, municipalities and other large industrial end users.
•: Michigan. The Partnership owns a 90-mile gas gathering pipeline and one natural gas processing plant in Michigan. MarkWest Energy Partners also owns approximately 250 miles of an intrastate crude gathering pipeline, which we refer to as the Michigan Crude Pipeline, the primary intrastate crude oil pipeline in Michigan.

Appalachian Assets

Appalachian Gathering and Processing Facilities

The table below describes MarkWest Energy Partners' processing assets in the Appalachian region:

				Year Ended December 31, 2003
			Design Throughput Capacity (Mcf/d)	Year Ended December 31, 2003
Facility	Location	Year Constructed	Design Throughput Capacity (Mcf/d)	Natural Gas Throughput (Mcf/d)	Utilization of Design Capacity
Kenova Processing Plant(1)	Wayne County, WV	1996	160,000	133,000	83	%
Boldman Processing Plant(1)	Pike County, KY	1991	70,000	46,000	66	%
Maytown Processing Plant	Floyd County, KY	2000	55,000	51,000	93	%
Cobb Processing Plant(2)	Kanawha County, WV	1968	35,000	24,000	69	%
Kermit Processing Plant(3)	Mingo County, WV	2001	32,000	NA	NA

(1): A portion of the Boldman volumes and all of the Kermit volumes are included in Kenova throughput, as these volumes require further processing at our Kenova facility.
(2): During the first half of 2004, the Partnership began construction of a new 24 MMcf/d processing plant. This new plant will replace the Partnership's existing Cobb plant.
(3): The Kermit processing plant is operated by Columbia Gas and the Partnership does not receive inlet volume information.

Kenova Processing Plant. MarkWest Energy Partners' Kenova cryogenic facility was expanded by 40 MMcf/d in 2001 to accommodate expected new production from Columbia Resources. The cryogenic process utilizes a turbo-expander and heat exchangers to cool the gas, which condenses the NGLs. The NGLs are then separated from condensed gaseous components by distillation. This facility receives all of its intake of raw natural gas from Columbia Gas' transmission lines and processes gas produced in Knott, Magoffin, Floyd, Johnson, Martin and Lawrence Counties, Kentucky, and Mingo, Logan, Lincoln, Boone, Cabell, Putman, Wayne and Kanawha Counties, West Virginia. NGLs extracted at this facility are transported to the Partnership's Siloam fractionator via its pipeline.

Boldman Processing Plant. The Partnership's Boldman straight refrigeration processing plant processes gas using a propane refrigeration system to cool the gas and condense the NGLs. The NGLs are then separated from condensed gaseous components by distillation. This facility receives its entire intake of raw natural gas from Columbia Gas' transmission lines and processes gas produced in Pike, Floyd, Letcher and Knott Counties, Kentucky. NGLs extracted at this facility are first delivered by truck to the Partnership's Maytown facility and transported on its leased pipeline to its Siloam fractionator.

Maytown Processing Plant. Pursuant to contract, Equitable Production Company (Equitable; a subsidiary of Equitable Resources, Inc.) operates MarkWest Energy Partners' Maytown facility, a straight refrigeration plant, on the Partnership's behalf. As operator, Equitable is responsible for the day-to-day operation of the Maytown plant. Under our Gas Processing Agreement with Equitable, MarkWest Energy Partners has the right to assume the role of operator upon providing Equitable with 30 day written notice. Like the Boldman plant, the Maytown plant also processes gas using a propane refrigeration system to cool the gas and condense the NGLs. The NGLs are then separated from condensed gaseous components by distillation. This facility receives its entire intake of raw natural gas from Equitable's gathering system in Kentucky. NGLs extracted at this facility are transported to

Siloam via pipeline. The plant also contains a truck unloading facility that allows for the delivery of NGLs into the Partnership's pipeline system for transportation to its Siloam fractionator.

Under the terms of the Gas Processing Agreement, Equitable agrees to deliver to MarkWest Energy Partners all gas now or subsequently produced from specified wells, plus gas attributable to the interests of third parties that is currently being delivered into Equitable's gathering system (to the extent Equitable has the right to process such third party gas). Equitable also grants the Partnership the exclusive right to process all of this natural gas and conveys to it title to the extracted NGLs.

As compensation for its services, MarkWest Energy Partners earns both a fee for its transportation and fractionation services as well as a percentage of the proceeds from the sale of NGLs produced on Equitable's behalf. A portion of the transportation and fractionation fee is subject to annual adjustment in proportion to the annual average percentage change in the Producer Price Index for Oil and Gas Field Services. We, in a separate agreement, have agreed to buy the NGLs from MarkWest Energy Partners and pay a purchase price equal to the net proceeds received from the resale of such NGLs to third parties. The initial term of the Gas Processing Agreement with Equitable runs through February 2015. The operating revenues the Partnership earns under the percent-of-proceeds component of this agreement will fluctuate with the sales price for the NGLs produced.

Cobb Processing Plant. MarkWest Energy Partners' Cobb facility, a refrigerated lean oil processing plant, was acquired by MarkWest Hydrocarbon in 2000 and then conveyed to the Partnership in 2002. The refrigerated lean oil process utilizes a propane refrigeration system to cool the gas and the lean oil. The chilled lean oil absorbs the NGLs that are then separated from the lean oil by distillation. An upgrade of this facility was completed in 2000 by MarkWest Hydrocarbon to decrease downtime and increase recoveries from the facility. This facility receives its entire intake of raw natural gas from Columbia Gas' transmission lines and processes gas produced in Kanawha, Clay, Roane and Jackson Counties, West Virginia. NGLs extracted at this facility are transported to the Partnership's Siloam facility by tanker truck. During the first half of 2004, the Partnership is replacing its existing Cobb facility with a newly constructed 24 MMcf/d processing plant. The new plant is expected to require significantly less operating and maintenance expense. The cost of the construction is expected to be approximately $2.1 million. We will provide approximately $1.7 million in payment of a portion of the costs. The Partnership will pay the remaining approximately $0.4 million and own and operate the plant.

Kermit Processing Plant. MarkWest Energy Partners' Kermit facility, a straight refrigeration plant, was constructed in connection with the expansion at its Kenova facility and in anticipation of increased demand for its services by Columbia Resources. This facility was designed and constructed to increase the volume of natural gas transported to the Partnership's Kenova facility by decreasing the liquid content of the natural gas in Columbia Gas' transmission lines. The Kermit plant processes gas using a similar straight refrigeration process used at the Partnership's Boldman plant. NGLs extracted at this facility are transported to MarkWest Energy Partners' Siloam facility via tanker truck.

The Partnership does not operate its Kermit plant. Under the terms of a Construction and Lease Agreement between MarkWest Hydrocarbon and Columbia Gas, Columbia Gas has the exclusive authority and responsibility for the operation, maintenance and repair of the Kermit Plant. Columbia has the right to operate the plant only during such times as it deems necessary for operational purposes. Columbia Gas has the right to purchase the Kermit plant from the Partnership at any time during the lease term and at the termination of the lease. The lease expires on December 31, 2015. If Columbia Gas does not exercise its option to purchase, MarkWest Energy Partners, at its expense, must remove the plant from Columbia Gas' property within a reasonable time following the expiration of the lease.

Prior to conveying it to the Partnership in 2002, MarkWest Hydrocarbon completed a multi-year expansion of the Appalachian infrastructure in mid-2001, increasing total natural gas designed processing capacity by 127 MMcf/d.

Appalachian NGL Pipelines

All of the NGLs recovered at the Partnership's Kenova, Boldman and Maytown plants are transported to Siloam via pipeline (NGLs from Boldman are first transported to our Maytown facility via tanker trucks). NGLs from the Partnership's Cobb and Kermit plants are transported to Siloam via tanker trucks.

MarkWest Energy Partners' Appalachian liquids pipeline includes the following segments:

				Year Ended December 31, 2003
			Design Throughput Capacity (gal/day)	Year Ended December 31, 2003
Pipeline	Location	Year Constructed	Design Throughput Capacity (gal/day)	NGL Throughput (gal/day)	Utilization of Design Capacity
Maytown to Institute(1)	Floyd County, KY to Kanawha County, WV	1956	250,000	154,000	62	%
Ranger to Kenova(2)	Lincoln County, WV to Wayne County, WV	1976	831,000	154,000	19	%
Kenova to Siloam	Wayne County, WV to South Shore, KY	1957	831,000	409,000	49	%

(1): Includes 40 miles of currently unused pipeline extending from Ranger to Institute.
(2): NGLs transported through the Ranger to Kenova pipeline are included in the Kenova to Siloam volumes.

The Partnership's 40-mile Ranger to Kenova NGL pipeline and the Maytown to Ranger segment of its leased Maytown to Institute pipeline, together with its existing Kenova to Siloam pipeline, form 136 miles of NGL pipeline running through the southern portion of the Appalachia basin. Prior to conveying it to the Partnership in 2002, MarkWest Hydrocarbon acquired the Ranger to Kenova pipeline and leased the 100-mile Maytown to Institute pipeline in 2000 as part of an overall Appalachian expansion project. MarkWest Hydrocarbon originally acquired the Kenova to Siloam pipeline in 1988. MarkWest Energy Partners leases the Maytown to Institute pipeline from Equitable. Our lease expires in 2015. Prior to leasing the Maytown to Institute pipeline, Boldman NGLs were transported by truck to Siloam at significantly greater expense than trucking to an injection point.

Appalachian Fractionation Facility

MarkWest Energy Partners' Siloam fractionation plant receives substantially all of its NGLs via pipeline or tanker truck from its five Appalachia processing plants, with the balance received from tanker truck and rail car deliveries from other third-party NGL sources. The NGLs are then separated into NGL products, including propane, isobutane, normal butane and natural gasoline. The typical composition of the NGL throughput in its Appalachian operations has been approximately 64% propane, 18% normal butane, 6% isobutane, and 12% natural gasoline. The Partnership does not currently produce or sell ethane. Its Siloam fractionation plant has been continually upgraded and maintained since its acquisition by MarkWest Hydrocarbon in 1988.

The following table provides additional detail regarding MarkWest Energy Partners' Siloam fractionation plant:

				Year Ended December 31, 2003
			Design Throughput Capacity (gal/day)	Year Ended December 31, 2003
Facility	Locations	Year Constructed	Design Throughput Capacity (gal/day)	NGL Throughput (gal/day)	Utilization of Design Capacity
Siloam Fractionation Plant	South Shore, KY	1957	600,000	458,000	76	%

Appalachian Storage Facilities

In Appalachia, the Partnership's Siloam facility has both above ground, pressurized storage facilities, with capacity of three million gallons, and underground storage facilities, with capacity of 11 million gallons. Product can be received by truck, pipeline or rail car and can be transported from the facility by truck, rail car or barge. There are eight automated 24-hour-a-day truck loading and unloading slots, a modern rail loading/unloading rack with 12 unloading slots, and a river barge facility capable of loading barges with a capacity of up to 840,000 gallons.

Southwest Assets

Southwest Gathering and Processing Facilities

The table below describes MarkWest Energy Partners' Southwest gathering and processing assets:

				Year Ended December 31, 2003
			Design Throughput Capacity (Mcf/d)	Year Ended December 31, 2003
Facility	Location	Year of Initial Construction	Design Throughput Capacity (Mcf/d)	Natural Gas Throughput (Mcf/d)(3)	Utilization of Design Capacity		NGL Throughput (gal/day)
Foss Lake Gathering System(1)	Roger Mills and Custer County, OK	1998	65,000	52,100	80	%	NA
Appleby Gathering System(2)	Nacogdoches County, TX	1990	40,000	23,800	60	%	NA
18 Other Gathering Systems(2)	Various in TX, LA, MS, NM	Various	53,000	20,500	39	%	NA
Arapaho Processing Plant(1)	Custer County, OK	2000	75,000	51,500	69	%	82,500

(1): The Partnership acquired the Foss Lake Gathering System and Arapaho Processing Plant on December 1, 2003.
(2): The Partnership acquired the Appleby Gathering System, along with 18 other gathering systems, as part of its March 28, 2003 Pinnacle acquisition.
(3): Throughput volumes are for the calendar year ended December 31, 2003, and not just for the period of time the Partnership owned each facility.

Foss Lake Gathering System. MarkWest Energy Partners acquired the Foss Lake Gathering System as part of its western Oklahoma acquisition in December 2003. The system is a low-pressure gathering system consisting of approximately 167 miles of four to 20-inch pipeline connected to approximately 270 wells and includes 10,240 horsepower of owned-compression and 770 horsepower of leased-compression. The system gathers natural gas from the Anadarko Basin in western Oklahoma from approximately 50 producers. The Partnership generates operating margins by charging fixed fees per Mcf of natural gas gathered. All of the natural gas gathered into the system is dehydrated at the Butler compression station for delivery to the Arapaho processing plant.

Appleby Gathering System. MarkWest Energy Partners acquired the Appleby Gathering System as part of its Pinnacle acquisition in March 2003. The system is a low-pressure gathering system consisting of approximately 80 miles of three to eight-inch pipeline connected to approximately 136 wells and includes approximately 6,520 horsepower of leased-compression. The system gathers natural gas from

the Travis Peak Basin in east Texas from approximately seven producers, with one producer accounting for approximately 50% of the volumes. The Partnership sells the gas to marketing companies and to an industrial user under short-term marketing contracts. The Partnership generates a majority of its operating margin through percent-of-index contracts, with the remaining margin generated through fee-based contracts.

Other Gathering Systems. As part of the Pinnacle acquisition, MarkWest Energy Partners acquired 19 other natural gas gathering systems, primarily located in Texas. One of the smaller gathering systems was subsequently disposed of in December 2003. The systems typically gather natural gas from mature producing wells. The Partnership generates operating margins from these systems through percent-of-index, percent-of-proceeds and fixed-fee contracts.

Arapaho Processing Plant. MarkWest Energy Partners' acquired the Arapaho Processing Plant, located in Custer County, Oklahoma, as part of the western Oklahoma acquisition in December 2003. The Arapaho gas processing plant is a cryogenic plant installed in early 2000. The plant is designed to recover ethane and heavier NGLs, including propane. The plant can also reject ethane and continue to recover high levels of propane. The plant delivers processed natural gas into the Panhandle Eastern Pipe Line, or PEPL, and recovered NGLs are sold to Koch Hydrocarbon LP. The Partnership generates operating margins through keep-whole contracts. Under these keep-whole arrangements, MarkWest Energy Partners processes the natural gas and sells the resulting NGLs to third parties at market prices. Because the extraction of the NGLs from the natural gas stream during processing reduces the Btu content of the natural gas, the Partnership must either purchase natural gas at market prices for return to producers, or make a cash payment to the producers. Accordingly, under these arrangements the Partnership's revenues and gross margins increase as the price of NGLs increases relative to the price of natural gas, and its revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs. In the latter case, however, the Partnership has the option of not operating the plant in a low processing margin environment because the Btu content of the inlet natural gas meets the PEPL Btu specification. In addition, approximately 45% of the Foss Lake gas gathering contracts include additional fees to cover plant operating costs, fuel costs and shrinkage costs in a low processing margin environment. Because of its ability to operate the plant in several recovery modes, or to turn it off, as well as the additional fees provided for in the gas gathering contracts, the Partnership's exposure is limited to a portion of the operating costs of the plant.

Southwest Lateral Pipelines. MarkWest Energy Partners acquired the Lake Whitney lateral, the Rio Nogales lateral and the Blackhawk lateral as part of its Pinnacle acquisition in March 2003.

•: The Lake Whitney lateral, constructed in 2001 and 2002, is a 33-mile intrastate natural gas pipeline that transports natural gas to Mirant America Energy Marketing's 556-megawatt Bosque power plant, located near Waco, Texas. The lateral transports natural gas from the El Paso Field Services Pipeline and is the only pipeline connected to, and the sole source of natural gas for, the Bosque power plant. The Partnership has a 30-year fixed-fee contract with Mirant for natural gas transportation on this lateral pipeline. This contract expires in 2030.
•: The Rio Nogales lateral, constructed in 2001, consists of two natural gas lateral pipelines, which in aggregate total 27 miles in length. The laterals transport natural gas from the Duke Energy Field Services Pipe Line, the Houston Pipe Line and the Oasis Pipe Line to Constellation Energy Group's 800-megawatt Rio Nogales power plant, located near Seguin, Texas. The Partnership has a 20-year fixed-fee contract with Constellation. This contract expires in 2022.
•: The Blackhawk lateral is a seven-mile intrastate natural gas pipeline that serves as a back-up natural gas supply source for Borger Energy Associates' 200-megawatt cogeneration power facility, located in Borger, Texas. The lateral is connected to the El Paso Natural Gas pipeline. The Partnership has a fixed-fee contract as operator of the pipeline through September 2005.

However, the Partnership's fixed-fee revenue reduces as of April 2004, at which time ownership of the lateral will transfer to Borger Energy Associates.

MarkWest Energy Partners acquired the Lubbock Lateral from Power-Tex Joint Venture in September 2003. It consists of one 12-inch, 50-mile pipeline and one six-inch, 18-mile pipeline serving several industrial users and municipalities in and around Lubbock, Texas, including the City of Lubbock, Texas Tech University and Southwestern Public Service, a subsidiary of Xcel Energy. The Lubbock Lateral transports natural gas from the El Paso Natural Gas pipeline and the Northern Natural Gas Pipeline. The Partnership has fixed-fee contracts with maturities ranging from one to five years. The lateral has a capacity of 100 MMcf/d and throughput was approximately 26 MMcf/d for 2003.

Michigan Assets

Michigan Gathering and Processing Facilities

The table below describes MarkWest Energy Partners' Michigan gathering and processing assets:

				Year Ended December 31, 2003
			Design Throughput Capacity (Mcf/d) (1)	Year Ended December 31, 2003
Facility	Location	Year Constructed	Design Throughput Capacity (Mcf/d) (1)	Natural Gas Throughput (Mcf/d)	Utilization of Design Capacity		NGL Throughput (gal/day)
90-mile Gas Gathering Pipeline	Manistee, Mason and Oceana Counties, MI	1994 — 1998	35,000	15,000	43	%	NA
Fisk Processing Plant	Manistee County, MI	1998	35,000	15,000	43	%	32,200

(1): MarkWest Hydrocarbon has retained a 70% net profits interest in all gathering and processing fees generated by quarterly throughput volumes in excess of 10 MMcf/d.

The Partnership's Michigan gathering pipeline gathers and transports sour gas produced by third parties in Oceana, Mason and Manistee Counties for sulfur removal at a treatment plant that is owned and operated by Merit Energy Company (Merit), Inc. The Partnership's Fisk processing plant is located adjacent to Merit's treatment plant. The Partnership's gathering pipeline serves approximately 30 wells and 13 producers in this three county area. The Fisk plant processes all of the natural gas gathered and produces propane and a butane-natural gasoline mix. The Partnership processes natural gas under a number of third-party agreements containing both fee and percent-of-proceeds components. Under these agreements, production from all of the acreage adjacent to the Partnership's pipeline and processing facility is dedicated to its gathering and processing facilities. Under the fee component of these agreements, which represent approximately half of the Partnership's gross margin in Michigan, producers pay a fee to transport and treat their gas. Under the percent-of-proceeds component, the Partnership retains a portion of the proceeds from the sale of the NGLs as compensation for the processing services provided.

MarkWest Energy Partners receives 100% of all fee and percent-of-proceeds consideration for the first 10 MMcf/d that it gathers and processes in Michigan. MarkWest Hydrocarbon retains a 70% net profits interest in the gathering and processing income earned on quarterly pipeline throughput in excess of 10 MMcf/d.

Under a Gas Treating and Processing Agreement between MarkWest Energy Partners' subsidiary, West Shore Processing Company, LLC and Merit, Merit operates the Fisk natural gas processing plant. Under the terms of this agreement, Merit treats and processes sour gas delivered to its treatment plant by the Partnership and delivers the treated gas to the Partnership's Fisk plant where NGLs are extracted. For these services, the Partnership pays Merit a set monthly treating fee and a volumetric treating fee based on the amount of gas we deliver to Merit. Both of these fees are adjusted annually

in proportion to the change in a government reported index. In addition, Merit has agreed to pay the Partnership a per-gallon surcharge for propanes, butanes and pentanes (or a combination thereof) contained in the treated gas that is not subsequently delivered to it for processing at its natural gas processing plant.

The Partnership generates revenues from its Michigan natural gas and NGL operations primarily by charging a fee for the gathering and processing services provided. Its contracts in Michigan also provide that the Partnership retains a portion of the proceeds from the sale of NGLs that are produced at its Michigan facility. The Partnership's propane and butane-natural gasoline production is usually sold at the plant.

Michigan Crude Pipeline

MarkWest Energy Partners acquired the Michigan Crude Pipeline in December 2003. The system consists of approximately 152 miles of eight to 16-inch main pipeline, approximately 92 miles of four to ten-inch gathering pipeline, four truck loading facilities and 15 storage tanks. The pipeline, which serves over 1,000 oil and gas wells on the Niagaran Reef Trend, delivers crude oil to the Enbridge Pipeline. Approximately 60% of the crude oil transported through the pipeline was shipped for one marketing customer. The Partnership generates operating margins by charging a tariff per barrel of crude oil transported. Because the Partnership has the ability to set the amount of this tariff, it believes this pipeline will provide it with a relatively stable base of cash flows. The pipeline has a capacity of 60,000 bpd and transported approximately 16,200 bpd of crude oil for the year ended December 31, 2003.

MarkWest Hydrocarbon Assets

Marketing

Our marketing group markets our NGL production in Appalachia. In 2003, we sold approximately 177 million gallons of NGLs extracted at the Partnership's Siloam facility. We ship NGL products from Siloam by truck, rail and barge. Our marketing customers include propane retailers, refineries, petrochemical plants and NGL product resellers. Most marketing sales contracts have terms of one year or less, are made on best-efforts basis and are priced in reference to Mt. Belvieu index prices or plant posting prices. In addition to our NGL product sales, our marketing operations are also responsible for the purchase of natural gas delivered for the account of producers pursuant to our keep-whole processing contracts.

We strive to maximize the value of our NGL output by marketing directly to our customers. We minimize the use of third-party brokers, preferring instead to support a direct marketing staff focused on multi-state and independent dealers. Additionally, we use our own trailer and railcar fleet, as well as our own terminal and owned and leased storage facilities, to enhance supply reliability to our customers. These efforts have allowed us to maintain premium pricing for the majority of our NGL products compared to Gulf Coast spot prices.

In Appalachia, we have entered into operating agreements with Columbia Gas Transmission Corporation (Columbia Gas) with respect to natural gas delivered into its transmission facilities upstream of MarkWest Energy Partners' Kenova, Boldman and Cobb facilities. Under the terms of these operating agreements, Columbia Gas has agreed to use reasonable, diligent efforts to supply these facilities with consistent volumes of natural gas shipped by Columbia Gas on behalf of the Appalachian producers. The initial terms of our agreements with Columbia Gas run through December 31, 2015, with annual renewals thereafter.

Our operating agreements with Columbia Gas require us to enter into contracts with the natural gas producers whose production will be processed in the Partnership's Kenova, Boldman and Cobb facilities. We have contractual commitments with approximately 260 such producers in Appalachia.

Approximately 54% of these contracts representing approximately 27% of the committed volumes expire in 2009. The remaining balance of approximately 46% of the contracts representing approximately 73% of the committed volumes expires in 2015. Our largest producers are Columbia Resources and Equitable. Under the provisions of our contracts with the Appalachian producers, the producers have committed all of the natural gas they deliver into Columbia Gas' transmission facilities upstream of MarkWest Energy Partners' Kenova, Boldman and Cobb facilities for processing.

As compensation for providing processing services to our Appalachian producers (we have since outsourced these services to MarkWest Energy Partners as discussed below), we earn both a fee and the NGLs produced. In return, we are required to replace, in dry natural gas, the Btu value of the NGLs extracted. This Btu replacement obligation is referred to in the industry as a "keep-whole" arrangement. In keep-whole arrangements, our principal cost is the replacement of the Btus extracted from the gas stream in the form of NGLs or consumed as fuel during processing with dry gas of an equivalent Btu content. Generally, the value of the NGLs extracted is greater than the cost of replacing those Btus with dry gas, resulting in positive operating margins under these contracts. In the event natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, the cost of keeping the producer "whole" results in operating losses. The spread between the NGL product sales price and the purchase price of natural gas with an equivalent Btu content is called the "frac spread."

At the closing of MarkWest Energy Partners' initial public offering on May 24, 2002, we outsourced our midstream services to the Partnership, which performs natural gas gathering and processing and NGL transportation, fractionation and storage services for us for a fee pursuant to the terms of our operating agreements with the Partnership. Under those agreements, we retained all the benefits and associated risks of our keep-whole contracts with producers. Our NGL and gas marketing operations were not contributed to MarkWest Energy Partners.

Our keep-whole contracts expose us to commodity price risk, both on the sales side (of NGLs) and on the purchase side (of natural gas), which may make our marketing results and cash flows volatile. We attempt to mitigate our commodity price risk through our hedging program. You should read Item 7A, "Quantitative and Qualitative Disclosures About Market Risk" for further details about our commodity price risk management program, which is incorporated herein by reference.

Our natural gas marketing group sources new gas for MarkWest Energy Partners' facilities, purchases our replacement Btu gas requirements, and assists with our business development efforts. Our natural gas marketing operations are a fundamentally high-dollar, low-margin business. Consequently, a significant percentage of our overall revenue stems from gas marketing, but the contribution to our gross margin is modest. For the years ended December 31, 2003, 2002, and 2001, 17%, 37%, and 36%, respectively, of gathering, processing and marketing revenue stemmed from gas marketing. However, the gas marketing gross margin as a percent of gathering, processing and marketing gross margin was just 0%, 12%, and 4%, respectively.

Exploration and Production

We discontinued our exploration and production business during 2003. At December 31, 2003, our exploration and production assets had been reduced to a minority interest in three wells in Michigan.

Reserves

Please review Note 20 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K, which is incorporated herein by reference, for information regarding our proved and developed oil and gas reserves and the standardized measure of discounted future net cash flows and changes therein.

We have not filed any oil or natural gas reserve estimates or included any such estimates in reports to a federal or foreign government authority or agency, other than the Securities and Exchange Commission (SEC) and the Department of Energy (DOE). There were no differences between the reserve estimates included in the SEC report, the DOE report and those included herein, except for production and additions and deletions due to the difference in the "as of" dates of such reserve estimates.

Production

The following table sets forth information regarding net oil and natural gas production, average sales prices and other production information. Hedging gains and losses are disclosed separately for the years ended December 31, 2003, 2002 and 2001.

			United States								Canada(1)
			2003			2002		2001			2003			2002		2001
Quantities produced and sold:
	Natural gas (MMcf)			1,981			3,228		2,743			5,341			7,098		1,944
	Oil and liquids (MBbl)			24			23		36			87			45		21
		Total Mmcfe (2)		2,125			3,367		2,959			5,866			7,370		2,073
		Average Mcfe/d		5,800			9,200		7,400			16,100			20,200		5,700
Average sales price:
	Natural gas ($/Mcf) sales price received		$	4.51		$	2.54	$	3.36		$	4.29		$	2.55	$	2.35
	Natural gas ($/Mcf) effects of energy swaps		$	(0.12	)	$	0.44	$	(0.01	)	$	(0.71	)	$	0.26	$	—
	Oil and liquids ($/Bbl)		$	14.92		$	15.61	$	15.89		$	23.42		$	18.20	$	16.35
Average production (lifting) costs ($/Mcfe)			$	1.57		$	1.24	$	1.38		$	1.22		$	0.96	$	0.67

(1): The results for 2001 reflect the result of our Canadian acquisition since August 2001. Production in Canada for August 1, 2001 to December 31, 2001, averaged 13,500 Mcfe/d.
(2): Oil and liquid production is converted to natural gas equivalents (Mcfe) at a rate of one barrel to six Mcf.

Productive Wells

The following table sets forth information regarding the number of productive wells in which we held a working interest at December 31, 2003:

			2003 Productive Wells(1)
			Gas Wells		Oil Wells
			Gross(2)	Net(3)	Gross	Net
United States
	San Juan Basin		—	—	—	—
	Michigan		3	.62	—	—

		Total	3	.62	—	—
Canada
	Alberta		—	—	—	—

Total wells			3	.62	—	—

(1): Each well completed to more than one producing zone is counted as a single well.

(2): A gross well is a well in which a working interest is owned.
(3): One net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interest owned in gross wells.

Drilling and Recompletion Activity

The following table sets forth our gross and net interest in exploration and developmental wells drilled and wells recompleted during the periods indicated.

				United States									Canada(1)
				2003			2002			2001			2003			2002			2001
Gross(2) (Net)(3) wells
	Development
		Natural gas		10	(4.2	)	14	(8	)	1	(0.5	)	21	(16.7	)	13	(12.3	)	10	(8.5	)
		Oil		—	—		—	(—	)	—	(—	)	2	(1.5	)	1	(—	)	—	(—	)
		Non-productive(4)		—	—		—	(—	)	—	(—	)	2	(1.4	)	3	(2.5	)	—	(—	)

			Total	10	(4.2	)	14	(8	)	1	(0.5	)	25	(19.6	)	17	(14.8	)	10	(8.5	)

	Exploratory
		Natural gas		—	—		2	(0.3	)	1	(0.2	)	23	(18.4	)	13	(10.6	)	7	(6.3	)
		Oil		—	—		—	(—	)	—	(—	)	4	(3.1	)	2	(2.0	)	—	(—	)
		Non-productive		2	(0.5	)	—	(—	)	—	(—	)	6	(4.4	)	6	(5.5	)	1	(1.0	)

			Total	2	(0.5	)	2	(0.3	)	1	(0.2	)	33	(25.9	)	21	(18.1	)	8	(7.3	)

	Recompletion(5)
		Natural gas		1	(0.8	)	5	(2.5	)	16	(10.2	)	21	(17.2	)	12	(11	)	—	(—	)
		Oil		—	—		—	(—	)	—	(—	)	—	(—	)	—	(—	)	—	(—	)
		Non-productive		—	—		—	(—	)	—	(—	)	2	(1.6	)	4	(4	)	—	(—	)

			Total	1	(0.8	)	5	(2.5	)	16	(10.2	)	23	(18.8	)	16	(15	)	—	(—	)

Total gross (net) wells				13	(5.5	)	21	(10.8	)	18	(10.9	)	81	(64.3	)	54	(47.9	)	18	(15.8	)

(1): The results for 2001 reflect the results of our Canadian acquisition since August 2001.
(2): A gross well is a well in which a working interest is owned.
(3): One net well is deemed to exist when the sum of the fractional ownership working interest in gross wells equals one producing well, in addition to the existing producing horizon. These are dually completed wells.
(4): A non-productive well is a well deemed to be incapable of producing either natural gas or oil in sufficient quantities to justify completion as a natural gas or oil well.
(5): A recompletion well is a well which within an existing wellbore, a different geological horizon with proved reserves is completed as a producing well, in addition to the existing producing horizon. These are dually completed wells.

Acreage

The following table sets forth the leasehold acreage held by MarkWest Hydrocarbon at December 31, 2003.

		Developed Acreage(1)		Undeveloped Acreage(2)(5)
		Gross(3)	Net(4)	Gross	Net
United States
	Michigan	320	46	—	—

(1): Developed acres are those acres that are spaced or assigned to productive wells.
(2): Undeveloped acres are considered to be those acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. It should not be confused with undrilled acreage held by production under the terms of a lease.
(3): A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
(4): A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres.
(5): On December 12, 2003, the Company assigned all of its remaining undeveloped acreage located in Michigan to M & M Exploration Partners, LLC. After the second anniversary of the assignment, the Company has the right to receive re-assignment of any acreage not committed to an exploration venture.

Factors Affecting our Operations

Seasonality

A substantial portion of our revenues and, as a result, our gross margin, remains dependent upon the volume and sales price of NGL products, particularly propane. The volume and sales price of NGL products fluctuate with the winter weather conditions and other supply and demand determinants. The strongest demand for propane and the highest propane sales margins generally occur during the winter heating season. As a result, we recognize a substantial portion of our annual income from our marketing segment during the first and fourth quarters of the year.

Competition

MarkWest Hydrocarbon

MarkWest Hydrocarbon faces competition for marketing products and purchasing natural gas supplies. Competition for customers and purchases of natural gas are based primarily on price, delivery capabilities, flexibility, and maintenance of quality customer relationships. The Company's competitors are similar to those of MarkWest Energy Partners (described below).

MarkWest Energy Partners

MarkWest Energy Partners faces competition for crude oil and natural gas transportation and in obtaining natural gas supplies for processing and related services operations, in obtaining unprocessed NGLs for fractionation, and in marketing products and services. Competition for natural gas supplies is based primarily on location of gas gathering facilities and gas processing plants, operating efficiency

and reliability, and ability to obtain a satisfactory price for products recovered. Competitive factors affecting our fractionation services include availability of capacity, proximity to supply and to industry marketing centers, and cost efficiency and reliability of service. Competition for customers is based primarily on price, delivery capabilities, flexibility, and maintenance of quality customer relationships.

In competing for new business opportunities, MarkWest Energy Partners faces strong competition in acquiring natural gas and crude oil supplies and in competing for service fees. The Partnership's competitors include:

•: major integrated oil companies;
•: major interstate and intrastate pipelines;
•: other large raw natural gas gatherers that gather, process and market natural gas and NGLs; and
•: a relatively large number of smaller gas gatherers of varying financial resources and experience.

Many of the Partnership's competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than the Partnership. Smaller local distributors may enjoy a marketing advantage in their immediate service areas.

Operational Risks and Insurance

Our operations are subject to the usual hazards incident to the exploration, production, gathering and processing of natural gas; the transmission, fractionation and storage of NGLs; and the transmission of crude oil; such as explosions, product spills, leaks, emissions and fires. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage, and may result in curtailment or suspension of operations at the affected facility.

We maintain general public liability, property and business interruption insurance in amounts that we consider to be adequate for such risks. Such insurance is subject to deductibles that we consider reasonable and not excessive. Consistent with insurance coverage generally available to the industry, our insurance policies provide coverage for losses or liabilities related to sudden occurrences of pollution or other environmental damage.

The occurrence of a significant event that we are not fully insured or indemnified against, and/or the failure of a party to meet its indemnification obligations to us, could materially and adversely affect our operations and financial condition. Moreover, we cannot provide assurance that we will be able to maintain adequate insurance in the future at rates we consider reasonable. To date, however, we have not experienced material uninsured losses or any difficulty in acquiring insurance coverage in amounts we believe to be adequate.

Title to Properties

We believe we have satisfactory title to all of our assets.

Substantially all of MarkWest Energy Partners' pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. The Partnership has obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which the Partnership's pipelines were built was purchased in fee. The Partnership's Siloam fractionation plant and Kenova processing plant are on land that the Partnership owns in fee.

Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that were transferred to the Partnership required the consent of the then-current landowner to transfer these rights, which in some instances was a governmental entity. The Partnership's general partner believes that it has obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for the Partnership to operate its business in all material respects.

The Partnership's general partner believes that the Partnership has satisfactory title to all of the Partnership's assets. To the extent certain defects in title to the assets contributed to the Partnership or failures to obtain certain consents and permits necessary to conduct our business arise within three years after the closing of the Partnership's initial public offering, the Partnership is entitled to indemnification from MarkWest Hydrocarbon under the Omnibus Agreement. Title to property may be subject to encumbrances. The Partnership's general partner believes that none of such encumbrances materially detract from the value of the Partnership's properties or from its interest in these properties or should materially interfere with their use in the operation of the Partnership's business.

The Partnership has pledged substantially all of its assets to secure its credit facility as discussed in Note 9 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K, which is incorporated herein by reference.

Regulatory Matters

The activities of MarkWest Hydrocarbon and MarkWest Energy Partners are subject to various state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, community right-to-know, protection of the environment, safety and other matters.

Some of MarkWest Energy Partners' gas, liquids and crude oil gathering and transmission operations are subject to regulation by various state regulatory bodies. In many cases, various phases of our gas, liquids and crude oil operations in the states in which the Partnership operates are subject to rate and service regulation. The applicable state statutes generally require that the Partnership's rates and terms and conditions of service provide no more than a fair return on the aggregate value of the facilities used to render services. Regulatory authorities in the states in which the Partnership operates have generally not been aggressive in regulating gas, liquids and crude oil gathering and transmission facilities and have generally not investigated the rates or practices of the owners of such facilities in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally.

The Partnership's Appalachian pipeline carries NGLs across state lines. The primary shipper on the pipeline is MarkWest Hydrocarbon, who has entered into agreements with the Partnership providing for a fixed transportation charge for the term of the agreements, which expire on December 31, 2015. The Partnership is the only other shipper on the pipeline. As the Partnership does not operate its Appalachian pipeline as a common carrier and does not hold the pipeline out for service to the public generally, there are currently no third-party shippers on this pipeline and the pipeline is and will continue to be operated as a proprietary facility. Similarly, the Partnership's Michigan Crude Pipeline delivers crude oil to a third party carrier which makes deliveries both within and outside Michigan, in this case for unaffiliated third parties. Neither pipeline is currently subject to regulation by the Federal Energy Regulatory Commission, or FERC. However, if a shipper sought to challenge the jurisdictional status of either of these pipelines, the FERC could determine that such transportation is within its jurisdiction under the Interstate Commerce Act. In such a case, the Partnership would be required to file a tariff for such transportation with the FERC and provide a cost justification for the transportation charge. Because MarkWest Hydrocarbon has agreed to not challenge the status of the Partnership's Appalachian pipeline or the transportation charge during the term of the agreements between the Partnership and MarkWest Hydrocarbon and, moreover, the likelihood of

other entities seeking to utilize the Partnership's Appalachian pipeline is limited, the likelihood of such a challenge on the Partnership's Appalachian pipeline is remote. Similarly, because the Partnership is operating its Michigan Crude Pipeline in the same manner as it was historically operated by Shell for a significant period of time prior to the Partnership's acquisition and because the Partnership's operations are entirely within the state of Michigan, the likelihood of a challenge to the status of this pipeline is considered remote. However, the Partnership cannot predict whether a FERC jurisdictional challenge might be made with respect to either of these pipelines, nor provide assurance that such a challenge would not adversely affect the Partnership's results of operations.

Some of the Partnership's liquids and crude oil gathering facilities deliver into pipelines that have the ability to make redeliveries in both interstate and intrastate commerce. The rates the Partnership charges on its liquids and crude oil facilities are not regulated at the state or federal level, however, there can be no assurance that the rates for service on these facilities will remain unregulated in the future.

Environmental Matters

MarkWest Hydrocarbon

We are subject to environmental risks normally incident to our operations and construction activities including, but not limited to, uncontrollable flows of natural gas, fluids and other substances into the environment, explosions, fires, pollution, and other environmental and safety risks. Our business is subject to comprehensive state and federal environmental regulations. For example, we, without regard to fault, could incur liability under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (also known as Superfund), or state counterparts, in connection with the disposal or other releases of hazardous substances, including sour gas, and for natural resource damages. Further, the recent trend in environmental legislation and regulations is toward stricter standards, and this will likely continue in the future.

Our activities are subject to environmental and safety regulation by federal and state authorities, including, without limitation, the state environmental agencies and the federal Environmental Protection Agency, which can increase the costs of designing, installing and operating our facilities. In most instances, the regulatory requirements relate to the discharge of substances into the environment and include measures to control water and air pollution.

Laws and regulations may require us to obtain a permit or other authorization before we may conduct certain activities or we may be subject to fines and penalties for non-compliance. Further, these rules may limit or prohibit our activities within wilderness areas, wetlands, and areas providing habitat for certain species or other protected areas. We are also subject to other federal, state and local laws covering the handling, storage or discharge of materials used by us. We believe that we are in material compliance with all applicable laws and regulations.

MarkWest Energy Partners

General. MarkWest Energy Partners' operation of processing and fractionization plants, pipelines and associated facilities in connection with the gathering and processing of natural gas, the transportation, fractionization and storage of NGLs and the storage and gathering and transportation of crude oil is subject to stringent and complex federal, state and local laws and regulations relating to release of pollutants into the environment or otherwise relating to protection of the environment. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases the Partnership's overall cost of doing business, including the Partnership's cost of constructing, maintaining and upgrading equipment and facilities. The Partnership's failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, imposition of investigatory or remedial requirements, and, in less common circumstances,

issuance of injunctions. MarkWest Energy Partners believes that the Partnership's operations and facilities are in substantial compliance with applicable environmental laws and regulations and that the cost of compliance with such laws and regulations will not have a material adverse effect on the Partnership's results of operations or financial condition.

Nevertheless, the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts MarkWest Energy Partners currently anticipates. Moreover, risks of process upsets, accidental releases or spills are associated with the Partnership's operations and MarkWest Energy Partners cannot assure you that MarkWest Energy Partners will not incur significant costs and liabilities as a result of such upsets, releases, or spills, including those relating to claims for damage to property and persons. In the event of future increases in costs, MarkWest Energy Partners may be unable to pass on those increases to the Partnership's customers. MarkWest Energy Partners will attempt to anticipate future regulatory requirements that might be imposed and plan accordingly in order to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance.

Hazardous Substance and Waste. To a large extent, the environmental laws and regulations affecting the Partnership's operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control environmental pollution of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation, and disposal of solid and hazardous wastes, and may require investigatory and corrective actions of facilities where such waste may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the "Superfund" law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to a release of "hazardous substance" into the environment. These persons include the owner or operator of a site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the Environmental Protection Agency, or EPA, and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Although "petroleum" is excluded from CERCLA's definition of a "hazardous substance," in the course of the Partnership's ordinary operations MarkWest Energy Partners will generate wastes that may fall within the definition of a "hazardous substance." MarkWest Energy Partners may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed. MarkWest Energy Partners has not received any notification that MarkWest Energy Partners may be potentially responsible for cleanup costs under CERCLA.

MarkWest Energy Partners also generates both hazardous and nonhazardous solid wastes which are subject to requirements of the federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. From time to time, the EPA has considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. MarkWest Energy Partners is not currently required to comply with a substantial portion of the RCRA requirements because the Partnership's operations generate minimal quantities of hazardous wastes. However, it is possible that some wastes generated by the Partnership that are currently classified as nonhazardous may in the future be designated as "hazardous wastes," resulting in the wastes being subject to more

rigorous and costly disposal requirements. Changes in applicable regulations may result in an increase in the Partnership's capital expenditures or plant operating expenses.

MarkWest Energy Partners currently owns or leases, and has in the past owned or leased, properties that have been used over the years for natural gas gathering and processing, for NGL fractionation, transportation and storage and for the storage and gathering and transportation of crude oil. Solid waste disposal practices within the NGL industry and other oil and natural gas related industries have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, a possibility exists that hydrocarbons and other solid wastes may have been disposed of on or under various properties owned or leased by the Partnership during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties over whom MarkWest Energy Partners had no control as to such entities' handling of hydrocarbons or other wastes and the manner in which such substances may have been disposed of or released. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, MarkWest Energy Partners could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination or to perform remedial operations to prevent future contamination. MarkWest Energy Partners does not believe that there presently exists significant surface and subsurface contamination of the Partnership's properties by hydrocarbons or other solid wastes for which MarkWest Energy Partners is currently responsible.

Ongoing Remediation and Indemnification from Columbia Gas. Columbia Gas is the previous or current owner of the property on which the Partnership's Kenova, Boldman, Cobb and Kermit facilities are located and is the previous operator of the Partnership's Boldman and Cobb facilities. Columbia Gas has been or is currently involved in investigatory or remedial activities with respect to the real property underlying the Boldman and Cobb facilities pursuant to an "Administrative Order by Consent for Removal Actions" entered into by Columbia Gas and EPA Regions II, III, IV, and V in September 1994. Columbia Gas is also pursuing these remedial activities at the Boldman facility pursuant to an "Agreed Order" that it entered into with the Kentucky Natural Resources and Environmental Protection Cabinet in October 1994. The focus of the investigatory and remedial activities pursued by Columbia Gas has been the cleanup of polychlorinated biphenyls, also known as PCBs, and other hazardous substances which may be found in these real properties. Columbia Gas has agreed to retain sole liability and responsibility for, and indemnify MarkWest Hydrocarbon against, any environmental liabilities associated with the EPA Administrative Order, the Kentucky Agreed Order or any other environmental condition related to the real property prior to the effective dates of MarkWest Hydrocarbon's agreements pursuant to which MarkWest Hydrocarbon leased the real property or purchased the real property from Columbia Gas. In addition, Columbia Gas has agreed to perform all the required response actions at its cost and expense in a manner that minimizes interference with MarkWest Hydrocarbon's use of the properties. On May 24, 2002, MarkWest Hydrocarbon assigned to the Partnership the benefit of its indemnity from Columbia Gas with respect to the Cobb, Boldman and Kermit facilities. While MarkWest Energy Partners is not a party to the agreement under which Columbia Gas agreed to indemnify MarkWest Hydrocarbon with respect to the Kermit facility, MarkWest Hydrocarbon has agreed to provide the Partnership with the benefit of its indemnity, as well as any other third-party environmental indemnity of which it is a beneficiary. To date, Columbia Gas has been performing all actions required under these agreements, and, accordingly, MarkWest Energy Partners does not believe that the remediation of these properties by Columbia Gas pursuant to the EPA Administrative Order or the Kentucky Agreed Order will have a material adverse impact on the Partnership's financial condition or results of operations. MarkWest Hydrocarbon has also agreed to provide the Partnership an additional environmental indemnification pursuant to the terms of the Omnibus Agreement. See "Certain Relationships and Related Transactions."

Air Emissions. The Partnership's operations are subject to the Clean Air Act and comparable state statutes. Amendments to the Clean Air Act were enacted in 1990. Moreover, recent or soon to be adopted changes to state implementation plans for controlling air emissions in regional, non-attainment areas require or will require most industrial operations in the United States to incur capital expenditures in order to meet air emission control standards developed by the EPA and state environmental agencies. As a result of these amendments, the Partnership's processing and fractionating plants, pipelines, and storage facilities that emit volatile organic compounds or nitrogen oxides may become subject to increasingly stringent regulations, including requirements that some sources install maximum or reasonably available control technology. In addition, the 1990 Clean Air Act Amendments established a new operating permit for major sources, which applies to some of the Partnership's facilities. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties, and may result in the limitation or cessation of construction or operation of certain air emission sources. Although MarkWest Energy Partners can give no assurances, MarkWest Energy Partners believes implementation of the 1990 Clean Air Act Amendments will not have a material adverse effect on the Partnership's financial condition or results of operations.

Clean Water Act. The Federal Water Pollution Control Act, also known as the Clean Water Act, and similar state laws impose restrictions and strict controls regarding the discharge of pollutants, including natural gas liquid-related wastes, into state waters or waters of the United States. Regulations promulgated pursuant to these laws require that entities that discharge into federal and state waters obtain National Pollutant Discharge Elimination System, or NPDES, and/or state permits authorizing these discharges. The Clean Water Act and analogous state laws assess administrative, civil and criminal penalties for discharges of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such waters. In addition, the Clean Water Act and analogous state laws require that individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff. MarkWest Energy Partners believes that MarkWest Energy Partners is in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposed thereunder, and that continued compliance with such existing permit conditions will not have a material effect on the Partnership's results of operations.

Safety Regulation. The Partnership's pipelines are subject to regulation by the U.S. Department of Transportation under the Hazardous Liquid Pipeline Safety Act, as amended, or HLPSA, relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The HLPSA covers crude oil, carbon dioxide, NGL and petroleum products pipelines and requires any entity which owns or operates pipeline facilities to comply with the regulations under the HLPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. MarkWest Energy Partners believes that the Partnership's pipeline operations are in substantial compliance with applicable HLPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with the HLPSA will not have a material adverse effect on the Partnership's results of operations or financial position.

The Pipeline Safety Improvement Act of 2002 includes numerous provisions that tighten federal specifications and safety requirements for natural gas and hazardous liquids pipeline facilities. Many of the statute's provisions build on existing statutory requirements and strengthen regulations of the Research and Special Programs Administration and the office of Pipeline Safety, in particular, with respect to operator qualifications programs, natural mapping system and safe excavation practices. Management of the Partnership believes that compliance with the Pipeline Safety Improvement Act of 2002 will not have a material effect on its operations.

Employee Safety

The workplaces associated with the processing and storage facilities and the pipelines we operate are also subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statues that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to our employees, state and local government authorities, and citizens. We believe that we have conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.

In general, we expect industry and regulatory safety standards to become stricter over time, thereby resulting in increased compliance expenditures. While we cannot accurately estimate these expenditures at this time, we do not expect such expenditures will have a material adverse effect on our results of operations.

Employees

As of December 31, 2003, we had 128 employees. At our fractionation facility in South Shore, Kentucky, the Paper, Allied Industrial, Chemical, and Energy Workers International Union Local 5-372 represents 14 employees. We entered into our collective bargaining agreement with this Union on June 29, 2001 that expires on June 28, 2004. The agreement covers only hourly, non-supervisory employees. We consider our labor relations to be good.

Available Information

You can find more information about us at our Internet website located at www.markwest.com. Our Annual Report on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and any amendments to those reports are available free of charge through our internet website as soon as is reasonably practicable after we electronically file such material with the SEC.

In addition, the SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.

ITEM 3. LEGAL PROCEEDINGS

MarkWest Hydrocarbon, 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.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted to a vote of security holders during the quarter ended December 31, 2003.

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Our common stock trades on the American Stock Exchange national market under the symbol "MWP." As of December 31, 2003, there were 9,562,407 shares of common stock outstanding held by approximately 33 holders of record. The following table sets forth quarterly high and low sales prices as reported by the American Stock Exchange, as retroactively amended to give effect to the 2003 stock dividend (see below), for the periods indicated.

	2003				2002
	High		Low		High		Low
First Quarter	$	5.17	$	4.47	$	7.32	$	5.68
Second Quarter	$	6.76	$	5.00	$	7.27	$	6.45
Third Quarter	$	7.50	$	6.80	$	6.55	$	5.36
Fourth Quarter	$	13.13	$	7.35	$	5.64	$	4.83

Dividend Policy

On July 10, 2003, the Board of Directors declared a stock dividend of one share for each ten shares owned by stockholders of record as of the close of business on July 31, 2003. The stock dividend was paid on August 11, 2003, with an ex-dividend date of July 29, 2003.

On January 22, 2004, the Board of Directors declared a one-time special cash dividend of $0.50 per share of common stock. The dividend was paid on February 18, 2004 to stockholders of record as of the close of business on February 4, 2004, with an ex-dividend date of February 2, 2004.

Other than the stock dividend and one-time special dividend, we have never paid dividends on our common stock. Payment of dividends in the future will depend on our earnings, financial condition and contractual restrictions, including those under our bank line of credit or imposed by law and other factors deemed relevant by our Board of Directors, if any.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected consolidated historical financial and operating data for MarkWest Hydrocarbon. Certain prior year amounts have been reclassified to conform to the 2003 presentation. The selected consolidated statement of operations and balance sheet data for the years ended December 31, 2003, 2002 and 2001, and as of December 31, 2003 and 2002, are derived from, and are qualified by reference to, our audited Consolidated Financial Statements included elsewhere in this Form 10-K. The selected consolidated statement of operations and balance sheet data set forth below for the years ended December 31, 2000 and 1999, and as of December 31, 2001, 2000 and 1999, have been derived from audited financial statements not included in this Form 10-K. You should read this in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of

Operations" and our Consolidated Financial Statements and accompanying Notes included elsewhere in this Form 10-K, which are incorporated herein by reference.

		Year Ended December 31,
		2003			2002			2001		2000		1999
		(in thousands, except per share amounts and operating data)
Statement of Operations Data:
Revenue		$	207,651		$	154,338		$	173,890	$	217,567	$	105,169
Income (loss) from continuing operations		$	(20,898	)	$	(4,713	)	$	315	$	8,493	$	2,988
Net income (loss)		$	(9,949	)	$	(2,796	)	$	2,810	$	8,878	$	2,823
Earnings (loss) from continuing operations per share:
	Basic	$	(2.23	)	$	(0.50	)	$	0.04	$	0.91	$	0.32
	Diluted	$	(2.23	)	$	(0.50	)	$	0.04	$	0.91	$	0.32
Earnings (loss) per share:
	Basic	$	(1.06	)	$	(0.30	)	$	0.30	$	0.95	$	0.30
	Diluted	$	(1.06	)	$	(0.30	)	$	0.30	$	0.95	$	0.30
Weighted average shares outstanding:
	Basic		9,389			9,349			9,326		9,297		9,323
	Diluted		9,406			9,363			9,349		9,341		9,329
Balance Sheet Data (as of December 31):
Total assets		$	280,713		$	257,523		$	250,511	$	147,287	$	119,243
Long-term debt		$	126,200		$	64,223		$	104,850	$	43,000	$	44,035
Stockholders' equity		$	52,184		$	53,352		$	69,033	$	61,594	$	52,719
Operating Data:
Marketing:
	NGL product sales (gallons)(5)		177,000,000			183,000,000			152,200,000		153,000,000		115,800,000
MarkWest Energy Partners(1)
Appalachia:
	Natural gas processed for a fee (Mcf/d)(2)		202,000			202,000			192,000		196,000		171,000
	NGLs fractionated for a fee (gal/d) (3)		458,000			476,000			423,000		406,000		310,000
Southwest:
	Gathering systems throughput (Mcf/d)(4)		55,000			—			—		—		—
Michigan:
	Pipeline throughput (Mcf/d)		15,000			13,800			8,800		11,000		17,800
	NGL product sales (gallons)		111,800,000			11,100,000			8,000,000		9,200,000		13,500,000

(1): Represents MarkWest Hydrocarbon until May 23, 2002, and MarkWest Energy Partners from May 24, 2002—the date its initial public offering closed.
(2): Represents throughput at the Kenova, Cobb, Boldman and Maytown processing plants.
(3): Prior to May 24, 2002, this represents NGL product production at the Siloam fractionator.
(4): Includes volumes since March 28, 2003, the date the Partnership's Pinnacle acquisition was completed. Also, includes the Partnership's Lubbock Pipeline volumes. The Partnership acquired the Lubbock Pipeline on September 2, 2003.
(5): Represents sales at the Siloam fractionator.

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

The following discussion and analysis relates to factors that have affected our consolidated financial condition and results of operations for the three years ended December 31, 2003, 2002 and 2001. Certain prior year amounts have been reclassified to conform to the presentation used in 2003. In conjunction with the following discussion and analysis, you should also read our Consolidated Financial Statements and related Notes thereto and the "Selected Financial Data" included elsewhere in this Form 10-K, which are incorporated herein by reference.

Recent Developments

During the year ended December 31, 2003, we completed several important initiatives that accomplished the transformation of MarkWest Hydrocarbon into a company focused on increasing shareholder value through our ownership in MarkWest Energy Partners. Specifically, we discontinued our exploration and production business and significantly grew MarkWest Energy Partners, primarily through the acquisition of third-party midstream assets.

MarkWest Hydrocarbon Dispositions

Our three primary dispositions were the following:

•: We sold our San Juan Basin oil and gas producing properties in two separate sales during the second and third quarters of 2003. The San Juan Basin properties represented substantially all of our exploration and production business located in the United States. Net proceeds from the sales were approximately $55.3 million. We recognized a net pretax gain on the sales of approximately $23.3 million.
•: We sold our entire Canadian exploration and production business in two separate transactions during December 2003. Net proceeds from the sales were approximately $49.1 million. We recognized a net pretax loss on the sales of approximately $4.8 million.
•: We sold two of our three NGL terminals during the third quarter of 2003. Net proceeds were approximately $2.3 million. We recognized a net pretax loss on the sales of less than $0.1 million.

MarkWest Energy Partners Acquisitions

Pinnacle Merger. On March 28, 2003, we completed the acquisition of Pinnacle Natural Gas Company, or Pinnacle. The aggregate purchase price of $39.9 million was comprised of $23.4 million in cash plus the assumption of $16.6 million of bank indebtedness. The assets are primarily located in Texas and include three lateral natural gas pipelines and twenty natural gas gathering systems. One of the gathering systems was subsequently disposed of in December 2003 for an immaterial amount. The three lateral natural gas pipelines consist of approximately 67 miles of pipeline that deliver natural gas under firm contracts to power plants. The nineteen natural gas gathering systems gathered an aggregate of approximately 44.3 MMcf/d of natural gas during the year ended December 31, 2003, and have a capacity of approximately 93.0 MMcf/d. This acquisition provided MarkWest Energy Partners with a new area for growth in the Southwest and diversified its lines of business and revenues. In addition, the acquisition is expected to increase the stability of the Partnership's cash flows because Pinnacle has a high percentage of fee-based lateral pipeline contracts.

Lubbock Pipeline Acquisition. Effective September 1, 2003, MarkWest Energy Partners completed the acquisition of an intrastate gas transmission pipeline and related assets near Lubbock, Texas, from Power-Tex Joint Venture, a subsidiary of ConocoPhillips, for $12.2 million in cash. This gas pipeline is the only connection between the Northern Natural Gas and El Paso interstate pipelines and the City of

Lubbock. Its customers include the City of Lubbock, Texas Tech University, Xcel Energy and several other end-use consumers. This acquisition allowed the Partnership to further expand its operations in the Southwest with an additional lateral system while providing an added source of fee-based cash flows.

Western Oklahoma Acquisition. On December 1, 2003, MarkWest Energy Partners completed the acquisition of substantially all of the assets of American Central Western Oklahoma Gas Company, LLC for approximately $38.0 million in cash. These assets include 167 miles of natural gas gathering pipeline, known as the Foss Lake gathering system, and the associated Arapaho gas processing plant in western Oklahoma. The Foss Lake gathering system, which has a current capacity of 65.0 MMcf/d, connects to approximately 270 wells. The Arapaho gas processing plant has a current capacity of 75.0 MMcf/d. Capacity on the gathering system can be expanded to 75.0 MMcf/d with additional compression. By establishing a presence in Oklahoma, this acquisition significantly expanded the Partnership's Southwest operations.

Michigan Crude Pipeline Acquisition. On December 18, 2003, the Partnership completed the acquisition of approximately 250 miles of intrastate crude oil gathering pipeline, for $21.3 million in cash. The pipeline serves over 1,000 oil and gas wells on the Niagaran Reef Trend and has 487,000 barrels of storage capacity in 15 storage tanks. This acquisition further diversifies the Partnership's lines of business with the addition of crude oil gathering and transportation services. The acquisition also provides the Partnership with the opportunity to leverage off its existing infrastructure and personnel in Michigan while adding additional fee-based cash flows.

Initial and Secondary Public Offerings of MarkWest Energy Partners, L.P.

Initial Public Offering

On May 24, 2002, MarkWest Hydrocarbon contributed most of the assets, liabilities and operations of our midstream business to MarkWest Energy Partners, L.P. 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), and $63.5 million in cash (which was used to pay down bank debt). The Partnership closed its initial public offering on that date selling 2,415,000 common units (including the underwriters' exercise of their over-allotment option) for gross proceeds of $49 million and net proceeds (after fees and expenses) of $43 million. Concurrent with its initial public offering the Partnership borrowed $21.4 million. MarkWest Energy Partners' limited partnership structure reduces its cost of capital thereby enhancing its ability to grow more efficiently.

Secondary Public Offering

On January 12, 2004, the Partnership priced its offering of 1,148,000 common units at $39.90 per unit. Of the 1,148,000 common units, 1,100,444 were sold by the Partnership for gross proceeds of $43.9 million. The remaining 47,556 were sold by certain selling unitholders, proceeds of which have been retained by them, and not the Partnership.

By the terms of the over-allotment provisions of the underwriting agreement, the Partnership granted underwriters a 30-day option to purchase up to 172,200 additional common units. In connection therewith, the Partnership issued an additional 72,500 common units for gross proceeds of $2.9 million during the first quarter of 2004.

Gross proceeds of $46.8 million were reduced by underwriters' fees of $2.5 million and professional fees and other offering costs of $1.0 million, resulting in net proceeds of $43.3 million. The net proceeds were used to pay down the Partnership's credit facility.

As of February 29, 2004, MarkWest Hydrocarbon's partnership interests consisted of the following:

•: 2,469,496 subordinated units, representing a 34.6% limited partner interest in the Partnership; and a
•: 90.2% ownership interest in the general partner of the Partnership. The general partner owns a 2% general partner interest in the Partnership.

MarkWest Hydrocarbon's consolidated financial statements reflect the consolidation of MarkWest Energy Partners, with the public unitholders' interest being reflected as a minority interest in the consolidated statement of operations and the consolidated balance sheet.

Results of Operations

Year Ended December 31, 2003 Compared to the Year Ended December 31, 2002

Revenues. Revenues were $207.7 million for the year ended December 31, 2003, compared to $154.3 million for the year ended December 31, 2002, an increase of $53.3 million, or 35%. The increase was primarily due to MarkWest Energy Partners' acquisitions, which added approximately $54.8 million. Increases in our weighted average NGL product sales prices in Appalachia were generally offset by decreases in our Appalachian NGL and gas marketing sales volumes. Included in our 2003 revenues were approximately $18.8 million in hedging losses, primarily from crude oil hedges, an increase of approximately $11.2 million over the prior year.

Purchased product costs. Purchased product costs were $187.5 million for the year ended December 31, 2003, compared to $127.5 million for the year ended December 31, 2002, an increase of $60.0 million, or 47%. Purchased product costs increased in 2003 primarily due to:

•: MarkWest Energy Partners' acquisitions added approximately $44.8 million.
•: An increase in the weighted average price of our Appalachian replacement natural gas from our keep-whole and percent-of-proceeds contract based business increased purchased product costs $32.6 million.
•: A decrease in the level of gas marketing activity offset the above increases by approximately $19.3 million.

Facility expenses. Facility expenses were $20.0 million for the year ended December 31, 2003, compared to $16.3 million for the year ended December 31, 2002, an increase of $3.7 million, or 23%. Facility expenses increased primarily due to MarkWest Energy Partners' 2003 acquisitions.

Selling, general and administrative expenses. Selling, general and administrative expenses were $14.5 million for the year ended December 31, 2003, compared to $9.4 million for the year ended December 31, 2002, an increase of $5.0 million, or 54%. The increase is principally attributable to MarkWest Energy Partners' 2003 acquisitions; the incremental, public company costs from MarkWest Energy Partners first full year of operations in 2003; and compensation expense related to phantom units granted to our employees.

Depreciation. Depreciation was $8.3 million for the year ended December 31, 2003, compared to $5.7 million for the year ended December 31, 2002, an increase of $2.6 million, or 46%. The increase was principally due to MarkWest Energy Partners' 2003 acquisitions.

Impairment. MarkWest Energy Partners recorded an impairment of $1.1 million related to its Cobb processing facility. The facility is slated to be replaced in mid-2004, at which time the current facility will be retired. The Cobb facility was written down to its estimated recoverable value. No impairment was recorded during the year ended December 31, 2002.

Interest expense, net. Interest expense was $5.9 million for the year ended December 31, 2003, compared to $3.8 million for the year ended December 31, 2002, an increase of $2.2 million, or 57%. The increase was primarily attributable to borrowings by MarkWest Energy Partners to finance its 2003 acquisitions.

Write-down of deferred financing costs. Write-down of deferred financing costs was $0.4 million for the year ended December 31, 2003, compared to $3.0 million for the year ended December 31, 2002, a decrease of $2.6 million, or 86%. The 2003 write-down eliminated the remaining deferred financing costs associated with the MarkWest Hydrocarbon credit facility that was terminated in December 2003.

Income from discontinued operations. Income from discontinued operations was $11.0 million for the year ended December 31, 2003, compared to $1.9 million for the year ended December 31, 2002, an increase of $9.1 million, or 473%. The increase is primarily attributable to the net gain on sales of our oil and gas properties during 2003.

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

Revenue. Revenue was $154.3 million for the year ended December 31, 2002 compared to $173.9 million for the year ended December 31, 2001, a decrease of $19.6 million, or 11%. Revenue was lower in 2002 than in 2001 primarily due to:

•: A decrease in the average NGL product sales price from our keep-whole contract, or "frac spread", business, net of volume increases, which accounted for approximately $3.6 million of the overall decrease. The average NGL sales price was $0.43 per gallon for the year ended December 31, 2002, compared to $0.55 per gallon for the year ended December 31, 2001, a decrease of $0.12 per gallon, or 22%.
•: We recognized a $2.4 million hedging ineffectiveness charge in 2002.
•: A decrease in gas marketing revenues, which accounted for approximately $6.2 million of the decrease. Gas marketing revenues declined in 2002 as natural gas prices retreated from above average levels that existed in 2001, more than offsetting volume increases.
•: A net $5.4 million decrease from our Michigan operations, primarily a function of the sales of an unusual amount of NGL products in the first quarter of 2001.

Purchased gas costs. Purchased gas costs were $127.5 million for the year ended December 31, 2002, compared to $140.2 million for the year ended December 31, 2001, a decrease of $12.7 million, or 9%. Purchased gas costs were lower in 2001 primarily due to:

•: A decrease in our gas marketing cost of goods sold, which accounted for $8.2 million of the overall decrease. Gas marketing costs declined in 2002 as natural gas prices retreated from above average levels that existed in 2001, more than offsetting volume increases.
•: A net $5.6 million decrease from our Michigan operations, primarily a function of the sales of an unusual amount of NGL products in the first quarter of 2001.

Facility expenses. Facility expenses were $16.3 million for the year ended December 31, 2002, compared to $16.5 million for the year ended December 31, 2001, a decrease of $0.3 million, or 2%.

Selling, general and administrative expenses. Selling, general and administrative expenses were $9.4 million for the year ended December 31, 2002, compared to $7.5 million for the year ended December 31, 2001, an increase of $1.9 million, or 26%. The increase primarily stems from the incremental, public company costs from our consolidated subsidiary, MarkWest Energy Partners, which closed its IPO on May 24, 2002.

Depreciation. Depreciation was $5.7 million for the year ended December 31, 2002, compared to $5.2 million, for the year ended December 31, 2001, an increase of $0.5 million, or 11%.

Interest expense, net. Net interest expense was $3.8 million for the year ended December 31, 2002, compared to $3.7 million for the year ended December 31, 2001, an increase of $0.1 million, or 2%.

Income from discontinued operations. Income from discontinued operations was $1.9 million for the year ended December 31, 2002, compared to $2.5 million for the year ended December 31, 2001, a decrease of $0.6 million, or 23%. The decrease was primarily a result of increased depletion expense during 2002.

Write-down of deferred financing costs. We wrote off $3.0 million in deferred financing costs as a result of the May 24, 2002 amendment of our credit facility—which was completed concurrently with the IPO of our consolidated subsidiary, MarkWest Energy Partners—and an earlier amendment.

Gain on sale of non-operating assets. During November 2002, we sold 500,000 of our subordinated units of MarkWest Energy Partners to a third party.

Seasonality

A portion of our revenue and, as a result, our gross margin, is dependent upon the sales prices of natural gas and NGL products, particularly propane, and the purchase price of natural gas 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, we historically recognize a substantial portion of our annual income during the first and fourth quarters of the year.

Liquidity and Capital Resources

MarkWest Hydrocarbon

During 2003, we discontinued our exploration and production activities and sold all of our related Canadian oil and gas properties and substantially all of our U.S. oil and gas properties. The sales netted us $106.7 million in cash. The proceeds were primarily used to pay off and terminate our existing credit facility in its entirety in December 2003. We also had $33.4 million in unrestricted cash on hand at December 31, 2003, exclusive of MarkWest Energy Partners' cash on hand. As a result, our outstanding debt, exclusive of MarkWest Energy Partners' debt, was $0 as of December 31, 2003. In February 2004, we disbursed approximately $4.8 million to pay a special one-time dividend of $0.50 per share to our common shareholders.

Going forward, we expect MarkWest Hydrocarbon's primary sources of liquidity to be quarterly distributions received from MarkWest Energy Partners and cash flows generated from operations, principally the marketing of natural gas and NGLs.

We own 90.2% of the general partner of MarkWest Energy Partners. The general partner of MarkWest Energy Partners owns the 2% general partner interest and all of the incentive distribution rights. The incentive distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they entitle us to receive 13.0% of all cash distributed in a quarter after each unit has received $0.55 for that quarter, 23.0% of all cash distributed after each unit has received $0.625 for that quarter and 48.0% of all cash distributed after each unit has received $0.75 for that quarter. For the year ended December 31, 2003, we received $5.7 million in distributions for our subordinated units, and the general partner received $0.4 million, including $0.2 million representing payments on incentive distribution rights. As the Partnership continues to grow and increase its quarterly distributions per limited partner unit, we expect our distributions to increase accordingly.

Cash flows generated from our marketing operations are subject to volatility in energy prices, especially prices for NGLs and natural gas. Our cash flows are enhanced in periods when the prices received for NGLs are high relative to the price of natural gas we purchase to satisfy our "keep-whole" contractual arrangements in Appalachia, and are reduced in periods when the prices received for NGLs are low relative to the price of natural gas we purchase to satisfy such contractual arrangements. Under "keep-whole" contracts, we retain and sell the NGLs produced in our processing operations for third-party producers, and then reimburse or "keep whole" the producers for the Btu content of the NGLs removed through the re-delivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas. Generally, the value of the NGLs extracted is greater than the cost of replacing those Btus with dry gas, resulting in positive operating margins under these contracts. Periodically, when natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, the cost of keeping the producer "whole" can result in operating losses. For the year ended December 31, 2003, our loss from continuing operations before income taxes was $33.1 million. The loss from operations was primarily caused by the combination of an unfavorable pricing environment (primarily in the first half of 2003) and unfavorable crude oil hedges (throughout 2003). However, prices improved during the latter half of 2003 and remained at or above historical levels into the first quarter of 2004. Additionally, we exited certain unfavorable crude oil hedges in late 2003. We, however, cannot predict with any certainty what the pricing environment will be in the future.

We believe that cash on hand, cash received from quarterly distributions (including the incentive distribution rights) from MarkWest Energy Partners, and cash generated from our marketing operations will be sufficient to meet our working capital requirements and fund our required capital expenditures, if any, for the foreseeable future. Most of our future capital expenditures are discretionary and minimal in nature. During 2004, we have budgeted $1.7 million for our contribution to the Cobb plant replacement and an additional $0.3 million for other miscellaneous projects. Cash generated from our marketing operations will depend on our operating performance, which will be affected by prevailing commodity prices and other factors, some of which are beyond our control.

In an effort to increase our liquidity, we may seek to establish a bank credit facility and renegotiate certain keep-whole contracts in order to reduce our commodity price risk.

MarkWest Energy Partners

For the Partnership, future acquisitions or projects are expected to be financed through a combination of debt and issuance of additional units, as is common practice with master limited partnerships.

As of December 31, 2003, the Partnership had borrowed $126.2 million of the $140 million available under its credit facility. The Partnership paid down its debt by $42 million in January 2004 with the proceeds from its secondary offering.

Cash Flows

	Year Ended December 31,
	2003			2002			2001
	(in thousands)
Net cash provided by (used for) operating activities	$	(6,522	)	$	35,879		$	12,980
Net cash provided by (used for) investing activities	$	(36,887	)	$	(22,479	)	$	(77,643	)
Net cash provided by (used for) financing activities	$	79,067		$	(9,338	)	$	66,087

Net cash used in operations during 2003 resulted primarily from losses from operations. Net cash provided by operations increased during 2002 relative to 2001 primarily because 2002 represented the first full year of our Canadian operations.

Net cash flows used in investing activities increased during 2003 relative to 2002 principally due to cash paid for the Partnership's 2003 acquisitions (net of proceeds from 2003 dispositions). Net cash used in investing activities decreased in 2002 relative to 2001 due to cash paid for our 2001 Canadian acquisitions.

Net cash provided by financing activities during 2003 was primarily a result of borrowing by the Partnership to fund its acquisitions. Net cash used in financing activities in 2002 was primarily the result of using the proceeds from the Partnership's initial public offering to pay down debt. Net cash provided by financing activities in 2001 was principally due to borrowings used to finance our two Canadian acquisitions.

Total Contractual Cash Obligations

A summary of our total contractual cash obligations as of December 31, 2003, is as follows:

	Payment Due by Period
Type of obligation	Total obligation		Due in 2004		Due in 2005-2006		Due in 2007-2008		Thereafter
Long-term debt	$	126,200	$	—	$	126,200	$	—	$	—
Operating leases		11,018		2,180		3,469		2,765		2,604

Total contractual cash obligations	$	137,218	$	2,180	$	129,669	$	2,765	$	2,604

Credit Facility

You should read Note 9 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K, which is incorporated herein by reference, for information on our financing facilities.

Related Parties

You should read Note 16 of the accompanying Notes to consolidated Financial Statements included in Item 8 of this Form 10-K, which is incorporated herein by reference, for information regarding related parties.

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 policies are discussed below. You should also read Note 2 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K, which is incorporated herein by reference.

Impairment of Long-Lived 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, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value. 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.

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.
•: The availability and prices of crude oil.
•: Our ability to negotiate favorable marketing agreements.
•: The risks that third party oil and 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.
•: Competition from other midstream service providers, 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.

Commodity Price Risk Management Activities

We account for price risk management activities based upon the fair value accounting methods prescribed by SFAS No. 133, Accounting for Derivative Instruments. Risk management activities include utilizing various hedging contracts and other derivatives to reduce volatility in our cash flow. SFAS No. 133 requires that we determine the fair value of the instruments we use in these business activities and reflect them in our balance sheet at their fair values. However, changes in the fair value of our cash flow hedges are generally recognized in our income statement when the hedge is settled.

The determination of fair value for our hedging derivatives requires substantial judgment. The fair values of our derivatives are based upon certain estimations and internal valuation techniques. These estimations use various factors that include closing exchange prices on the NYMEX, over-the-counter quotations, correlation of the hedged items to the hedging instruments and basis (location) differences. The factors underlying our estimates of fair value and our assessment of correlation of our hedging derivatives are impacted by market volatility and changes.

Recent Accounting Pronouncements

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, as amended. This statement amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. In general, SFAS No. 149 was effective for the Company on a prospective basis for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after that date. The adoption of SFAS No. 149 had no impact on our results of operations, financial position or cash flows.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. SFAS No. 150 requires that certain financial instruments previously classified as equity be classified as liabilities or, in some cases, as assets. The adoption of SFAS No. 150 had no impact on our results of operations, financial position or cash flows.

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51, which it revised in December 2003 (collectively, FIN 46). FIN 46 requires the consolidation of certain variable interest entities, as defined. FIN 46 is effective for the Company as of December 31, 2003, as it relates to special-purpose entities, as defined, and in the first quarter 2004 for all other types of variable interest entities. 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 did not have an impact on our 2003 financial statements and is not expected to have an impact on our 2004 results of operations, financial position or cash flows.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity price variations and also incur, to a lesser extent, credit risks and risks related to interest rate variations.

Commodity Price Risk

Through our consolidated subsidiary, MarkWest Energy Partners, L.P., we are engaged in the gathering, processing and transmission of natural gas, the transportation, fractionation and storage of NGLs and the gathering and transportation of crude oil. We also market natural gas and NGL products. Our products are commodities that are subject to price risk resulting from material changes in response to fluctuations in supply and demand, general economic conditions and other market conditions, such as weather patterns, over which we have no control.

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, oversees all of our hedging activity.

We utilize a combination of fixed-price forward contracts, fixed-for-float price swaps and options on the over-the-counter (OTC) market. New York Mercantile Exchange (NYMEX) traded futures are authorized for use. Swaps and futures allow us to protect our margins because corresponding losses or gains in the value of financial instruments are generally offset by gains or losses in the physical market.

We enter OTC swaps with financial institutions and other energy company counterparties. We use standardized swap agreements that allow for the 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 natural gas, NGLs or crude oil or otherwise fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against unfavorable changes in such prices.

In addition to these risk management tools, we utilize our NGL product storage facilities and contracts for third-party storage to build product inventories during lower-demand periods for resale during higher-demand periods.

Types of Price Risk

Within our NGL marketing segment, our price risk varies by contract as well as by spot market prices for both NGL and natural gas commodities. Our Appalachian producers compensate us for providing midstream services under one of two contract types:

•: Under "keep-whole" contracts, we take title to and sell the NGLs produced in our processing operations. We also reimburse or "keep whole" the producers for the Btu content of the NGLs removed through the re-delivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas. Keep-whole contracts therefore expose us to NGL product price risk (on the sales side) and natural gas price risk (on the purchase or reimbursement side).
•: Under "percent-of-proceeds" contracts, we take title to the NGLs produced in our processing operations, sell the NGLs to third parties and pay the producer a specified percentage of the proceeds received from the sales. Percent-of-proceeds contracts therefore expose us to NGL product price risk. All of our Michigan processing business is also governed by percent-of-proceeds contracts.

Basis Risk

We are also subject to basis risk, which is the risk that an adverse change in the hedging market will not be completely offset by an equal and opposite change in the price of the physical commodity being hedged. Basis risk is primarily due to geographic price differentials between our physical sales locations and the hedging contract delivery location. While we are able to hedge our basis risk for natural gas commodity transactions in the readily available natural gas financial marketplace, similar markets do not exist for hedging basis risk on NGL products. NGL product basis risk also results from the difference in relative price movements between crude oil and NGL products. We may use crude oil, instead of NGL products, in our hedges because the NGL hedge products and markets are limited. Crude oil is typically highly correlated with certain NGL products. We hedge our NGL product sales by selling forward propane or crude oil.

Commodity Risk Management Position

As of December 31, 2003, we have hedged NGLs and natural gas sales as follows:

		Year Ending December 31,
		2004		2005
*MarkWest Hydrocarbon, Inc.*
NGL Volumes Hedged Using Crude Oil
	NGL gallons		6,756,737		—
	NGL sales price per gallon	$	0.525	$	NA
*MarkWest Energy Partners, L.P.*
Hedged Natural Gas Sales
	Natural gas MMBtu		183,000		182,500
	Natural gas sales price per MMBtu	$	4.57	$	4.26
Natural Gas Puts
	Natural gas MMBtu		366,000		—
	Natural gas sales price per MMBtu	$	4.00	$	NA
Total Hedged Natural Gas
	Natural gas MMBtu		549,000		182,500
	Natural gas sales price per MMBtu	$	4.19	$	4.26

As of December 31, 2003, we are not a party to any basis risk hedges.

Credit Risk

Counterparties, pursuant to the terms of their contractual obligations, expose us to potential losses as a result of nonperformance. We maintain credit policies with regard to our counterparties that we believe minimize overall credit risk. Such policies include the evaluation of a prospective counterparty's financial condition, collateral requirements where deemed necessary, and the use of standardized agreements, which facilitate the netting of cash flows associated with a single counterparty. We also monitor the financial condition of existing counterparties on an ongoing basis. In general, our risk of default by these counterparties is low. However, we experienced a loss in 2001 as described below.

SFAS No. 133 provides that hedge accounting must be discontinued on contracts when it becomes reasonably possible that the counterparty will default. During the fourth quarter of 2001, Enron Corporation and its subsidiaries (Enron) filed for bankruptcy protection. In response to this filing, we terminated all derivative contracts where Enron was the counterparty. As a result, in 2001 we wrote off $1.1 million of risk management assets related to our cash flow hedges offset by $0.1 million of risk management liabilities related to our fair value hedges. In addition, our contracts with Enron provided for netting of amounts owed to each other and as such we netted $0.6 million in amounts payable to Enron. The net result of the above transactions was a charge of $0.4 million to earnings in the fourth quarter of 2001. In the case of discontinued hedge accounting for cash flow hedges, SFAS No. 133 provides the amount in other comprehensive income will be reclassified to earnings in the periods of the forecasted transactions. As such, we reclassified $0.2 and $0.8 million from other comprehensive income to revenue, net of $0.1 million and $0.3 million of deferred taxes for 2003 and 2002, respectively.

While we enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that additional losses will result from counterparty credit risk in the future.

Interest Rate Risk

Through our consolidated subsidiary, MarkWest Energy Partners, L.P., we are exposed to changes in interest rates, primarily as a result of our long-term debt with floating interest rates. MarkWest Energy Partners may make use of interest rate swap agreements during the term of the Partnership's Credit Facility that matures on November 30, 2006, to adjust the ratio of fixed and floating rates in the debt portfolio. As of December 31, 2003, the Partnership is a party to contracts to fix interest rates on $8.0 million of debt at 3.85% through May 2005, compared to floating LIBOR, plus an applicable margin.

Sensitivities

Our annual sensitivities to changes in commodity prices considering our hedge position are as follows:

MarkWest Hydrocarbon, Inc.

•: for every $0.10 per MMBtu increase in the natural gas price, our gross margin would decrease by $1.0 million; and
•: for every $0.01 per gallon reduction in NGL prices, our gross margin would decrease by $1.7 million.

MarkWest Energy Partners, L.P.

•: for every $0.10 per MMBtu increase in the natural gas price, the Partnership's gross margin, exclusive of the Arapaho processing plant, would increase by $0.3 million, and
•: for every $0.02 per gallon reduction in NGL prices, exclusive of the Arapaho processing plant, the Partnership's gross margin would decrease by $0.1 million.

The Partnership's Arapaho plant processing margins are sensitive to commodity price changes. Because of the nature of the contracts associated with the plant, gross margin increases as the price of NGLs increases relative to natural gas and gross margin decreases as the price of natural gas increases relative to the price of NGLs. In the latter case, however, the Partnership has the option of not operating the plant in a low processing margin environment since the Btu content of the inlet natural gas meets the Btu specification of the interstate line into which the natural gas is delivered. A $0.01 per Mcf change in the processing margin results in a $0.2 million change in gross margin.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements


Report of Independent Auditors
Consolidated Balance Sheets at December 31, 2003 and 2002
Consolidated Statements of Operations for each of the three years in the period ended December 31, 2003
Consolidated Statements of Comprehensive Income (Loss) for each of the three years in the period ended December 31, 2003
Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2003
Consolidated Statements of Changes in Stockholders' Equity for each of the three years in the period ended December 31, 2003
Notes to Consolidated Financial Statements

REPORT OF INDEPENDENT AUDITORS

To the Board of Directors and Stockholders of MarkWest Hydrocarbon, Inc.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income (loss), of cash flows and of changes in stockholders' equity present fairly, in all material respects, the financial position of MarkWest Hydrocarbon, Inc., a Delaware corporation, and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company'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 discussed in Note 2 to the consolidated financial statements, MarkWest Hydrocarbon, Inc. changed its method of accounting for inventory effective January 1, 2002. As discussed in Note 13 to the consolidated financial statements, MarkWest Hydrocarbon, Inc. changed its method of accounting for derivative instruments and hedging activities in accordance with Statement of Financial Accounting Standards No. 133 on January 1, 2001. As discussed in Note 8 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143 on January 1, 2002.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado
March 30, 2004

MARKWEST HYDROCARBON, INC.

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)

				December 31,
				2003			2002
ASSETS
Current assets:
	Cash and cash equivalents			$	42,144		$	6,410
	Restricted cash				2,500			—
	Receivables, including related party receivables of $40 and $748, respectively, and net of allowance for doubtful accounts of $120 and $0, respectively				30,750			25,444
	Inventories				4,815			4,347
	Prepaid replacement natural gas				5,940			1,197
	Deferred income taxes				603			4,958
	Other assets				503			1,240

		Total current assets			87,255			43,596

Property, plant and equipment					232,257			270,235
Less: accumulated depreciation, depletion, amortization and impairment					(44,134	)		(58,717	)

		Total property, plant and equipment, net			188,123			211,518

Intangible assets, net of accumulated amortization of $1,275 and $2,018, respectively					3,831			2,138
Deferred offering costs					1,037			—
Investment in and advances to equity investee					250			—
Notes receivables from officers and other assets					217			271

		Total assets		$	280,713		$	257,523

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable, including related party payables of $51 and $1,264, respectively			$	24,052		$	26,063
	Accrued liabilities				16,751			8,145
	Risk management liability				1,769			13,719

		Total current liabilities			42,572			47,927

Deferred income taxes					6,346			39,894
Long-term debt					126,200			64,223
Risk management liability					125			2,115
Other long-term liabilities					504			4,011
Minority interest in consolidated subsidiary					52,782			46,001
Commitments and contingencies (see Note 18)
Stockholders' equity:
	Preferred stock, par value $0.01; 5,000,000 shares authorized, no shares outstanding				—			—
	Common stock, par value $0.01; 20,000,000 shares authorized, 9,637,977 and 9,370,790 shares issued, respectively				96			95
	Additional paid-in capital				50,715			48,818
	Retained earnings				3,676			13,625
	Accumulated other comprehensive loss, net of tax				(1,793	)		(8,858	)
	Treasury stock; 75,930 and 50,335 shares, respectively				(510	)		(328	)

		Total stockholders' equity			52,184			53,352

			Total liabilities and stockholders' equity	$	280,713		$	257,523

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

			Year Ended December 31,
			2003			2002			2001
Revenues			$	207,651		$	154,338		$	173,890
Operating expenses:
	Purchased product costs			187,544			127,526			140,225
	Facility expenses			19,977			16,257			16,522
	Selling, general and administrative expenses			14,465			9,420			7,502
	Depreciation			8,333			5,703			5,156
	Impairment			1,148			—			—

		Total operating expenses		231,467			158,906			169,405

		Income (loss) from operations		(23,816	)		(4,568	)		4,485
Other income and expense:
	Interest expense, net			(5,930	)		(3,775	)		(3,700	)
	Write-down of deferred financing costs			(415	)		(2,977	)		—
	Gain on sale of non-operating assets			—			5,454			—
	Gain on sale of non-operating assets to related parties			382			141			—
	Minority interest in net income of consolidated subsidiary			(3,236	)		(1,947	)		—
	Other expense, net			(92	)		(73	)		(231	)

		Income (loss) from continuing operations before income taxes		(33,107	)		(7,745	)		554

Provision (benefit) for income taxes:
	Current			(13,352	)		—			54
	Deferred			1,143			(3,032	)		185

		Provision (benefit) for income taxes		(12,209	)		(3,032	)		239

		Income (loss) from continuing operations		(20,898	)		(4,713	)		315

Discontinued operations (Note 5):
	Income from discontinued exploration and production operations (less applicable income taxes of $671, $1,220 and $1,342, respectively)			630			1,917			2,495
	Gain from disposal of discontinued exploration and production operations, including provision of $0 for operating losses during the phase-out period (less applicable income taxes of $6,322)			10,348			—			—

		Income from discontinued operations		10,978			1,917			2,495

		Income (loss) before cumulative effect of accounting change		(9,920	)		(2,796	)		2,810
Cumulative effect of change in accounting for asset retirement obligations, net of tax				(29	)		—			—

		Net income (loss)	$	(9,949	)	$	(2,796	)	$	2,810

Income (loss) from continuing operations per share:
		Basic	$	(2.23	)	$	(0.50	)	$	0.04

		Diluted	$	(2.23	)	$	(0.50	)	$	0.04

Net income (loss) per share:
		Basic	$	(1.06	)	$	(0.30	)	$	0.30

		Diluted	$	(1.06	)	$	(0.30	)	$	0.30

Weighted average number of outstanding shares of common stock:
		Basic		9,389			9,349			9,326

		Diluted		9,406			9,363			9,349

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

			Year Ended December 31,
			2003			2002			2001
Net income (loss)			$	(9,949	)	$	(2,796	)	$	2,810

Other comprehensive income (loss):
	Cumulative effect of change in accounting principle, net of tax			—			—			(1,230	)
	Risk management activities, net of tax			6,390			(13,606	)		6,328

		Ending accumulated derivative gain, net of tax		6,390			(13,606	)		5,098
	Foreign currency translation, net of tax			675			471			(821	)

		Total other comprehensive income (loss)		7,065			(13,135	)		4,277

	Comprehensive income (loss)		$	(2,884	)	$	(15,931	)	$	7,087

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

			Year Ended December 31,
			2003			2002			2001
Cash flows from operating activities:
Net income (loss)			$	(9,949	)	$	(2,796	)	$	2,810
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
	Cumulative effect of change in accounting principle			29			—			—
	Depreciation, depletion and amortization			24,489			21,388			10,327
	Impairment			2,187			—			—
	Amortization of deferred financing costs included in interest expense			1,689			1,366			719
	Write-off of deferred financing costs			415			2,977			—
	Minority interest in net income of subsidiary			3,235			1,947			—
	Derivative (effectiveness) ineffectiveness			(2,469	)		2,386			—
	Terminated derivative contracts			(719	)		—			—
	Deferred income taxes			(1,577	)		(2,574	)		1,499
	Phantom unit compensation expense			1,357			—			—
	Gain from sale of San Juan Basin properties			(23,279	)		—			—
	Loss from sales of MarkWest Resources Canada Corp. and MarkWest Midstream Services, Inc.			4,822			—			—
	Loss from sale of eastern Michigan oil and gas properties			1,788			—			—
	Loss from sale of other operating assets			30			—			—
	Gain on sale of non-operating assets			—			(5,454	)		—
	Gain on sale of non-operating asset to related party			(382	)		(141	)		—
	Write-off Enron financial position, net of tax			—			—			436
	Reclassification of Enron hedges to purchased product costs			(153	)		(697	)		341
	Other			—			114			(75	)
Changes in operating assets and liabilities, net of the effects of working capital assumed through acquisitions and dispositions:
	(Increase) decrease in receivables			(1,230	)		(5,894	)		19,580
	(Increase) decrease in inventories			(468	)		1,997			1,714
	(Increase) decrease in prepaid replacement natural gas and other assets			(7,380	)		7,055			(8,406	)
	Increase (decrease) in accounts payable and accrued liabilities			8,233			11,115			(15,965	)
	Increase (decrease) in other long-term liabilities			(7,190	)		3,090			—

		Net cash provided by (used in) operating activities		(6,522	)		35,879			12,980
Cash flows from investing activities:
	Increase in restricted cash			(2,500	)		—			—
	Pinnacle acquisition, net of cash acquired			(38,526	)		—			—
	Lubbock pipeline acquisition			(12,235	)		—			—
	Western Oklahoma acquisition			(37,951	)		—			—
	Michigan crude pipeline acquisition			(21,283	)		—			—
	Capital expenditures			(31,007	)		(31,683	)		(32,161	)
	Acquisition of Canadian operations, net of cash acquired			—			—			(46,136	)
	Proceeds from sale of San Juan Basin properties			55,251			—			—
	Proceeds from the sale of MarkWest Resources Canada Corp. and MarkWest Midstream Services, Inc.			49,097			—			—
	Proceeds from sale of property, plant and equipment			2,517			791			654
	Proceeds from sale of Partnership subordinated units and general partner interest to related party			—			263			—
	Proceeds from sale of Partnership subordinated units			—			8,173			—
	Acquisition of Partnership subordinated units and general partner interest			—			(23	)		—
	Equity investment			(250	)		—			—

		Net cash used in investing activities		(36,887	)		(22,479	)		(77,643	)

Continued on next page.
The accompanying notes are an integral part of these financial statements.

				Year Ended December 31,
				2003			2002			2001
Cash flows from financing activities:
	Payments for deferred offering costs				(389	)		—			—
	Proceeds from long-term debt				452,778			65,047			199,229
	Repayments of long-term debt				(373,925	)		(113,947	)		(128,851	)
	Proceeds from initial public offering, net				—			42,975			—
	Proceeds from private placement, net				9,774			—			—
	Debt issuance costs				(4,070	)		(1,889	)		(4,643	)
	Distributions to MarkWest Energy Partners unitholders				(7,311	)		(1,739	)		—
	Exercise of stock options				1,899			2			18
	Net reissuance (purchase) of treasury shares				(182	)		200			334
	Payment on share purchase notes				—			13			—
	Proceeds from sale of MarkWest Energy Partners Units				493			—			—

		Net cash provided by (used in) financing activities			79,067			(9,338	)		66,087
Effect of exchange rate on changes in cash					76			8			(18	)

Net increase (decrease) in cash and cash equivalents					35,734			4,070			1,406
Cash and cash equivalents at beginning of year					6,410			2,340			934

Cash and cash equivalents at end of year				$	42,144		$	6,410		$	2,340

Supplemental disclosures of cash flow information:
	Cash paid during the year for:
		Interest		$	3,868		$	3,834		$	3,968

		Capitalized interest		$	1,448		$	1,899		$	950

		Taxes		$	(114	)	$	(927	)	$	3,834

Supplemental disclosures of noncash investing and financing activities:
	Property, plant and equipment asset retirement obligation			$	3,994		$	—		$	—

	Deferred offering costs			$	606		$	—		$	—

	Stock dividend:
		Common stock		$	9		$	—		$	—
		Additional paid-in capital			6,058			—			—

			Capitalization of retained earnings	$	6,067		$	—		$	—

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

MARKWEST HYDROCARBON, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDERS' EQUITY

(in thousands)

	Shares of Common Stock	Shares of Treasury Stock		Common Stock		Additional Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total Stockholders' Equity
Balance, December 31, 2000	8,561	(104	)	$	86	$	42,471	$	19,679		$	—		$	(642	)	$	61,594
Stock dividend (Note 10)	807	—			8		6,060		(6,068	)		—			—			—
Net income	—	—			—		—		2,810			—			—			2,810
Other comprehensive income												4,277						4,277
Exercise of options	3	—			1		17		—			—			—			18
Reissuance of treasury stock	—	44			—		59		—			—			275			334

Balance, December 31, 2001	9,371	(60	)		95		48,607		16,421			4,277			(367	)		69,033
Net loss	—	—			—		—		(2,796	)		—			—			(2,796	)
Other comprehensive loss	—	—			—		—		—			(13,135	)		—			(13,135	)
Payment on share purchase notes	—	—			—		13		—			—			—			13
Forfeiture of share purchase notes	—	20			—		176		—			—			(141	)		35
Exercise of options	—	—			—		2		—			—			—			2
Net treasury stock (acquisitions) reissuances	—	(10	)		—		20		—			—			180			200

Balance, December 31, 2002	9,371	(50	)		95		48,818		13,625			(8,858	)		(328	)		53,352
Exercise of options	267	—			1		1,897		—			—			—			1,898
Treasury stock		(26	)									—			(182	)		(182	)
Net loss	—	—			—		—		(9,949	)		—			—			(9,949	)
Other comprehensive income	—	—			—		—		—			7,065			—			7,065

Balance, December 31, 2003	9,638	(76	)	$	96	$	50,715	$	3,676		$	(1,793	)	$	(510	)	$	52,184

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

MARKWEST HYDROCARBON, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Nature of Operations

MarkWest Hydrocarbon, Inc. (MarkWest Hydrocarbon or the Company) manages MarkWest Energy Partners, L.P. (MarkWest Energy Partners or the Partnership), a publicly-traded limited partnership engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids (NGLs); and the gathering and transportation of crude oil. We also market natural gas and NGLs. MarkWest Hydrocarbon and MarkWest Energy Partners provide services primarily in Appalachia, Michigan, and the Southwest.

Our assets consist almost exclusively of partnership interests in MarkWest Energy Partners. As of December 31, 2003, these partnership interests consisted of the following:

•: 2,468,129 subordinated units, representing a 41.6% limited partner interest in the Partnership; and an
•: 89.7% ownership interest in MarkWest Energy GP, L.L.C., the general partner of the Partnership, which owns a 2.0% general partner interest and all of the incentive distribution rights in the Partnership. Officers of MarkWest Hydrocarbon own the remainder of the ownership interest in the general partner.

MarkWest Energy Partners completed a secondary offering of units in January 2004, thereby reducing our ownership interest percentages (see Note 10). As of February 29, 2004, our partnership interests consisted of the following:

•: 2,469,496 subordinated units, representing a 34.6% limited partner interest in the Partnership; and a
•: 90.2% ownership interest in the general partner of the Partnership.

2. Summary of Significant Accounting Policies

Basis of Presentation

Our consolidated financial statements include the accounts of all majority-owned or controlled subsidiaries, including the accounts of MarkWest Energy Partners, after the elimination of all significant intercompany accounts and transactions. Our financial statements for prior periods include reclassifications that were made to conform to the current year presentation. Aside from reclassifications related to discontinued operations, those reclassifications had no impact on reported net income or stockholders' equity.

Principles of Consolidation

We consolidate entities when we have the ability to control the operating and financial decisions and policies of that entity. The determination of our ability to control or exert significant influence over an entity involves the use of judgment of the extent of our control or influence and that of the other equity owners or participants of the entity.

Minority Interest

The minority interest in consolidated subsidiary on the consolidated balance sheet represents the minority (non-MarkWest Hydrocarbon) shareholders' investment in the Partnership plus the minority shareholders' share of the net income of the Partnership since its initial public offering on May 24, 2002. Minority interest in net income of consolidated subsidiary in the consolidated statement of operations represents the minority shareholders' share of the net income of the Partnership.

Use of Estimates

The preparation of financial statements in conformity with U.S. 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.

Cash and Cash Equivalents

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Investments are limited to overnight investments of end-of-day cash balances.

Restricted Cash

Restricted cash is comprised of $2.5 million residing in an investment account as per the terms of the Security Agreement between MarkWest Hydrocarbon and a subsidiary of MarkWest Energy Partners, MarkWest Energy Operating Company L.L.C. The restricted cash is a deposit to secure certain intercompany obligations between MarkWest Hydrocarbon and MarkWest Energy Partners.

Inventories

Product inventory consists of propane, butane, isobutane, natural gasoline and natural gas and is valued at the lower of weighted average cost or market. Prior to 2002, our product inventory was valued at the lower of cost, using the first-in, first-out method (FIFO), or market. The change in accounting method from FIFO to weighted average cost was made to better match purchased gas costs with revenues on a quarterly basis and to account for NGL product inventories on a consistent basis with other industry peer companies. The cumulative effect of the change in accounting was not material as of January 1, 2002. If we would have changed our method of accounting from FIFO to weighted average cost on January 1, 2001, income from continuing operations before income taxes, net income and basic earnings per share would have been as follows for the year ended December 31, 2001, on a pro forma basis:

	Year Ended December 31, 2001
Pro forma income from continuing operations before income taxes	$	807
Pro forma net income	$	2,972
Pro forma basic earning per share	$	0.32

Prepaid Replacement Natural Gas

Prepaid replacement natural gas consists of natural gas purchased in advance of its actual use in our Appalachia processing business. Replacement natural gas purchased as a result of our hedging program is valued using the specific identification method. Unhedged replacement natural gas is valued using the weighted average cost 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, facilities

and processing plants, fractionation and storage facilities, natural gas pipelines, crude oil pipelines and NGL transportation facilities, 20 years or the number of years reserves behind our facilities are contractually obligated, whichever is longer; buildings, 40 years; furniture, leasehold improvements and other, 3 to 10 years.

Oil and gas properties and equipment consist of leasehold costs, producing and non-producing properties, oil and gas wells, and capitalized interest. We use the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves are capitalized to the full cost pool. Depletion for oil and gas properties is provided for using the units-of-production method.

These capitalized costs, including estimated future costs to develop the reserves and estimated abandonment costs, net of salvage value, are amortized on a units-of-production basis using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment of such properties indicate that the properties are impaired, the amount of impairment is added to the capitalized cost base to be amortized.

Depletion per unit of production (Mcfe) for each of our cost centers was as follows:

	United States		Canada
2003	$	0.80	$	2.47
2002	$	0.68	$	1.83
2001	$	0.61	$	1.66

The capitalized costs included in the full cost pool are subject to a "ceiling test," which limits such costs to the aggregate of the estimated present value, using a 10% discount rate, of the future net revenues from proved reserves, based on current economics and operating conditions. The ceiling test includes hedging contracts in place at the end of each year. We impaired our remaining U.S. properties by $1.0 million for the year ended December 31, 2003. No impairment existed during each of the two years in the period ended December 31, 2002.

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in the consolidated statement of operations.

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 our long-lived assets (excluding the full cost pool), 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, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value. 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.

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.
•: The availability and prices of crude oil.
•: Our ability to negotiate favorable marketing agreements.
•: The risks that third party oil and 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.
•: Competition from other midstream service providers, 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.

For the year ended December 31, 2003, MarkWest Energy Partners recorded a charge of $1.1 million related to the impairment of its Cobb facility. See Note 7 for further discussion regarding the Cobb processing plant. No impairment charges were recognized during each of the years ended December 31, 2002 and 2001.

Capitalization of Interest

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

Intangible Assets

Intangible assets primarily consist of 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.

Accrued Liabilities

At December 31, 2003, accrued liabilities are comprised of $6.3 million of replacement natural gas payable and other liabilities totaling $10.5 million.

Commodity Price Risk Management Activities

In June 1998, SFAS No. 133, Accounting for Derivative Instruments, was issued effective for fiscal years beginning after June 15, 2000. Under SFAS No. 133, which was subsequently amended by SFAS No. 138 and SFAS No. 149, 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.

We currently hedge the sale of future NGL production with crude oil futures contracts. Based on historical regression analysis, these contracts are effective for hedge accounting treatment. To determine

the current period ineffectiveness computation, we compare the futures market's value for existing crude oil futures contracts (the resulting mark to market adjustment) to the future value of the NGLs hedged.

Concentration of Credit Risk

Financial instruments that subject us to concentrations of credit risk consist principally of trade accounts receivable. Our customers are concentrated within the Appalachian basin, Michigan and Southwest geographic areas and the retail propane, refining, petrochemical and other energy-based industries. Consequently, changes within these regions and/or industries have the potential to impact, both positively and negatively, our exposure to credit risk. The concentration of credit risk in a single industry affects our overall exposure to credit risk because customers may be similarly affected by changes in economic or other conditions. We have not experienced significant credit losses on our receivables.

Treasury Stock

Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock. Treasury stock sold or reissued is relieved on a weighted average cost basis.

Fair Value of Financial Instruments

Our financial instruments consist of cash and cash equivalents, receivables, accounts payable and other current liabilities, and long-term debt. Except for long-term debt, the carrying amounts of financial instruments approximate fair value due to their short maturities. At December 31, 2003 and 2002, based on rates available for similar types of debt, the fair value of long-term debt was not materially different from its carrying amount.

Revenue Recognition

Gas gathering and processing, NGL fractionation, transportation and storage revenues are recognized as volumes are processed, fractionated, transported and stored in accordance with contractual terms. Gas volumes received may be different from gas volumes delivered resulting in gas imbalances. We record a receivable or payable for such imbalances based upon each imbalance's contractual terms. Revenues for the transportation of crude are recognized (i) based upon regulated tariff rates and the related transportation volumes and (ii) when delivery of crude is made to the shipper or other common carrier pipeline. Revenue for natural gas and NGL product sales is recognized at the time the title is transferred.

Income Taxes

Deferred income taxes reflect the impact of "temporary differences" between amounts of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws. These temporary differences are determined in accordance with the liability method of accounting for income taxes as prescribed by SFAS No. 109, Accounting for Income Taxes.

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 stock-based and unit-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. We have a fixed compensation plan and, through our consolidated subsidiary, MarkWest Energy

Partners, we have a variable plan. We account for these plans using fixed and variable accounting as appropriate.

Had compensation cost for our two stock-based compensation plans been determined based on the fair value at the grant dates under those plans consistent with the method prescribed by SFAS No. 123, Accounting for Stock-Based Compensation, our net income and earnings per share would have been reduced to the pro forma amounts listed below:

		Year Ended December 31,
		2003			2002			2001
		(in thousands, expect per share data)
Net income (loss), as reported		$	(9,949	)	$	(2,796	)	$	2,810
Add: compensation expense included in reported net income (loss)			1,398			73			—
Deduct: total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effect			(1,626	)		(442	)		(534	)

Pro forma net income (loss)		$	(10,177	)	$	(3,165	)	$	2,276

Net income (loss) per share:
	Basic, as reported	$	(1.06	)	$	(0.30	)	$	0.30
	Basic, pro forma	$	(1.08	)	$	(0.34	)	$	0.24
	Diluted, as reported	$	(1.06	)	$	(0.30	)	$	0.30
	Diluted, pro forma	$	(1.08	)	$	(0.34	)	$	0.24

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. Our 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.

Earnings (Loss) Per Share

Basic earnings (loss) per share are determined by dividing net income (loss) by the weighted-average number of common shares outstanding during the year. Diluted earnings (loss) per share are determined by dividing net income (loss) by the weighted-average number of common shares and common stock equivalents outstanding, increased by the assumed exercise of stock options convertible into common stock, for which the effect of exercise using the treasury stock method would be dilutive.

Segment Reporting

In accordance with SFAS No. 131, Disclosures About Segments of an Enterprise and Related Information, the internal organization that is used by management for making operating decisions and assessing performance is the source of our reportable segments (see Note 17).

Foreign Currency Translation

On December 2, 2003, we sold all our Canadian subsidiaries and, consequently, no longer have assets, liabilities or operations that require foreign currency translation. Prior thereto, assets and liabilities of our Canadian subsidiary, which had the Canadian dollar as its functional currency, were translated into United States dollars at the foreign currency exchange rate in effect at the applicable reporting date, and the statements of operations were translated at the average rates in effect during the applicable period. The resulting cumulative translation adjustment was recorded as a separate component of other comprehensive income.

Recent Accounting Pronouncements

3. Initial Public Offering of MarkWest Energy Partners, L.P. and Concurrent Transactions

On May 24, 2002, MarkWest Hydrocarbon conveyed most of the assets, liabilities and operations of our midstream business to MarkWest Energy Partners 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.
•: The right to receive $26.7 million in cash upon the closing of the initial public offering (IPO) and MarkWest Energy Operating Company, L.L.C.'s (the Operating Company) new $60 million credit facility. The Operating Company is a wholly owned subsidiary of the Partnership.

The Partnership concurrently issued 2,415,000 common units (including 315,000 units issued pursuant to the underwriters' over-allotment option), representing a 43.7% limited partnership interest in the Partnership, in an IPO at a price of $20.50 per unit. The Operating Company concurrently entered into a $60 million term loan credit facility with various lenders and borrowed $21.4 million upon the closing of the IPO.

Upon the closing of the IPO, MarkWest Hydrocarbon received cash totaling $63.5 million, which was funded by proceeds from the IPO and by Partnership borrowings under its credit facility. We used the cash to repay bank indebtedness.

The common units have preference over the subordinated units with respect to cash distributions and, accordingly, we accounted for the sale of the common units as a sale of a minority interest. Our subordinated units automatically convert to common units on June 30, 2009, but a portion of the subordinated units may convert on or after June 30, 2005 if the Partnership meets certain financial

tests, namely operating surpluses that exceed the minimum quarterly distributions, as defined in the partnership agreement.

4. MarkWest Energy Partners' Acquisitions

Pinnacle Acquisition

On March 28, 2003, the Partnership completed the acquisition (the "Pinnacle Acquisition") of Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG Transmission Company, Inc., PNG Utility Company and Bright Star Gathering, Inc. (collectively, "Pinnacle" or the "Sellers"). Pinnacle's results of operations have been included in the Partnership's consolidated financial statements since that date.

The Pinnacle Acquisition was accomplished through a merger under Texas law of the Sellers and four newly formed wholly owned subsidiaries of the Partnership as buyers. In the merger, most of the assets and liabilities of the Sellers were allocated to the Partnership entities, and all entities survived the merger. The assets acquired from the Sellers, primarily located in the State of Texas, with the balance located in New Mexico, Louisiana, Mississippi and Kansas, are comprised of three lateral natural gas pipelines and twenty gathering systems.

The purchase price was comprised of $23.4 million paid in cash to the Sellers, plus the assumption of specified liabilities, including $16.6 million of bank indebtedness, and was allocated as follows (in thousands):

Acquisition costs:
	Long-term debt incurred		$	39,471
	Direct acquisition costs			450
	Current liabilities assumed			8,945

		Total	$	48,866

Allocation of acquisition costs:
	Current assets		$	10,643
	Fixed assets (including long-term contracts)			38,223

		Total	$	48,866

Pro Forma Results of Operations (Unaudited)

The following table reflects the unaudited pro forma consolidated results of operations for the comparable periods presented, as though the Pinnacle Acquisition had occurred on January 1 in each of the periods presented. These unaudited pro forma results have been prepared for comparative purposes only and may not be indicative of future results.

		Year Ended December 31,
		2003			2002
		(in thousands, except per unit amounts)
Revenue		$	225,438		$	197,638
Net loss(1)		$	(9,234	)	$	(4,929	)
Net loss per share:
	Basic(1)	$	(0.98	)	$	(0.53	)
	Diluted(1)	$	(0.98	)	$	(0.53	)

(1): Includes a one-time impairment charge of $1.7 million for the year ended December 31, 2002.

Western Oklahoma Acquisition

On December 1, 2003, the Partnership completed the acquisition (the "western Oklahoma acquisition") of certain assets of American Central Western Oklahoma Gas Company, L.L.C. ("AWOC") for approximately $38.0 million, before transaction costs and subject to certain post-closing adjustments. Western Oklahoma's results of operations have been included in the Partnership's consolidated financial statements since that date.

The assets include the Foss Lake gathering system (the "gathering system") and the Arapaho gas processing plant. The gathering system is comprised of approximately 167 miles of pipeline, connected to approximately 270 wells, and 11,000 horsepower of compression facilities.

The purchase price of approximately $38.0 million was financed through borrowings under the Partnership line of credit, which was amended at the closing of the acquisition to increase availability under the credit facility from $75 million to $140 million. Substantially all of the acquired assets are pledged to the credit facility lenders to secure the repayment of the outstanding borrowings under the credit facility.

The purchase price was comprised of $38.0 million paid in cash to AWOC, and was allocated as follows (in thousands):

Acquisition costs:
	Cash consideration		$	37,850
	Direct acquisition costs			101

		Total	$	37,951

Allocation of acquisition costs:
	Property, plant and equipment		$	37,951

Pro Forma Results of Operations (Unaudited)

The following table reflects the unaudited pro forma consolidated results of operations for the comparable periods presented, as though the western Oklahoma acquisition had occurred on January 1 in each of the periods presented. These unaudited pro forma results have been prepared for comparative purposes only and may not be indicative of future results.

		Year Ended December 31,
		2003			2002
		(in thousands, except per unit amounts)
Revenue		$	244,667		$	178,989
Net loss(1)		$	(5,015	)	$	(3,383	)
Net loss per share:
	Basic(1)	$	(0.53	)	$	(0.36	)
	Diluted(1)	$	(0.53	)	$	(0.36	)

(1): Includes management fee expense of approximately $1.7 million and $1.9 million for the years ended December 31, 2003 and 2002, respectively.

Michigan Crude Pipeline

On December 18, 2003, the Partnership completed the acquisition (the "Michigan Crude Pipeline acquisition") of Shell Pipeline Company, LP's and Equilon Enterprises, LLC's, doing business as Shell Oil Products US ("Shell"), Michigan Crude Gathering Pipeline (the "System"), for approximately

$21.3 million. The System's results of operations have been included in the Partnership's consolidated financial statements since December 18, 2003. The $21.3 million purchase price was financed through borrowings under the Partnership line of credit.

The System extends from production facilities near Manistee, Michigan to a storage facility near Lewiston, Michigan. The trunk line consists of approximately 150 miles of pipe. Crude oil is gathered into the System from 57 injection points, including 52 central production facilities and five truck unloading facilities, and comprises approximately 100 miles of pipe. The System also includes truck-unloading stations at Manistee, Seeley Road and Junction, and the Samaria Truck Unloading Station located in Monroe County, Michigan, near Toledo, Ohio.

The System is a common carrier Michigan intrastate pipeline and gathers light crude oil from wells. The oil is transported for a fee to the Lewiston, Michigan station where it is batch injected into the Enbridge Lakehead Pipeline, which then transports oil to refineries in Sarnia, Ontario, Canada. The pipeline is an alternative form of crude oil transportation to trucking.

The purchase price was comprised of $21.3 million paid in cash to Shell, and was allocated as follows (in thousands):

Acquisition costs:
	Cash consideration	$	21,155
	Direct acquisition costs		128

	Total	$	21,283

Allocation of acquisition costs:
	Property, plant and equipment	$	21,283

Pro Forma Results of Operations (Unaudited)

The following table reflects the unaudited pro forma consolidated results of operations for the comparable periods presented, as though the Michigan Crude Pipeline Acquisition had occurred on January 1 in each period presented. These unaudited pro forma results have been prepared for comparative purposes only and may not be indicative of future results.

		Year Ended December 31,
		2003			2002
		(in thousands, except per unit amounts)
Revenue		$	211,839		$	159,347
Net loss		$	(10,231	)	$	(2,092	)
Net loss per share:
	Basic	$	(1.09	)	$	(0.22	)
	Diluted	$	(1.09	)	$	(0.22	)

Lubbock Pipeline

Effective September 1, 2003, the Partnership, through its wholly owned subsidiary, MarkWest Pinnacle L.P., completed the acquisition (the "Lubbock Pipeline Acquisition") of a 68-mile intrastate gas transmission pipeline near Lubbock, Texas from a subsidiary of ConocoPhillips for approximately $12.2 million. The transaction was financed through borrowings under the Partnership's credit facility. The pro forma results of operations of the Lubbock Pipeline Acquisition have not been presented as they are not significant.

5. Discontinued Operations

During 2003, we discontinued our exploration and production business. Through a series of dispositions noted below, we sold off substantially all of our U.S. and Canadian oil and gas properties. We owned a minority working interest in three wells in Michigan as of December 31, 2003. The dispositions in chronological order were as follows:

Sales of San Juan Basin Properties

During the second and third quarters of 2003, we completed the sales of our San Juan Basin (U.S.) oil and gas properties to certain third parties for net proceeds in the aggregate of approximately $55.3 million. We recognized an aggregate net pretax gain of $23.3 million on the sales for the year ended December 31, 2003. The proceeds from the sales were used for working capital and general corporate purposes.

Sales of Canadian Properties

During December 2003, we completed the sales of all of our Canadian oil and gas properties to certain third parties for net proceeds in the aggregate of approximately $49.1 million. We recognized an aggregate pretax loss of $4.8 million on the sales for the year ended December 31, 2003. The proceeds from the sales were primarily used to pay off our remaining outstanding debt, exclusive of MarkWest Energy Partners' debt. See Note 9.

Sale of Eastern Michigan Properties

During December 2003, we completed the sale of certain oil and gas properties and related assets located in eastern Michigan for net proceeds of less than $0.1 million. We recognized a pretax loss of $1.8 million.

Financial Statement Impact of Discontinued Operations

For the years ended December 31, 2003, 2002 and 2001, revenues from our discontinued operations were $31.8, $32.9 and $15.2 million, respectively, and income (loss) from discontinued operations before income taxes was $1.3 million, $3.1 million and $3.8 million, respectively.

For the years ended December 31, 2003, 2002 and 2001, the impact to net income (loss) per share from discontinued operations was $1.17, $0.21 and $0.27 per basic and diluted share, respectively.

6. Dispositions

In addition to the dispositions of substantially all of our oil and gas properties (see Note 5), we also sold our Lordstown, Ohio terminal on July 15, 2003 to a third party for approximately $0.7 million, including $0.2 million for on-hand inventory. On September 2, 2003, we sold our Lynchburg, Virginia terminal to a third party for approximately $1.6 million plus on-hand inventory. As a result of the two sales, we incurred a loss of less than $0.1 million.

During November 2002, MarkWest Hydrocarbon sold 500,000 of its Partnership subordinated units to a private venture fund for $8.6 million. The sale price was $17.146 per subordinated unit, representing a 22 percent discount off the common unit price of MarkWest Energy Partners over the twenty trading days prior to closing. The discounted subordinated unit sales price relative to the market value of the common units was attributable to the preference of the common units with respect to distributions as well as no public trading market for the subordinated units. Net proceeds after transaction costs were $8.1 million. MarkWest Hydrocarbon recognized a gain on the sale of $5.5 million. MarkWest Hydrocarbon granted preferential rights to conversion to the buyer: one-third of the 500,000 subordinated units sold will be converted into common units at each of the first three

possible conversion dates provided for in MarkWest Energy's partnership agreement. MarkWest Hydrocarbon's former President and Chief Executive Officer and current Chairman of the Board of Directors purchased 13,997 of the subordinated units as a limited partner of the private venture fund.

7. Property, Plant and Equipment

The following provides composition of the Company's property, plant and equipment at:

			December 31,
			2003			2002
			(in thousands)
Property, plant and equipment:
	Gas gathering facilities		$	73,424		$	38,409
	Gas processing plants			55,888			48,922
	Fractionation and storage facilities			22,160			22,076
	Natural gas pipelines			38,790			—
	Crude oil pipelines			18,352			—
	NGL transportation facilities			4,415			4,990
	Marketing assets			1,987			5,280
	Oil and gas properties and equipment, full cost method			2,380			139,235
	Land, buildings and other equipment			12,499			9,714
	Construction in-progress			2,362			1,609

				232,257			270,235
	Less: Accumulated depreciation, depletion, amortization and impairment			(44,134	)		(58,717	)

		Total property, plant and equipment, net	$	188,123		$	211,518

Cobb Processing Plant

During 2003, we entered into an agreement with the Partnership for the construction of a new Cobb processing plant. Of the expected $2.1 million to construct the new plant and decommission and dismantle the old plant, $1.7 million will be funded by MarkWest Hydrocarbon, and $0.5 million will be funded by the Partnership.

The Partnership will continue to operate the existing Cobb processing plant until the scheduled mid-2004 completion date of the new plant. Subsequent thereto, the existing plant will be decommissioned and dismantled at an expected cost of $0.4 million. As of December 31, 2003, the costs have been reflected in the balance sheet as an increase to property, plant and equipment, and a corresponding increase to the asset retirement obligation has been reflected in other liabilities. As of December 31, 2003, and in accordance with SFAS No. 144, it was determined that the carrying value of the old processing plant of $1.4 million exceeded its estimated fair value of $0.3 million. Consequently, an impairment of $1.1 million has been recorded in the statement of operations.

8. Asset Retirement Obligations

In June 2001, the FASB issued Statement No. 143, Accounting for Asset Retirement Obligations. We adopted SFAS No. 143 beginning January 1, 2003. Under SFAS No. 143, the fair value of asset retirement obligations is recorded as a liability when incurred, which is typically at the time the assets are placed in service. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities are accreted for the change in their present value and the initial capitalized costs are depreciated over the useful lives of the related assets.

The cumulative effect of this accounting change for years prior to 2003 was less than $0.1 million and is reflected in our statement of operations. At the time of adoption, we also recorded an asset retirement obligation of $3.4 million (a net increase to long-term liabilities of $2.5 million) and increased net properties $2.4 million in accordance with the provisions of SFAS No. 143. There was no impact on our cash flows as a result of adopting SFAS No. 143. For the year ended December 31, 2003, the impact to earnings per share from the cumulative effect of the change in accounting for asset retirement obligations was not significant.

The pro forma asset retirement obligation would have been $2.5 million at January 1, 2002 had we adopted SFAS No. 143 on January 1, 2002. For the year ended December 31, 2002, the pro forma effect on net income and earnings per share, had we adopted SFAS No. 143 on January 1, 2002, would have been as follows:

		Year Ended December 31, 2002
		As Reported			Pro Forma
		(in thousands, except per share data)
Net loss		$	(2,796	)	$	(4,241	)
Loss per share:
	Basic	$	(0.30	)	$	(0.45	)
	Diluted	$	(0.30	)	$	(0.45	)

The following is a reconciliation of our asset retirement obligation for the year months ended December 31, 2003 (in thousands):

Asset retirement obligation as of January 1, 2003	$	3,367
Liability accrued upon capital expenditures		1,197
Liability settled		(4,188	)
Accretion of discount expense		128

Asset retirement obligation as of December 31, 2003	$	504

The Company's assets subject to asset retirement obligations, exclusive of assets owned by MarkWest Energy Partners (discussed below), were primarily oil and gas wells. We discontinued our exploration and production business and sold off substantially all of are assets as of December 31, 2003 (see Note 5).

MarkWest Energy Partners' assets subject to asset retirement obligations are primarily certain gas gathering pipelines and processing facilities, a crude oil pipeline and other related pipeline assets. The Partnership has identified certain of its assets as having an indeterminate life in accordance with SFAS No. 143, which does not trigger a requirement to establish a fair value for future retirement obligations associated with such assets. These assets include certain pipelines and processing plants. A liability for these asset retirement obligations will be recorded if and when a future retirement obligation is identified. The asset retirement obligation associated with the remaining facilities was immaterial and not recognized in the financial statements.

In October 2003, the board of directors of our general partner approved a plan to shut down the Partnership's existing Cobb processing facility, contingent upon the construction of a replacement facility. The Partnership expects the construction of the new facility to be completed by mid-2004. During the fourth quarter of 2003, the Partnership estimated the amount of the asset retirement obligation associated with the shut down of the old Cobb facility to be $0.5 million, and, accordingly, the Partnership recorded a related accrued liability.

9. Debt

MarkWest Hydrocarbon, Inc.

With the proceeds from the sales of our Canadian oil and gas properties, we paid off all of our outstanding debt—exclusive of MarkWest Energy Partners' debt, which is discussed below—in December 2003. We then terminated our credit facility. At December 31, 2003, we had no outstanding debt, exclusive of MarkWest Energy Partners' debt. For the year ended December 31, 2003, we wrote off $0.4 million of deferred financing costs as a result of the termination of our credit facility. For the year ended December 31, 2002, the Company wrote off approximately $3.0 million as a result of two amendments to our credit facility.

MarkWest Energy Partners, L.P.

On May 20, 2002, a wholly owned subsidiary of the Partnership (the "Operating Company") entered into a $60 million credit facility (the "Original Credit Facility") with various financial institutions that was comprised of both a revolving and term loan. In March 2003, the Original Credit Facility was increased by $15 million to $75 million.

On December 1, 2003, the Operating Company amended the Original Credit Facility, and entered into a $140 million Amended and Restated Credit Agreement (the "Partnership Credit Facility") with various financial institutions. The Partnership Credit Facility is available to fund capital expenditures and acquisitions, working capital requirements (including letters of credit) and distributions to unit holders. Advances to fund distributions to unit holders may not exceed $0.50 per outstanding unit in any 12-consecutive-month period. At December 31, 2003, $126.2 million was outstanding, and $13.8 million was available, under the Partnership Credit Facility.

The Operating Company may prepay all loans at any time without penalty. During each calendar year, the Partnership Credit Facility requires that there be a 15-consecutive-day period during which there are no distribution loans made or outstanding.

At the Operating Company's option, indebtedness under the Partnership Credit Facility bears interest 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 0.625% to 2.125% or (ii) at a rate equal to LIBOR plus an applicable margin ranging from 2.00% per annum to 3.50% per annum depending on the Partnership's ratio of Consolidated Funded Debt (as defined in the Partnership Credit Facility) to Consolidated EBITDA (as defined in the Partnership Credit Facility) for the four most recently completed fiscal quarters. For the year ended December 31, 2003, the weighted average interest rate was 4.69%.

The Operating Company incurs a commitment fee on the unused portion of the credit facility at a rate ranging from 37.5 to 50.0 basis points based upon the ratio of our Consolidated Funded Debt (as defined in the Partnership Credit Facility) to Consolidated EBITDA (as defined in the Partnership Credit Facility) for the four most recently completed fiscal quarters. The Partnership Credit Facility matures in November 2006. At that time, the Partnership Credit Facility 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 loans, acquisitions and investments;
•: amend 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 Consolidated EBITDA to interest expense for the prior four fiscal quarters;
•: a ratio of not more than 4.75:1.00 prior to March 2004 and 3.50 to 1.00 after March 2004 of total debt to Consolidated EBITDA for the prior four fiscal quarters;
•: a minimum net worth of $55 million plus 75% of proceeds of equity issued after December 1, 2003; and
•: a ratio of not more than 3.00 to 1.00 of Consolidated EBITDA to cash interest payments on indebtedness for the prior fiscal quarter in the event that MarkWest Hydrocarbon has freely available cash reserves of less than $17.5 million.

MarkWest Energy Partners and its subsidiaries have given full, unconditional and joint and several guarantees of any obligation under the credit facility and have pledged substantially all of their assets to secure the credit facility.

Scheduled Debt Maturities

Scheduled debt maturities were as follows:

	December 31, 2003
	(in thousands)
2004	$	—
2005		—
2006		126,200
2007		—
2008		—
2009 and thereafter		—

Total debt outstanding	$	126,200

10. Stockholders' Equity

Private Placement

Through a private placement transaction to certain accredited investors, MarkWest Energy Partners sold 375,000 common units at a price of $26.23 per unit that yielded gross proceeds of approximately $9.8 million. The offering was consummated in two installments of 300,031 and 74,969 units, completed on June 27, and July 10, 2003 that yielded gross proceeds of approximately $7.9 million and $1.9 million, respectively.

Stock Dividend

On July 10, 2003, our Board of Directors declared a stock dividend of one share of MarkWest Hydrocarbon's common stock for each ten shares held by our stockholders. The stock dividend was

paid on August 11, 2003 to the stockholders of record as of the close of business on July 31, 2003. The effect of the stock dividend has been retroactively applied to January 1, 2001.

Cash Dividend

MarkWest Energy Partners' Secondary Offering

11. Income Taxes

The provision for income taxes from continuing operations is comprised of:

		Year Ended December 31,
		2003			2002			2001
		(in thousands)
Current:
	Federal	$	(11,964	)	$	—		$	—
	State		(1,388	)		—			54

	Total current		(13,352	)		—			54

Deferred:
	Federal		1,065			(2,704	)		163
	State		78			(328	)		22

	Total deferred		1,143			(3,032	)		185

	Total tax provision	$	(12,209	)	$	(3,032	)	$	239

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

	December 31,
	2003			2002
	(in thousands)
Property, plant and equipment	$	9,199		$	43,972
Intangibles		—			322

Total deferred income tax liabilities		9,199			44,294

Alternative minimum tax (AMT) credit carryforwards		(2,773	)		(3,426	)
Risk management assets		(510	)		(5,543	)
State net operating loss (NOL) carryforwards		(59	)		(75	)
Percentage depletion carryforwards		—			(191	)
Other, net		(114	)		(123	)

Total deferred income tax assets		(3,456	)		(9,358	)

Net deferred tax liability	$	5,743		$	34,936

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

	Year Ended December 31,
	2003			2002			2001
	(in thousands)
Income tax at statutory rate	$	(11,256	)	$	(2,711	)	$	194
State income taxes, net of federal benefit		(794	)		(329	)		33
Other		(159	)		8			12

Total	$	(12,209	)	$	(3,032	)	$	239

At December 31, 2003, we had no federal-NOL carryforward. State-NOL carryforwards were $1.3 million and expire in 2019 and 2021. We had AMT credit carryforwards of $2.8 million that we believe will be fully utilized. AMT credit carry forwards have no expiration date and can be applied as a credit to reduce regular income taxes. They are expected to be offset by existing taxable temporary differences as they reverse or be realized by achieving future profitable operations based on past results of operations, history, and projections of future results of operations.

12. Significant Customer

For the years ended December 31, 2003 and 2002, there were no sales to a single customer that accounted for in excess of 10% of total revenues. For the year ended December 31, 2001, sales to one customer accounted for approximately 11% of total revenues.

13. Commodity Price Risk Management

Commodity Price Risk

products. Our products are commodities that are subject to price risk resulting from material changes in response to fluctuations in supply and demand, general economic conditions and other market conditions, such as weather patterns, over which we have no control.

Types of Price Risk

•: Under "keep-whole" contracts, we take title to and sell the NGLs produced in our processing operations. We also reimburse or "keep whole" the producers for the Btu content of the NGLs removed through the re-delivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas. Keep-whole contracts therefore expose us to NGL product price risk (on the sales side) and natural gas price risk (on the purchase or reimbursement side).
•: Under "percent-of-proceeds" contracts, we take title to the NGLs produced in our processing operations, sell the NGLs to third parties and pay the producer a specified percentage of the proceeds received from the sales. Percent-of-proceeds contracts therefore expose us to NGL product price risk. All of our Michigan processing business is also governed by percent-of-proceeds contracts.

Basis Risk

natural gas commodity transactions in the readily available natural gas financial marketplace, similar markets do not exist for hedging basis risk on NGL products. NGL product basis risk also results from the difference in relative price movements between crude oil and NGL products. We may use crude oil, instead of NGL products, in our hedges because the NGL hedge products and markets are limited. Crude oil is typically highly correlated with certain NGL products. We hedge our NGL product sales by selling forward propane or crude oil.

Commodity Risk Management Position

As of December 31, 2003, we have hedged NGLs and natural sales as follows:

		Year Ending December 31,
		2004		2005
MarkWest Hydrocarbon, Inc.
NGL Volumes Hedged Using Crude Oil:
	NGL gallons		6,756,733		—
	NGL sales price per gallon	$	0.525	$	NA
MarkWest Energy Partners, L.P.
Hedged Natural Gas Sales:
	Natural gas MMBtu		183,000		182,500
	Natural gas sales price per MMBtu	$	4.57	$	4.26
Natural Gas Puts:
	Natural gas MMBtu		366,000		—
	Natural gas sales price per MMBtu	$	4.00	$	NA
Total Hedged Natural Gas:
	Natural gas MMBtu		549,000		182,500
	Natural gas sales price per MMBtu	$	4.19	$	4.26

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. At December 31, 2003, of the $1.8 million reflected as accumulated other comprehensive loss, approximately $1.5 million is related to hedging activities that expire within one year and, consequently, may be reflected in 2004 operations.

As of December 31, 2003, we are not a party to any basis risk hedges.

Credit Risk

Interest Rate Risk

Through our consolidated subsidiary, MarkWest Energy Partners, L.P., 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, during the term of the Partnership's Credit Facility that matures on November 30, 2006, to adjust the ratio of fixed and floating rates in the debt portfolio. As of December 31, 2003, we are a party to contracts to fix interest rates on $8.0 million of our debt at 3.85% through May 2005, compared to floating LIBOR, plus an applicable margin.

SFAS No. 133

SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, 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. We formally document, designate and assess the effectiveness of transactions receiving hedge accounting treatment.

In the case of discontinued hedge accounting for cash flow hedges, SFAS No. 133 provides the amount in other comprehensive income will be reclassified to earnings in the periods of the forecasted transactions. As such, we reclassified $0.2 and $0.8 million from other comprehensive income to revenue, net of $0.1 million and $0.3 million of deferred taxes for 2003 and 2002, respectively.

Adoption of SFAS No. 133

We adopted SFAS No. 133, on January 1, 2001. In accordance with the transition provisions of SFAS No. 133, we recorded on that date a net-of-tax cumulative effect adjustment of approximately $1.2 million loss to other comprehensive income to recognize at fair value all derivatives that are designated as cash-flow hedging instruments.

The following provides a summary of the amounts reflected as other comprehensive income at December 31, 2001, and of the amounts reflected as cumulative effect of a change in accounting principle at January 1, 2001, as a result of implementing SFAS No. 133:

		December 31, 2001							January 1, 2001
Asset (Liability)		Risk Management		Deferred taxes			Gain (Loss)		Risk Management			Deferred taxes			Gain (Loss)
Fixed-price NGL purchase and sales contracts		$	1,000	$	(400	)	$	700	$	2,100		$	(800	)	$	1,300
Fixed-price natural gas sales contract			6,300		(2,200	)		4,100		(3,900	)		1,400			(2,500	)
Fixed interest rate contracts			500		(200	)		300		—			—			—

	Total	$	7,900	$	(2,800	)	$	5,100	$	(1,800	)	$	600		$	(1,200	)

Enron Bankruptcy Filing

14. Benefit Plan

We made contributions of $0.4 million, $0.3 million, $0.3 million to a 401(k) savings and profit-sharing plan for the years ended December 31, 2003, 2002 and 2001, respectively. The plan is discretionary, with annual contributions determined by our board of directors.

15. Stock Compensation Plans

At December 31, 2003, we have two stock-based compensation plans, and, through our consolidated subsidiary, MarkWest Energy Partners, a variable unit-based plan. These plans are described below. We apply APB Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations in accounting for our plans. Accordingly, no compensation cost has been recognized for our fixed stock option plans but we did recognize $1.4 million, $0.1 million and $0 in compensation expense for the variable plan for the years ended December 31, 2003, 2002 and 2001, respectively.

Under the 1996 Stock Incentive Plan, we may grant options to our 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 our 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.

Under the 1996 Non-employee Director Stock Option Plan, we may grant options to our non-employee directors for up to 30,000 shares of common stock in the aggregate. Under this plan, the exercise price of each option equals the market price of our stock on the date of the grant, and an option's maximum term is three years. Options are granted upon the date the director first becomes a director and biannually thereafter. Options granted upon the date the director first becomes a director vest at the rate of 33.33% per year. Biannual options vest 100% on the first anniversary of the option grant date.

The fair value of each option granted in 2003, 2002 and 2001 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:

	2003		2002		2001
Expected life of options	6 years		6 years		6 years
Risk free interest rates	3.48	%	3.54	%	4.84	%
Estimated volatility	51	%	52	%	52	%
Dividend yield	0.0	%	0.0	%	0.0	%

A summary of the status of our two, fixed stock option plans as of December 31, 2003, 2002 and 2001, and changes during the years ended on those dates are presented below:

	2003				2002				2001
	Shares		Weighted- Average Price		Shares		Weighted- Average Price		Shares		Weighted- Average Price
Fixed Options
Outstanding at beginning of year	728,315		$	9.06	792,948		$	9.18	740,246		$	9.15
Granted	45,750			8.44	20,000			6.09	71,464			7.62
Stock dividend	83,042			8.35	—			—	—			—
Exercised	(261,141	)		8.11	(386	)		5.38	(2,713	)		6.74
Cancelled	(155,886	)		8.78	(84,247	)		9.51	(16,049	)		9.62

Outstanding at end of year	440,080		$	8.35	728,315		$	9.06	792,948		$	9.18

Options exercisable at December 31, 2003, 2002 and 2001, respectively	342,043				559,382				478,265
Weighted-average fair value of options granted during the year			$	8.57			$	2.54			$	4.11

The following table summarizes information about fixed stock options outstanding at December 31, 2003:

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number Outstanding at 12/31/03	Weighted- Average Remaining Contractual Life	Weighted- Average Exercise Price		Number Exercisable At 12/31/03	Weighted- Average Exercise Price
$4.85 to $5.55	65,343	5.14	$	5.09	40,045	$	5.03
$6.49 to $6.96	48,984	4.29		6.89	36,474		6.86
$7.00 to $7.96	80,943	5.59		7.78	68,535		7.82
$8.30 to $9.81	177,074	3.81		9.47	174,170		9.47
$10.17 to $11.28	67,736	7.64		10.28	31,754		10.23

$4.85 to $11.28	440,080	5.01	$	8.35	350,978	$	8.44

16. Related Party Transactions

Transactions Involving MAK-J Energy Partners, Ltd.

Through our wholly owned subsidiary, MarkWest Resources, Inc. ("Resources"), we held varied undivided interests in several exploration and production assets in which MAK-J Energy Partners Ltd. ("MAK-J") also owns or owned an undivided interest, varying from 25% to 51%. The general partner of MAK-J is a corporation owned and controlled by our former President and Chief Executive Officer and current Chairman of the Board of Directors. Two former officers, both of who left the Company during 2003, were limited partners in MAK-J. The properties were operated pursuant to joint operating agreements entered into between Resources and MAK-J. Resources was the operator under such agreements. The joint operating agreements were governed by a Participation and Operations Agreement, most recently amended June 2, 2003. The joint property acquisitions and joint operating agreements were subject to the approval of the independent members of our Board of Directors. As the operator, Resources was obligated to provide certain accounting and well operations services to the parties. The Participation and Operations Agreement provided for a monthly fee ($2,000 per month) payable to Resources to offset the costs of accounting and well operations on a monthly basis. As a

part of the sale of our San Juan Basin oil and gas properties to a third party on June 30, 2003, the Participation and Operations Agreement was assigned to the purchasing third party.

From time to time, MarkWest Hydrocarbon entered into hedges with counterparties on behalf of MAK-J. MarkWest Hydrocarbon billed or remitted to MAK-J, as circumstances dictated, its portion of transaction costs and settlements on a monthly basis. As of July 2003, all such hedges had been settled.

Through our wholly owned subsidiary, Matrex, LLC, we hold interests in certain exploration and production assets in which MAK-J also owns interests. Both parties are participants to joint operating agreements involving other third parties.

We have receivables due from MAK-J, representing its share of operating and capital costs generated in the normal course of business, of less than $0.1 million and approximately $0.7 million as of December 31, 2003 and 2002, respectively. We also have payables to MAK-J, representing its share of revenues generated in the normal course of business, of approximately $0.1 million and $1.3 million as of December 31, 2003 and 2002, respectively.

Transactions Involving Officers of MarkWest Hydrocarbon

From time to time, MarkWest Hydrocarbon sells to certain of its executive officers (i) a certain amount of the subordinated units the Company obtained during the formation of MarkWest Energy Partners in May 2002 and (ii) a portion of its ownership interest in the general partner, which was also obtained by the Company during the formation of the Partnership (see Note 3). The sales are governed by a purchase and sales agreement (the agreement) that outlines the terms and conditions.

Immediately after MarkWest Energy Partners' initial public offering on May 24, 2002, MarkWest Hydrocarbon sold an 8.6% interest in the general partner of the Partnership and 24,864 of its Partnership subordinated units, representing a 0.4% limited partner interest in the Partnership, to certain officers of MarkWest Hydrocarbon for $183,000 and $408,000, respectively. The officers and employees paid approximately 30% of the purchase price in cash and financed the remainder via loans from MarkWest Hydrocarbon. The loans are formalized by non-recourse promissory notes requiring the principal balance to be repaid no later than June 30, 2009 and bearing interest at the rate of 7% per annum on the unpaid balance. For the year ended December 31, 2002, we recognized $0.1 million gain on sale to related party on the sales price in excess of our book value to the extent that the sales price was paid in cash. The portion of the sales price in excess of our book value that was financed by loans from the Company, approximately $0.3 million, was recorded as deferred income and is included in accrued liabilities on our balance sheet.

In accordance with the Sarbanes-Oxley Act of 2002, the Company no longer permits loans to employees. Subsequent to the May 24, 2002 sales, all transactions have been settled in cash. For the year ended December 31, 2003, we recognized $0.4 million from gains from these sales. Outstanding notes receivable from officers pertaining to the loans made in May 2002 was approximately $0.2 million as of December 31, 2003.

17. Segment Reporting

Our operations are classified into two reportable segments:

(1): Managing MarkWest Energy Partners—we operate MarkWest Energy Partners, a publicly traded limited partnership engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids, and the gathering and transportation of crude oil.
(2): Marketing—we sell our equity and third party NGLs, purchase third party natural gas and sell our equity and third-party natural gas.

During 2003, we discontinued our exploration and production business segment.

On May 24, 2002, we spun off our gathering and processing assets into MarkWest Energy Partners, our consolidated subsidiary. The formation and initial public offering of MarkWest Energy Partners (the initial public offering closed on May 24, 2002) and the subsequent change to the structure of our internal organization caused the composition of our reportable segments to change in the fourth quarter of 2002. Prior to the fourth quarter of 2002, we classified our operations into two reportable segments:

(1): Exploration and Production—explore for and produce natural gas.
(2): Gathering, Processing and Marketing—gathering and processing of natural gas and the transportation, fractionation and storage of natural gas liquids; also purchase and market third-party natural gas and NGLs.

Information for the period from May 24, 2002, through December 31, 2002 (shown below), reflects our segments in effect since the date of the Partnership's initial public offering. Information prior to May 24, 2002, has not been restated to reflect the change in segmentation because no transfer pricing existed between Gathering and Processing and Marketing up until that point in time. In connection with the formation of MarkWest Energy Partners, certain contracts were executed which established the basis of fees for services rendered by processing MarkWest Hydrocarbon's natural gas. No such arrangement existed prior to the formation of MarkWest Energy Partners. As a result, it is not practicable to restate certain prior period segment information to conform to our current presentation.

We evaluate the performance of our segments and allocate resources to them based on operating income. There were no intersegment revenues prior to May 24, 2002. We conduct our continuing operations in the United States.

The table below presents information about operating income for the reported segments for the three years ended December 31, 2003, 2002 and 2001. Operating income for each segment includes total revenues less cost of goods sold, operating expenses, depreciation and impairment and excludes selling, general and administrative expenses, interest expense, interest income and income taxes. We

have not reported asset information by reportable segment because we do not produce such information internally.

	Marketing			MarkWest Energy Partners		Eliminating Entries			Total
Year Ended December 31, 2003
Revenues from external customers	$	139,964		$	67,687	$	—		$	207,651
Intersegment revenues	$	—		$	49,850	$	(49,850	)	$	—
Segment operating income	$	(26,897	)	$	17,546	$	—		$	(9,351	)
May 24 through December 31, 2002
Revenues from external customers	$	86,266		$	7,110	$	—		$	93,376
Intersegment revenues	$	—		$	26,093	$	(26,093	)	$	—
Segment operating income	$	(7,896	)	$	8,435	$	—		$	539

	Gathering Processing & Marketing		Total
January 1 through May 23, 2002
Revenues	$	60,962	$	60,962
Segment operating income	$	4,313	$	4,313
Year Ended December 31, 2001
Revenues	$	173,890	$	173,890
Segment operation income	$	11,987	$	11,987

A reconciliation of total segment operating income to total consolidated income before taxes is as follows:

		Year Ended December 31,
		2003			2002			2001
		(in thousands)
Total segment operating income (loss)		$	(9,351	)	$	4,852		$	11,987
Selling, general and administrative expenses			(14,465	)		(9,420	)		(7,502	)
Interest expense, net			(5,930	)		(3,775	)		(3,700	)
Write-down of deferred financing costs			(415	)		(2,977	)		—
Gain on sale of non-operating assets			—			5,454			—
Gain on sale of non-operating assets to related parties			382			141			—
Minority interest in net income of consolidated subsidiary			(3,236	)		(1,947	)		—
Other expense			(92	)		(73	)		(231	)

	Income (loss) from continuing operations before taxes	$	(33,107	)	$	(7,745	)	$	554

18. Commitments and Contingencies

Legal

Lease Obligations

We have various non-cancelable operating lease agreements for equipment and office space expiring at various times through fiscal 2015. Annual rent expense under these operating leases was $2.2 million, $2.3 million and $2.0 million for the three years ended December 31, 2003, 2002 and 2001, respectively. Our minimum future lease payments under these operating leases are as follows:

	December 31, 2003
	(in thousands)
2004	$	2,180
2005		1,789
2006		1,680
2007		1,449
2008		1,316
2009 and thereafter		2,604

Total	$	11,018

19. Quarterly Results of Operations (Unaudited)

The following summarizes certain quarterly results of operations:

		Three Months Ended(1)
		March 31			June 30			September 30			December 31
*2003*
Revenues		$	50,651		$	47,888		$	48,228		$	60,884
Income (loss) from operations(2)		$	(4,009	)	$	(6,158	)	$	(7,321	)	$	(6,328	)
Net income (loss)(2)		$	(1,042	)	$	9,979		$	(6,978	)	$	(11,908	)
Earnings (loss) per share:
	Basic	$	(0.11	)	$	1.06		$	(0.74	)	$	(1.27	)
	Diluted	$	(0.11	)	$	1.06		$	(0.74	)	$	(1.27	)
*2002*
Revenues		$	37,330		$	38,560		$	29,540		$	48,908
Income (loss) from operations		$	1,452		$	(1,039	)	$	(4,197	)	$	(784	)
Net income (loss)		$	175		$	(2,075	)	$	(3,162	)	$	2,266
Earnings (loss) per share:
	Basic	$	0.02		$	(0.22	)	$	(0.34	)	$	0.24
	Diluted	$	0.02		$	(0.22	)	$	(0.34	)	$	0.24

(1): As disclosed in Note 5, during the year ended December 31, 2003, we discontinued our exploration and production business. For 2003 and 2002, quarterly results of operations reflect amounts from continuing operations and exclude amounts associated with discontinued operations.
(2): Three months ended December 31, 2003, includes an impairment of $1.1 million (see Note 7).

20. Supplemental Information on Oil and Gas Producing Activities (Unaudited)

The following information is presented in accordance with SFAS No. 69, Disclosure about Oil and Gas Producing Activities.

(A) Costs Incurred in Oil and Gas Exploration and Development Activities—The following costs were incurred in oil and gas exploration and development activities during the years ended December 31, 2003, 2002 and 2001:

			United States		Canada		Total
			(in thousands)
2003
	Property acquisition costs (undeveloped leases and proved properties)		$	406	$	1,878	$	2,284
	Exploration costs			252		19,461		19,713
	Development costs			2,197		7,247		9,444

		Total	$	2,855	$	28,586	$	31,441

2002
	Property acquisition costs (undeveloped leases and proved properties)		$	1,792	$	1,252	$	3,044
	Exploration costs			1,170		5,360		6,530
	Development costs			7,851		10,270		18,121

		Total	$	10,813	$	16,882	$	27,695

2001
	Property acquisition costs (undeveloped leases and proved properties)		$	4,563	$	79,496	$	84,059
	Exploration costs			1,259		1,387		2,646
	Development costs			3,427		1,826		5,253

		Total	$	9,249	$	82,709	$	91,958

(B) Aggregate Capital Costs—The aggregate capitalized costs relating to oil and gas activities at December 31 of each of the years indicated were as follows:

		2003			2002			2001
		(in thousands)
Proved properties		$	741		$	99,360		$	72,294
Unproved properties			—			32,934			36,629
Equipment and facilities			1,639			6,940			4,570

			2,380			139,234			113,493
Less: accumulated depreciation, depletion, amortization and impairment			(1,624	)		(21,876	)		(7,119	)

	Net capitalized costs	$	756		$	117,358		$	106,374

(C) Results of Operations from Producing Activities—Results of operations from producing activities for the years ended December 31, 2003, 2002 and 2001, are presented below. Income taxes

are different from income taxes shown in the Consolidated Statements of Operations because this table excludes general and administrative and interest expense.

			United States			Canada			Total
			(in thousands)
2003
	Revenues:
		Sales	$	9,038		$	21,225		$	30,263
		Other		181			1,336			1,517

		Total		9,219			22,561			31,780
	Production taxes			(568	)		(1,314	)		(1,882	)
	Transportation and processing costs			(946	)		(429	)		(1,375	)
	Lease operating costs			(2,271	)		(5,430	)		(7,701	)
	Depreciation, depletion, amortization			(1,692	)		(14,464	)		(16,156	)
	Impairment			(1,034	)		—			(1,034	)

	Operating income			2,708			924			3,632
	Income tax provision			(1,077	)		(380	)		(1,457	)

	Results of operations		$	1,631		$	544		$	2,175

2002
	Revenues:
		Sales	$	9,988		$	20,717		$	30,705
		Other		468			1,750			2,218

		Total		10,456			22,467			32,923
	Production taxes			(591	)		(1,453	)		(2,044	)
	Transportation and processing costs			(1,199	)		(481	)		(1,680	)
	Lease operating costs			(2,777	)		(5,135	)		(7,912	)
	Depreciation, depletion and amortization			(2,506	)		(13,179	)		(15,685	)

	Operating income			3,383			2,219			5,602
	Income tax provision			(1,334	)		(959	)		(2,293	)

	Results of operations		$	2,049		$	1,260		$	3,309

2001
	Revenues:
		Sales	$	9,761		$	5,075		$	14,836
		Other		157			—			157

		Total		9,918			5,075			14,993
	Production taxes			(674	)		—			(674	)
	Transportation and processing costs			(1,314	)		(431	)		(1,745	)
	Lease operating costs			(1,743	)		(948	)		(2,691	)
	Depreciation, depletion and amortization			(1,726	)		(3,445	)		(5,171	)

	Operating income			4,461			251			4,712
	Income tax provision			(1,763	)		(107	)		(1,870	)

	Results of operations		$	2,698		$	144		$	2,842

(D) Estimated Proved Oil and Gas Reserves—Estimate of our proved and proved developed future net recoverable oil and gas reserves and changes for 2003, 2002 and 2001 follow. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions based on prices and costs as of the date of the estimate. Proved quantities of crude oil and natural gas liquids were not significant in any of the years presented.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on drilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and of future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in commodity prices and operating costs.

		Gas
		United States		(MMcfe) Canada		Total
Total proved reserves:
Balance at December 31, 2000		34,585		—		34,585
	Revisions of previous estimates	(2,895	)	(3,778	)	(6,673	)
	Purchase of minerals in place	6,900		25,959		32,859
	Extensions and discoveries	5,730		9,232		14,962
	Production	(2,832	)	(2,073	)	(4,905	)
	Sale of minerals in place	—		—		—

Balance at December 31, 2001		41,488		29,340		70,828
	Revisions of previous estimates	1,393		(4,958	)	(3,565	)
	Purchase of minerals in place	2,749		179		2,928
	Extensions and discoveries	3,458		12,953		16,411
	Production	(3,367	)	(7,370	)	(10,737	)
	Sale of minerals in place	—		—		—

Balance at December 31, 2002		45,721		30,144		75,865
	Revisions of previous estimates	596		(2,552	)	(1,956	)
	Purchase of minerals in place	—		—		—
	Extensions and discoveries	1,906		2,796		4,702
	Production	(2,125	)	(5,866	)	(7,991	)
	Sale of minerals in place	(45,856	)	(24,522	)	(70,378	)

Balance at December 31, 2003		242		—		242

Proved developed reserves at:
	December 31, 2000	22,804		—		22,804
	December 31, 2001	28,586		27,774		56,360
	December 31, 2002	37,327		28,752		66,079
	December 31, 2003	242		—		242

(E) Standardized Measure of Discounted Future Net Cash Flows—Estimated discounted future net cash flows and changes therein were determined in accordance with SFAS No. 69, Disclosures about Oil and Gas Producing Activities. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. We believe such information is essential for a proper understanding and assessment of the data presented.

Future cash inflows are computed by applying year-end prices of oil and gas relating to our proved reserves to the year-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements, including hedging contracts in existence at year-end.

The assumptions used to compute estimated future net revenues do not necessarily reflect our expectations of actual revenues or costs, or their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of our control, such as unintentional delays in development, changes in prices or regulatory controls. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

As of December 31, 2002 and 2001, future income tax expenses were estimated using a combined federal and state income tax rate of 38.8% in the United States and a combined federal and provincial rate of 43.25% in Canada. As of December 31, 2003, remaining tax attributes are expected to eliminate future income taxes. Permanent differences in Canadian resource allowances and natural gas-related tax credits were recognized. Estimates for future general and administrative and interest expense have not been considered.

An annual discount rate of 10% was used to reflect the timing of the future net cash flows relating to proved reserves.

	December 31, 2003
	United States			Canada		Total
	(in thousands)
Future gas sales	$	1,192		$	—	$	1,192
Future production costs		(364	)		—		(364	)
Future development costs		—			—		—
Future income taxes		—			—		—

Future net cash flows		828			—		828
10% annual discount for estimated timing of cash flows		(72	)		—		(72	)

Standardized measure of discounted future net cash flows	$	756		$	—	$	756

Present value of future net cash flows before income taxes was $828 in the United States and $0 in Canada at December 31, 2003. Present value of future net cash flows before income taxes was $828 in

the United States and $0 in Canada. As of December 31, 2003, there were no hedges of remaining oil and gas production.

	December 31, 2002
	United States			Canada			Total
	(in thousands)
Future gas sales	$	197,626		$	122,621		$	320,247
Future production costs		(65,035	)		(34,059	)		(99,094	)
Future development costs		(3,888	)		(3,077	)		(6,965	)
Future income taxes		(47,165	)		(23,713	)		(70,878	)

Future net cash flows		81,538			61,772			143,310
10% annual discount for estimated timing of cash flows		(37,849	)		(15,809	)		(53,658	)

Standardized measure of discounted future net cash flows	$	43,689		$	45,963		$	89,652

Present value of future net cash flows before income taxes was $67,524 in the United States and $63,751 in Canada at December 31, 2002.

	December 31, 2001
	United States			Canada			Total
	(in thousands)
Future gas sales	$	101,228		$	66,623		$	167,851
Future production costs		(39,679	)		(22,653	)		(62,332	)
Future development costs		(4,194	)		(1,078	)		(5,272	)
Future income taxes		(18,654	)		(10,292	)		(28,946	)

Future net cash flows		38,701			32,600			71,301
10% annual discount for estimated timing of cash flows		(20,335	)		(7,780	)		(28,115	)

Standardized measure of discounted future net cash flows	$	18,366		$	24,820		$	43,186

Present value of future net cash flows before income taxes was $29,269 in the United States and $32,628 in Canada at December 31, 2001. Present value of future net cash flows before income taxes, including hedging contracts in place at December 31, 2001, was $27,919 in the United States and $38,824 in Canada.

Changes in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas Reserves—An analysis of the changes in the standardized measure of discounted future net cash flows during each of the last three years is as follows.

		December 31, 2003
		United States			Canada			Total
		(in thousands)
Standardized measure of discounted future net cash flows relating to proved gas reserves, at beginning of year		$	43,689		$	54,524		$	98,213
Changes resulting from:
	Sales and transfers of natural gas produced, net of production costs		(5,253	)		(14,052	)		(19,305	)
	Net changes in prices and production costs related to future production		(7,830	)		(1,632	)		(9,462	)
	Previously estimated development costs incurred during the year		199			2,834			3,033
	Changes in future development costs		(304	)		(3,124	)		(3,428	)
	Extensions and discoveries		1,610			6,611			8,221
	Revisions of previous quantity estimates		695			(1,739	)		(1,044	)
	Sales of reserves in place		(56,730	)		(52,338	)		(109,067	)
	Changes in production rates and other		(1,221	)		(2,957	)		(4,178	)
	Accretion of discount		3,481			5,844			9,324
	Net change in income taxes		22,420			6,029			28,449

Standardized measure of discounted future net cash flows relating to proved gas reserves, at end of year		$	756		$	—		$	756

The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2003, was based on year-end natural gas prices of approximately $4.91 per Mcfe in the United States, equivalent to $6.19 per MMBtu at the Henry Hub.

		December 31, 2002
		United States			Canada			Total
		(in thousands)
Standardized measure of discounted future net cash flows relating to proved gas reserves, at beginning of year		$	18,366		$	24,820		$	43,186
Changes resulting from:
	Sales and transfers of natural gas produced, net of production costs		(5,799	)		(15,398	)		(21,197	)
	Net changes in prices and production costs related to future production		24,956			10,939			35,895
	Previously estimated development costs incurred during the year		243			15,630			15,873
	Changes in future development costs		1,197			976			2,173
	Extensions and discoveries		5,940			23,953			29,893
	Revisions of previous quantity estimates		1,843			(273	)		1,570
	Purchases of reserves in place		3,738			365			4,103
	Sales of reserves in place		—			—			—
	Changes in production rates and other		6,510			—			6,510
	Accretion of discount		2,627			2,739			5,366
	Net change in income taxes		(15,932	)		(9,227	)		(25,159	)

Standardized measure of discounted future net cash flows relating to proved gas reserves, at end of year		$	43,689		$	54,524		$	98,213

The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2002, was based on year-end natural gas prices of

approximately $4.27 per Mcfe in the United States and approximately $3.87 per Mcfe in Canada, equivalent to $4.74 per MMBtu at the Henry Hub.

		December 31, 2001
		United States			Canada			Total
		(in thousands)
Standardized measure of discounted future net cash flows relating to proved gas reserves, at beginning of year		$	65,050		$	—		$	65,050
Changes resulting from:
	Sales and transfers of natural gas produced, net of production costs		(5,894	)		(3,696	)		(9,590	)
	Net changes in prices and production costs related to future production		(76,600	)		—			(76,600	)
	Previously estimated development costs incurred during the year		—			—			—
	Changes in future development costs		(781	)		—			(781	)
	Extensions and discoveries		3,139			11,801			14,940
	Revisions of previous quantity estimates		(1,065	)		(4,177	)		(5,242	)
	Purchases of reserves in place		4,150			28,699			32,849
	Sales of reserves in place		—			—			—
	Changes in production rates and other		(4,429	)		—			(4,429	)
	Accretion of discount		9,795			—			9,795
	Net change in income taxes		25,001			(7,807	)		17,194

Standardized measure of discounted future net cash flows relating to proved gas reserves, at end of year		$	18,366		$	24,820		$	43,186

The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, was based on year-end natural gas prices of approximately $2.39 per Mcfe in the United States and approximately $2.19 per Mcfe in Canada, equivalent to $2.65 per MMBtu at the Henry Hub.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Attached as exhibits 31.1, 31.2 and 31.3 to this Annual Report are certifications of the Company's principal executive and accounting officers (who we refer to in this periodic report as our Certifying Officers) required in accordance with Section 302 of the Sarbanes-Oxley Act of 2002 (the "Section 302 Certifications"). This portion of our Annual Report on Form 10-K discloses the results of our evaluation of our disclosure controls and procedures as of December 31, 2003 referred to in paragraphs (4) and (5) of the Section 302 Certifications and should be read in conjunction with the Section 302 Certifications for a more complete understanding of the topics presented.

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Commission's rules and forms, and that information is accumulated and communicated to our management, including our Certifying Officers, as appropriate to allow timely decisions regarding required disclosure. Our management evaluated, with the participation of our Certifying Officers, the effectiveness of our disclosure controls and procedures as of December 31, 2003, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, our Certifying Officers concluded that as of December 31, 2003, our disclosure controls and procedures were effective.

Nevertheless, we are currently conducting a further review of our internal controls over financial reporting as a result of a report (the "PwC Report") delivered to our Audit Committee of our Board of Directors on March 24, 2004, by PricewaterhouseCoopers LLC ("PwC"), our independent accountants who audited our financial statements for the year ended December 31, 2003, in connection with the completion of its audit of, and the issuance of an unqualified report on, our financial statements for the years ended December 31, 2001, 2002 and 2003. In the PwC Report, PwC identified to management and the Audit Committee certain deficiencies in our internal accounting controls which, considered collectively, may constitute a material weakness in our internal controls pursuant to standards established by the American Institute of Certified Public Accountants. Deficiencies identified by PwC included a possible insufficiency in the personnel resources available to adequately maintain our financial reporting obligations as a public company; inadequate implementation of uniform controls over certain acquired entities and operations; inadequate control over classification of certain fixed asset balances and processes for accrual of certain accounts payable; and the potential need for separation of certain duties between payroll and other accounting personnel. PwC concluded that these deficiencies required PwC to increase the scope of its audit procedures in order to issue its unqualified report on our financial statements.

As a result of the PwC Report, we are in the process of carrying out a further internal review under the supervision and with the participation of our management and our Certifying Officers of the effectiveness of the design and operation of our disclosure controls and procedures. Such evaluation will consider all of the deficiencies noted in the PwC Report with the aim of supplementing our internal controls in order to mitigate the effect of the weaknesses and deficiencies identified in the PwC Report and to prevent any potential misstatements or omissions in our consolidated financial statements resulting from such factors. Our management has assigned a high priority to the short-term and long-term correction of the internal control weaknesses and deficiencies identified by PwC and will implement any necessary changes to our policies, procedures, systems and personnel to address these issues and any other matters identified by our review.

PART III

Certain information required by Part III is omitted from this Report. We will file a definitive proxy statement pursuant to Regulation 14A (the "Proxy Statement") not later than 120 days after the end of the fiscal year covered by this Report, and certain information included in the Proxy Statement is incorporated into Part III of this Report by reference. Only those sections of the Proxy Statement that specifically address the items set forth herein are incorporated by reference.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required by this Item is incorporated by reference from the section labeled "Directors and Executive Officers" in the Proxy Statement.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this Item is incorporated by reference from the sections labeled "Compensation of Directors" and "Executive Compensation" excluding the "Board Compensation Committee Report on Executive Compensation" and the "Performance Graph" in the Proxy Statement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this Item is incorporated by reference from the section labeled "Principal Stockholders" in the Proxy Statement.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by this Item is incorporated by reference from the section labeled "Certain Relationships and Related Transactions" in the Proxy Statement.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this Item is incorporated by reference from the section labeled "Principal Accounting Fees and Services" in the Proxy Statement.

PART IV

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 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, which is incorporated herein by reference.

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

(b)

Reports on Form 8-K:

•: A Current Report on Form 8-K was filed with the SEC under item 5 of Form 8-K on October 29, 2003 to announce the resignation of John M. Fox, the then Chairman, President and Chief Executive Officer of MarkWest Hydrocarbon and of MarkWest Energy GP, L.L.C., the general partner of the Partnership, as President, effective November 1, 2003, and as Chief Executive Officer effective December 31, 2003, and the appointment of Frank M. Semple in those positions subsequent to Mr. Fox's resignation.
•: A Current Report on Form 8-K was filed with the SEC under item 12 of Form 8-K on November 5, 2003 to announce the Company's consolidated financial results of operations for the quarter ended September 30, 2003.
•: A Current Report on Form 8-K was filed with the SEC under items 2 and 7 of Form 8-K on December 16, 2003 to announce the Partnership's acquisition of certain assets of American Central Western Oklahoma Gas Company, L.L.C.
•: A Current Report on Form 8-K was furnished with the SEC under items 2 and 7 of Form 8-K on December 17, 2003 to announce the Company's sale of its wholly owned subsidiary, MarkWest Resources Canada Corporation, to Advantage Energy Income Fund, and its wholly owned subsidiary, MarkWest Midstream Services, Inc., to Canadian Natural Resources Limited

(c)

Exhibits required by Item 601 of Regulation S-K.

2.1(4)		Share Purchase Agreement between MarkWest Hydrocarbon Acquisition Corporation and Kaiser Energy, Ltd., dated as of August 10, 2001.
2.2(4)		Share Purchase Agreement between MarkWest Hydrocarbon Acquisition Corporation and Brian E. Hiebert, Guy C. Crierson, Ian R. DeBie, Gordon A. Maybee, Erin Hiebert, Raylene Grierson, Kathleen DeBie and Patricia Maybee, dated as of August 10, 2001.
2.3(8)		Purchase Agreement dated as of March 24, 2003, among PNG Corporation, Energy Spectrum Partners LP, MarkWest Energy GP, L.L.C., MW Texas Limited, L.L.C. and MarkWest Energy Partners, L.P.
2.4(8)		Plan of Merger entered into as of March 28, 2003, by and among MarkWest Blackhawk L.P., MarkWest Pinnacle L.P., MarkWest PNG Utility L.P., MarkWest Texas PNG Utility L.P., Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG Transmission Company and Bright Star Gathering, Inc.

2.5(12)		Purchase and Sale Agreement, dated as of November 7, 2003, by and between Shell Pipeline Company, LP and Equilon Enterprises L.L.C., dba Shell Oil Products US, and MarkWest Michigan Pipeline Company, L.L.C.
2.6(11)		Asset Purchase and Sale Agreement dated as of November 18, 2003, by and between American Central Western Oklahoma Gas Company, L.L.C., MarkWest Western Oklahoma Gas Company, L.L.C. and American Central Gas Technologies, Inc.
3.1(1)		Certificate of Incorporation of MarkWest Hydrocarbon, Inc.
3.2(1)		Bylaws of MarkWest Hydrocarbon, Inc.
10.1(2)		1996 Incentive Compensation Plan.
10.2(1)		1996 Stock Incentive Plan.
10.3(1)		1996 Non-employee Director Stock Option Plan.
10.4(1)		Form of Non-Compete Agreement between John M. Fox and MarkWest Hydrocarbon, Inc.
10.5(3)		MarkWest Hydrocarbon, Inc., 1997 Severance and Non-Compete Plan.
10.6(5)		Amendment to Gas Processing Agreement (Maytown) dated as of March 26, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc.
10.7(11)		Credit Agreement dated as of May 20, 2002, among MarkWest Energy Operating Company, L.L.C. (as borrower), MarkWest Energy Partners, L.P. (as a Guarantor), and various lenders.
10.8(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.
10.9(6)		Fifth Amended and Restated Credit Agreement among MarkWest Hydrocarbon, Inc. and various lenders, dated as of May 24, 2002.
10.10(11)		Amended and Restated Canadian Credit Agreement among MarkWest Resources Canada Corp. and various lenders, dated as of May 24, 2002.
10.11(5)		Omnibus Agreement dated as 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.
10.12(5)+		Fractionation, Storage and Loading Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
10.13(5)+		Gas Processing Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and Markwest Hydrocarbon, Inc.
10.14(5)+		Pipeline Liquids Transportation Agreement dated as of May 24, 2002, between Markwest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
10.15(5)		Natural Gas Liquids Purchase Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.

10.16(5)+		Gas Processing Agreement (Maytown) dated as of May 28, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc.
10.17(7)		Subordinated Unit Purchase Agreement among MarkWest Hydrocarbon, Inc. and Tortoise MWEP, L.P., dated as of November 20, 2002.
10.18(9)		Purchase and Sale Agreement, dated as of June 5, 2003, by and among MarkWest Hydrocarbon, Inc., MarkWest Resources, Inc., and XTO Energy Inc.
10.19(10)		Purchase and Sale Agreement dated as of July 31, 2003, among Raptor Natural Plains Marketing LLC, Raptor Gas Transmission LLC, Power-Tex Joint Venture and MarkWest Pinnacle L.P.
10.20(11)		Amended and Restated Credit Agreement dated as of December 1, 2003, among MarkWest Energy Operating Company, L.L.C., as Borrower, Markwest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Bank One, NA, as Syndication Agent, and Fortis Capital Corp., as Documentation Agent, to the $140,000,000 Senior Credit Facility.
10.21*		Executive Employment Agreement.
11.1(13)		Statement regarding computation of earnings per share.
21.1*		List of Subsidiaries of Markwest Hydrocarbon, Inc.
23.1*		Consent of PricewaterhouseCoopers LLP.
31.1*		Chief Executive Officer Certification Pursuant to Rule 13a-14(a) of the Securities Exchange Act.
31.2*		Chief Accounting Officer Certification Pursuant to Rule 13a-14(a) of the Securities Exchange Act.
31.3*		Vice President, Treasurer and Secretary Certification Pursuant to Rule 13a-14(a) of the Securities Exchange Act.
32.1*		Certification of the Chief Executive Officer Pursuant to 18 U.S. C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*		Certification of the Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.3*		Certification of the Vice President, Treasurer and Secretary Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(1): Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513, filed with the Commission on August 2, 1996.
(2): Incorporated by reference to Amendment No. 1 to MarkWest Hydrocarbon Inc.'s Registration Statement on Form S-1, Registration No. 333-09513, filed with the Commission on September 13, 1996.
(3): Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Quarterly Report on Form 10-Q for the three months ended September 30, 1997, filed with Commission on November 13, 1997.

(4): Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Current Report on Form 8-K, filed with the Commission on August 27, 2001.
(5): Incorporated by reference to MarkWest Energy Partners, L.P.'s Current Report on Form 8-K, filed with the Commission on June 7, 2002.
(6): Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Quarterly Report on Form 10-Q for the three months ended June 30, 2002, filed with the Commission on August 14, 2002.
(7): Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Current Report on Form 8-K, filed with the Commission on November 25, 2002.
(8): Incorporated by reference to MarkWest Energy Partners, L.P.'s Current Report on Form 8-K, filed with the Commission on April 14, 2003.
(9): Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Current Report on Form 8-K, filed with the Commission on July 15, 2003.
(10): Incorporated by reference to MarkWest Energy Partners, L.P.'s Current Report on Form 8-K, filed with the Commission on September 17, 2003.
(11): Incorporated by reference to MarkWest Energy Partners, L.P.'s Current Report on Form 8-K, filed with the Commission on December 16, 2003.
(12): Incorporated by reference to MarkWest Energy Partners, L.P.'s Current Report on Form 8-K, filed with the Commission on December 31, 2003.
(13): Incorporated by reference to Item 8, Consolidated Statements of Operations, and footnote 2 of Summary of Significant Accounting Policies, Earnings Per Share, of the Annual Report Form 10-K.
+: 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 has been filed separately with the Securities and Exchange Commission.
*: Filed herewith.

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.

		MARKWEST HYDROCARBON, INC. (Registrant)
Date: March 30, 2004		By:	/s/ FRANK M. SEMPLE Frank M. Semple President and Chief Executive Officer (Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Date: March 30, 2004	By:	/s/ FRANK M. SEMPLE Frank M. Semple President and Chief Executive Officer (Principal Executive Officer)
Date: March 30, 2004	By:	/s/ TED S. SMITH Ted S. Smith Chief Accounting Officer (Principal Accounting Officer)
Date: March 30, 2004	By:	/s/ ANDREW L. SCHROEDER Andrew L. Schroeder Vice President, Treasurer and Secretary
Date: March 30, 2004	By:	/s/ JOHN M. FOX John M. Fox Chairman of the Board and Director
Date: March 30, 2004	By:	/s/ ARTHUR J. DENNEY Arthur J. Denney Director
Date: March 30, 2004	By:	/s/ DONALD C. HEPPERMANN Donald C. Heppermann Director
Date: March 30, 2004	By:	/s/ WILLIAM A. KELLSTROM William A. Kellstrom Director
Date: March 30, 2004	By:	/s/ KAREN L. ROGERS Karen L. Rogers Director
Date: March 30, 2004	By:	/s/ BARRY W. SPECTOR Barry W. Spector Director
Date: March 30, 2004	By:	/s/ DONALD D. WOLF Donald D. Wolf Director

Exhibit Number		Exhibit Index
2.1(4)		Share Purchase Agreement between MarkWest Hydrocarbon Acquisition Corporation and Kaiser Energy, Ltd., dated as of August 10, 2001.
2.2(4)		Share Purchase Agreement between MarkWest Hydrocarbon Acquisition Corporation and Brian E. Hiebert, Guy C. Crierson, Ian R. DeBie, Gordon A. Maybee, Erin Hiebert, Raylene Grierson, Kathleen DeBie and Patricia Maybee, dated as of August 10, 2001.
2.3(8)		Purchase Agreement dated as of March 24, 2003, among PNG Corporation, Energy Spectrum Partners LP, MarkWest Energy GP, L.L.C., MW Texas Limited, L.L.C. and MarkWest Energy Partners, L.P.
2.4(8)		Plan of Merger entered into as of March 28, 2003, by and among MarkWest Blackhawk L.P., MarkWest Pinnacle L.P., MarkWest PNG Utility L.P., MarkWest Texas PNG Utility L.P., Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG Transmission Company and Bright Star Gathering, Inc.
2.5(12)		Purchase and Sale Agreement, dated as of November 7, 2003, by and between Shell Pipeline Company, LP and Equilon Enterprises L.L.C., dba Shell Oil Products US, and MarkWest Michigan Pipeline Company, L.L.C.
2.6(11)		Asset Purchase and Sale Agreement dated as of November 18, 2003, by and between American Central Western Oklahoma Gas Company, L.L.C., MarkWest Western Oklahoma Gas Company, L.L.C. and American Central Gas Technologies, Inc.
3.1(1)		Certificate of Incorporation of MarkWest Hydrocarbon, Inc.
3.2(1)		Bylaws of MarkWest Hydrocarbon, Inc.
10.1(2)		1996 Incentive Compensation Plan.
10.2(1)		1996 Stock Incentive Plan.
10.3(1)		1996 Non-employee Director Stock Option Plan.
10.4(1)		Form of Non-Compete Agreement between John M. Fox and MarkWest Hydrocarbon, Inc.
10.5(3)		MarkWest Hydrocarbon, Inc., 1997 Severance and Non-Compete Plan.
10.6(5)		Amendment to Gas Processing Agreement (Maytown) dated as of March 26, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc.
10.7(11)		Credit Agreement dated as of May 20, 2002, among MarkWest Energy Operating Company, L.L.C. (as borrower), MarkWest Energy Partners, L.P. (as a Guarantor), and various lenders.
10.8(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.
10.9(6)		Fifth Amended and Restated Credit Agreement among MarkWest Hydrocarbon, Inc. and various lenders, dated as of May 24, 2002.
10.10(11)		Amended and Restated Canadian Credit Agreement among MarkWest Resources Canada Corp. and various lenders, dated as of May 24, 2002.

10.11(5)		Omnibus Agreement dated as 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.
10.12(5)+		Fractionation, Storage and Loading Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
10.13(5)+		Gas Processing Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and Markwest Hydrocarbon, Inc.
10.14(5)+		Pipeline Liquids Transportation Agreement dated as of May 24, 2002, between Markwest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
10.15(5)		Natural Gas Liquids Purchase Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
10.16(5)+		Gas Processing Agreement (Maytown) dated as of May 28, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc.
10.17(7)		Subordinated Unit Purchase Agreement among MarkWest Hydrocarbon, Inc. and Tortoise MWEP, L.P., dated as of November 20, 2002.
10.18(9)		Purchase and Sale Agreement, dated as of June 5, 2003, by and among MarkWest Hydrocarbon, Inc., MarkWest Resources, Inc., and XTO Energy Inc.
10.19(10)		Purchase and Sale Agreement dated as of July 31, 2003, among Raptor Natural Plains Marketing LLC, Raptor Gas Transmission LLC, Power-Tex Joint Venture and MarkWest Pinnacle L.P.
10.20(11)		Amended and Restated Credit Agreement dated as of December 1, 2003, among MarkWest Energy Operating Company, L.L.C., as Borrower, Markwest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Bank One, NA, as Syndication Agent, and Fortis Capital Corp., as Documentation Agent, to the $140,000,000 Senior Credit Facility.
10.21*		Executive Employment Agreement.
11.1(13)		Statement regarding computation of earnings per share.
21.1*		List of Subsidiaries of Markwest Hydrocarbon, Inc.
23.1*		Consent of PricewaterhouseCoopers LLP.
31.1*		Chief Executive Officer Certification Pursuant to Rule 13a-14(a) of the Securities Exchange Act.
31.2*		Chief Accounting Officer Certification Pursuant to Rule 13a-14(a) of the Securities Exchange Act.
31.3*		Vice President, Treasurer and Secretary Certification Pursuant to Rule 13a-14(a) of the Securities Exchange Act.
32.1*		Certification of the Chief Executive Officer Pursuant to 18 U.S. C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes- Oxley Act of 2002.
32.2*		Certification of the Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes- Oxley Act of 2002.

32.3*

Certification of the Vice President, Treasurer and Secretary Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(1): Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513, filed with the Commission on August 2, 1996.
(2): Incorporated by reference to Amendment No. 1 to MarkWest Hydrocarbon Inc.'s Registration Statement on Form S-1, Registration No. 333-09513, filed with the Commission on September 13, 1996.
(3): Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Quarterly Report on Form 10-Q for the three months ended September 30, 1997, filed with Commission on November 13, 1997.
(4): Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Current Report on Form 8-K, filed with the Commission on August 27, 2001.
(5): Incorporated by reference to MarkWest Energy Partners, L.P.'s Current Report on Form 8-K, filed with the Commission on June 7, 2002.
(6): Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Quarterly Report on Form 10-Q for the three months ended June 30, 2002, filed with the Commission on August 14, 2002.
(7): Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Current Report on Form 8-K, filed with the Commission on November 25, 2002.
(8): Incorporated by reference to MarkWest Energy Partners, L.P.'s Current Report on Form 8-K, filed with the Commission on April 14, 2003.
(9): Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Current Report on Form 8-K, filed with the Commission on July 15, 2003.
(10): Incorporated by reference to MarkWest Energy Partners, L.P.'s Current Report on Form 8-K, filed with the Commission on September 17, 2003.
(11): Incorporated by reference to MarkWest Energy Partners, L.P.'s Current Report on Form 8-K, filed with the Commission on December 16, 2003.
(12): Incorporated by reference to MarkWest Energy Partners, L.P.'s Current Report on Form 8-K, filed with the Commission on December 31, 2003.
(13): Incorporated by reference to Item 8, Consolidated Statements of Operations, and footnote 2 of Summary of Significant Accounting Policies, Earnings Per Share, of the Annual Report Form 10-K.
+: 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.