**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

**FORM 10-K**

 

**ý****          ****Annual report pursuant to Section 13or 15(d) of the Securities Exchange Act of 1934**

** **

**for the fiscal year ended December 31, 2004.**

** **

**o****          ****Transition report pursuant to Section 13or 15(d) of the Securities Exchange Act of 1934**

** **

**for the transition period from                     to                         .**

** **

**Commission File Number 1-14841**

 

**MARKWEST HYDROCARBON, INC.**

(Exact name of registrant as specified in its charter)

 
| **Delaware**                                                     | ** ** | **84-1352233**                        |
|------------------------------------------------------------------|------------|---------------------------------------|
| (State or other jurisdiction of   incorporation or organization) |       | (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 allreports required to be filed by Section 13 or 15(d) of the SecuritiesExchange Act of 1934 during the preceding 12 months (or for such shorter periodthat the registrant was required to file such reports), and (2) has beensubject to such filing requirements for the past 90 days.  Yes o  No  ý

 

Indicateby check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K is not contained herein, and will not be contained, to the bestof registrant’s knowledge, in definitive proxy or information statementsincorporated by reference in Part III of this Form 10-K or anyamendment to this Form 10-K.  o

 

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

 

The aggregate market value of voting common stock held bynon-affiliates of the registrant on June 30, 2004 was approximately $60.4million.

 

The number of shares outstanding of the registrant’s common stock(excluding treasury stock) as of September 9, 2005, was 10,794,729.

 

**DOCUMENTS INCORPORATED BYREFERENCE**

 

None.

 

 

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**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                                                                         |   |
| Item 9B.          | Other Information                                                                                |   |
|              |                                                                                             |   |
| **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 and Related Stockholder  Matters |   |
| Item 13.          | Certain  Relationships and Related Transactions                                                  |   |
| Item 14.          | Principal  Accountant Fees and Expenses                                                          |   |
|              |                                                                                             |   |
| **PART IV**  |                                                                                             |   |
| Item 15.          | Exhibits  and Financial Statement Schedules                                                      |   |

 

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Inthis document, unless the context requires otherwise, references to “we,” “ us,”“our,” “MarkWest Hydrocarbon” or the “Company” are intended to mean MarkWestHydrocarbon, Inc., and its consolidated subsidiaries.

 

# **Glossary of Terms**

#  

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

 
| Bbls         | barrels                                                             |
|--------------|---------------------------------------------------------------------|
| Bbl/d        | barrels per day                                                     |
| Bcf          | one billion  cubic feet of natural gas                              |
| Btu          | one British  thermal unit, an energy measurement                    |
| Gal/d        | gallons per day                                                     |
| Gross Margin | revenues less  purchased product costs                              |
| 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                                                      |
| Tcf          | one trillion  cubic feet of natural gas                             |
|         |                                                                |

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

 

**Explanatory Note**

 

We have determined that, in certain cases, wedid not comply with generally accepted accounting principles in the preparationof our 2002 and 2003 consolidated financial statements and, accordingly, wehave restated our 2002 and 2003 annual financial statements in this 2004 AnnualReport on Form 10-K.  The Companyhas also filed Form 10-Q/A’s for the first three quarters of 2004 torestate its quarterly financial statements for 2003 and 2004.

 

The Company has determined that earlier issuedfinancial statements for the years 2002 and 2003 and the first three quartersof 2003 and 2004 should be restated to reflect compensation expense in ourfinancial statements for the sale of subordinated units of MarkWest EnergyPartners, L.P. (the “Partnership” or “MarkWest Energy”) and interests inMarkWest Energy GP, LLC (the “general partner”), the Partnership’s generalpartner, to certain of our employees and directors from 2002 through 2004 andfor an error in accounting for natural gas inventory in the fourth quarter of2003.  The Company is filingcontemporaneously with this Form 10-K, its quarterly reports on Form 10-Q/Afor the quarterly periods ended March 31, 2004, June 30, 2004 and September 30,2004.

 

As discussed more fully in Note 23, *Restatementof Consolidated Financial Statements*, tothe consolidated financial statements in Item 8 of this Form 10-K, therestatements have been made to account for the sale by the Company of its generalpartnership interests in the Partnership’s general partner to certain of itsemployees and directors, and the sale by the Company of its subordinated unitsof the Partnership to certain employees and directors of the Company ascompensatory arrangements pursuant to the guidance in Accounting PrinciplesBoard Opinion (“APB”) No. 25, *Accounting for Stock Issued toEmployee* and Emerging Issues TaskForce (“EITF”) No. 95-16, *Accounting for Stock CompensationArrangements with Employer Loan Features under APB Opinion No. 25.*  Thisguidance requires the Company to record compensation expense for the differencebetween the market value of the subordinated Partnership units and the formulavalue of the general partner interests held by these employees and directors atthe end of each reporting period.  Thesetransactions were previously reflected as sales of assets.

 

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TheCompany has also restated revenue for 2003 by $0.1 million to record naturalgas inventory in pipelines at cost. Previously, the inventory was incorrectly identified as sold with apipeline imbalance and was recorded at fair value. In addition, an adjustment of $2.5 million was also made to restate restrictedmarketable securities from restricted cash. Finally, the Company adjusted the income tax provision (benefit) for therestatement adjustments.

 

In addition, on October 28, 2004, theCompany’s Board of Directors declared a stock dividend of one share of theCompany’s common stock for each ten shares owned by stockholders.  The stock dividend was paid on November 19,2004 to the stockholders of record as of the close of business on November 9,2004.  Common stock information in this Form 10-Khas been restated to give retroactive effect to the stock dividend paid.

 

The Company has reclassified certain 2002 and2003 financial statement components to conform to the 2004 presentation.  The December 31, 2003 balance sheetseparately reflects intangible assets, net, and deferred financing costs, net,that were previously aggregated.  Thestatements of operations for the years ended December 31, 2003 and 2002separately reflect interest expense and amortization of deferred financingcosts that were previously aggregated.

 

**Forward-Looking Information**

 

Statements included inthis Annual Report on Form 10-K and documents incorporated by reference tothis report that are not historical facts are forward-looking statements withinthe meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21Eof the Securities and Exchange Act of 1934, as amended.  We use words such as “may,” “believe,” “estimate,”“expect,” “intend,” “project,” “anticipate,” and similar expressions toidentify forward-looking statements.

 

These forward-lookingstatements are made based upon management’s expectations, estimates,assumptions and beliefs concerning future events impacting us and thereforeinvolve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actualresults could differ materially from those expressed or implied in theforward-looking statements. Forward-looking statements include statements relating to, among otherthings:

 

•      Ourexpectations regarding MarkWest Energy Partners, L.P.

•      Ourability to grow MarkWest Energy Partners, L.P.

•      Ourability to amend certain producer contracts.

•      Ourexpectations regarding natural gas, NGLs product and prices.

•      Ourefforts to increase fee-based contract volumes.

•      Ourability to manage our commodity price risk.

•      Ourability to maximize the value of our NGL output.

•      Theadequacy of our general public liability, property, and business interruptioninsurance.

•      Ourability to comply with environmental and governmental regulations.

 

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

 

•      Theavailability of raw natural gas supply for our gathering and processingservices.

•      Theavailability of NGLs for our transportation, fractionation and storageservices.

•      Pricesof NGL products and natural gas, including the effectiveness of any hedgingactivities.

•      Ourability to negotiate favorable marketing agreements.

•      Therisks that third party natural gas exploration and production activities willnot occur or be successful.

•      Ourdependence on certain significant customers, producers, gatherers, treaters andtransporters of natural gas.

•      Competitionfrom other NGL processors, including major energy companies.

 

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•      Oursubstantial debt and other financial obligations could adversely impact ourfinancial condition.

•      Ourability to successfully integrate our recent or future acquisitions.

•      Ourability to identify and complete grass-roots projects or acquisitionscomplementary to our business.

•      Changesin general economic conditions in regions in which our products are located.

•      Winterweather conditions.

 

These factors are not necessarily all of the importantfactors that could cause actual results to differ materially from thoseexpressed in any of our forward-looking statements.  Other unknown or unpredictable factors couldalso have material adverse effects on future results.  The Company does not update publicly anyforward looking statement whether as a result of new information or futureevents.  Investors are cautioned not toput undue reliance on forward-looking statements.  You should read *Risk Factors* included in Item 7 of this Form 10-K forfurther information.

 

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**PART I**

 

**ITEMS 1.AND 2.  BUSINESS AND PROPERTIES**

 

**General**

 

We are anenergy company primarily focused on growing the value of our investment inMarkWest Energy, a publicly-traded limited partnership engaged in thegathering, processing and transmission of natural gas, the transportation,fractionation and storage of natural gas liquids (“NGLs”); and the gatheringand transportation of crude oil. We also market NGLs and natural gas.

 

Ourassets consist almost exclusively of partnership interests in MarkWestEnergy.  As of December 31, 2004, weowned a 25% interest in the Partnership consisting of the following:

 

•      2,469,496subordinated units, representing a 23% limited partner interest in the Partnership;and

•      a90% ownership interest in MarkWest Energy GP, L.L.C., the general partner ofthe Partnership, which in turn owns a 2% general partner interest and all ofthe incentive distribution rights in the Partnership.

 

Wewere founded in 1988 as a partnership and later incorporated in Delaware.  We completed our initial public offering in1996.

 

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

 

**Overview**

 

Since the formation ofthe Partnership, we have transformed MarkWest Hydrocarbon into a companyfocused on increasing shareholder value through our ownership in MarkWestEnergy.  Specifically, we discontinuedour exploration and production business in 2003 while facilitating the growthof MarkWest Energy through its acquisition of third-party midstreamassets.  From 2002 through December 31,2004, the Partnership completed six acquisitions for an aggregate purchase priceof $354.4 million.  These acquisitionsincluded:

 

•      In July 2004, thePartnership acquired natural gas gathering and processing assets located ineast Texas for $240.7 million.  Theassets, which we refer to as our East Texas System, consisted of approximately210 miles of natural gas gathering system pipelines, natural gas gatheringsystem pipelines currently under construction, 15 centralized compressorstations representing 74,000 horsepower of compression and a proposed naturalgas processing facility, now under construction.

•      InApril 2004, the Partnership acquired a lateral pipeline in Hobbs, NewMexico for approximately $2.3 million.

•      InDecember 2003, the Partnership acquired an intrastate crude oil pipelinein Michigan for approximately $21.3 million.

•      InDecember 2003, the Partnership also acquired a 167-mile gathering system,a processing plant and related compression facilities located in Oklahoma forapproximately $38.0 million.  ThePartnership has since expanded the gathering system to 240 miles of pipeline asof December 31, 2004.

•      InSeptember 2003, the Partnership acquired a 70-mile intrastate gastransmission pipeline near Lubbock, Texas for approximately $12.2 million.

•      In March 2003, thePartnership completed its acquisition of $39.9 million of midstream assets fromPinnacle in the Southwest.  The acquiredassets, primarily located in Texas, were comprised of (i) three lateralnatural gas pipelines transporting natural gas under firm contracts to powerplants and (ii) twenty gathering systems. One of the smaller gatheringsystems acquired was subsequently disposed of in December 2003 for aninsignificant amount and two were sold in 2004 for proceeds of approximately$0.1 million.

 

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**Strategy**

 

Ourtwo-part strategy is to increase shareholder value by growing the value of ourinvestment in MarkWest Energy and its cash distributions, and to improve thestability of our operating margins in our marketing business segment.

 

Webelieve the primary opportunity to increase shareholder value is tied to ourability to successfully facilitate the growth of MarkWest Energy.  The Partnership’s strategy is to grow itsbusiness, increase distributable cash flow to its common unitholders, improveits financial flexibility and increase its ability to access capital to fundits growth.  The Partnership plans toaccomplish this by increasing utilization of its facilities, expandingoperations through new construction, expanding operations through strategicacquisitions and securing additional long-term fee-based contracts.  If the Partnership is successful inimplementing this strategy, we believe the total amount of cash distributionsit makes will increase and our share of those distributions will also increase.The Partnership has announced multiple increases in its quarterly distributionsince its initial public offering in May 2002. Since that time, thePartnership has increased the quarterly per unit cash distribution on itscommon and subordinated units by 60%, from $0.50 to $0.80.

 

**Financial Information About Segments**

 

Our business activities are segregated intotwo segments:

 

•      Managing MarkWest Energy

•      Marketing of natural gasand NGLs

 

You should read Note 19 of the accompanyingNotes to Consolidated Financial Statements included in Item 8 of this Form 10-K,for financial information about our business segments.

 

**NarrativeDescription of Business**

 

***Our Relationship with MarkWest Energy***

 

We spun off the majority of our then-existing naturalgas gathering and processing and NGL transportation, fractionation and storageassets into MarkWest Energy in May 2002, just before the Partnershipcompleted its initial public offering. At the time of its formation and initialpublic offering, we entered into four contracts with MarkWest Energy wherebyMarkWest Energy provides midstream services for us in exchange for a fee. Inaccordance with generally accepted accounting principles, MarkWest Energy’sfinancial results are included in our consolidated financial statements.  All intercompany accounts and transactionsare eliminated during consolidation. Also at the time of MarkWest Energy’sinitial public offering, we entered into an omnibus agreement with MarkWestEnergy and related parties that govern potential competition andindemnification obligations among the involved parties.

 

As a result of the contracts between MarkWest Energyand us mentioned above, we are the Partnership’s largest customer, accountingfor 20% and 42% of its revenues, respectively, and 32% and 59% of its grossmargin for the year ended December 31, 2004 and 2003, respectively.  If the Partnership includes the results ofoperations from its 2004 acquisitions for the full year, and not just for theperiod that it owned the assets, our share would have been reduced to 18% ofthe Partnership’s pro forma revenue and 27% of its pro forma gross margin forthe year ended December 31, 2004. We expect we will continue to account for less of MarkWest Energy’sbusiness in the future as it continues to acquire assets and increase itscustomer base or diversify its business.

 

Through our majority ownership in the Partnership’sgeneral partner, we control and operate MarkWest Energy. Our employees areresponsible for conducting the Partnership’s business and operating its assetspursuant to a Services Agreement, which was formalized and made effective January 1,2004.

 

***Overview of theIndustry***

 

The following diagramillustrates the natural gas gathering, processing and fractionation process:

 

7

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Theindustry is characterized by regional competition based on the proximity ofgathering systems and processing plants to producing natural gas wells.

 

Naturalgas has a widely varying composition, depending on the field, the formation orthe reservoir from which it is produced. The principal constituents of naturalgas are methane and ethane, though most natural gas also contains varyingamounts of heavier components, such as propane, butane, natural gasoline and inertsubstances that may be removed by any number of processing methods.

 

Mostnatural gas produced at the wellhead is not suitable for long-haul pipelinetransportation or commercial use and must be gathered, compressed andtransported via pipeline to a central processing facility and then processed toremove the heavier hydrocarbon components and other contaminants that wouldinterfere with pipeline transportation or the end use of the gas. Our businessincludes these necessary services for either a fee or a percentage of the NGLsremoved or gas units processed.

 

The natural gas gatheringprocess begins with the drilling of wells into gas bearing rockformations.  Once a well has beencompleted, the well is connected to a gathering system.  Gathering systems typically consist of anetwork of small diameter pipelines and, if necessary, compression systems thatcollect natural gas from points near producing wells and transport it to largerpipelines for further transmission.

 

Naturalgas processing and treating involves the separation of raw natural gas intopipeline quality natural gas, principally methane, and NGLs, as well as theremoval of contaminants. In this process, raw natural gas from the wellhead isgathered at a processing plant, typically located near the production area,where it is dehydrated and treated, then sent through a process from which amixed NGL stream is recovered.

 

The removal and separation of individualhydrocarbons by processing is possible because of differences in physical properties,as each component has a distinctive weight, boiling point, vapor pressure andother physical characteristics. Natural gas may also contain water, sulfurcompounds, carbon dioxide, nitrogen, helium or other components that may bediluents and contaminants.  Natural gascontaining sulfur is referred to in the industry as “sour gas”.

 

Afterbeing separated from natural gas at the processing plant, the mixed NGL streamis typically transported to a centralized facility for fractionation.  Fractionation is the process by which NGLsare further separated into individual, more marketable components, consistingof ethane, propane, normal butane, isobutane and natural gasoline.Fractionation systems typically exist either as an integral part of a gasprocessing plant or as a “central fractionator”, often located many miles fromthe primary production and processing facility. A central fractionator mayreceive mixed streams of NGLs from many processing plants.

 

Describedbelow are the five basic NGL products and their typical uses:

 

•         *Ethane. *Ethaneis used primarily as feedstock in the production of ethylene, one of the basicbuilding blocks for a wide range of plastics and other chemical products.  Ethane is not produced at the Partnership’sSiloam fractionator as there is little petrochemical demand for

 

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ethanein Appalachia and, therefore, it remains in the natural gas stream.  Ethane, however, is produced and sold in thePartnership’s East Texas and Oklahoma operations.

 

•         *Propane. *Propaneis used for heating fuel, engine fuel, industrial fuel and for agriculturalburning and drying and as a petrochemical feedstock for production of ethyleneand propylene.  Propane is principallyused as a fuel in our operating area.

 

•         *Normal butane. *Normal butane is principally used for gasoline blending, as afuel gas, either alone or in a mixture with propane, and as a feedstock for themanufacture of ethylene and butadiene, a key ingredient of syntheticrubber.  In Appalachia we sell themajority of our normal butane to a specialty chemical manufacturer.

 

•         *Isobutane. *Isobutaneis principally used by refiners to enhance the octane content of motor gasolineand in the production of MTBE, an additive in cleaner burning motor gasoline.

 

•         *Natural gasoline.*Natural gasoline isprincipally used as a motor gasoline blend stock or petrochemical feedstock.

 

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***MarkWest Energy’s Assets***

 

The Partnership has five primary geographicareas of operation, three in the Southwest, one in Appalachia and one inMichigan:

 

•              ***Southwest***

 

•      *East Texas.*  On July 30, 2004, the Partnershipacquired certain natural gas gathering and processing assets, the East TexasSystem, located in east Texas from American Central Eastern Texas Gas Company,Limited Partnership.  The East TexasSystem currently consists of natural gas gathering system pipelines, naturalgas gathering system pipelines currently under construction, centralizedcompressor stations and a natural gas processing facility, also currently underconstruction.  The East Texas System islocated in Panola County and services the Carthage Field, one of Texas’ largestonshore natural gas fields.  Producingformations in Panola County currently consist of the Cotton Valley, Pettit andTravis Peak formations which form one of the largest natural gas producingregions in the United States.  TheCarthage Field has approximately 18 Tcf of estimated recoverable reserves andcumulative historical production in excess of 12 Tcf.

 

•      *Oklahoma*. The Partnership owns the FossLake gathering system and the Arapaho gas processing plant located in thewestern Oklahoma counties of Roger Mills and Custer, respectively.  The gathering system is comprised of a pipelinesystem that is connected to natural gas wells and associated compressionfacilities.  All of the gathered gas isultimately compressed and delivered to the processing plant.  After processing, all residue gas isdelivered to a third party pipeline and all natural gas liquids are sold to onecustomer.

 

•      *Other Southwest*. The Partnership owns 17natural gas gathering systems located in Texas, Louisiana, Mississippi and NewMexico.  These systems generally servicelong-lived natural gas basins that continue to experience drillingactivity.  The Partnership gathers asignificant portion of the gas produced from fields adjacent to its gatheringsystems.  In many areas, MarkWest Energyis the primary gatherer, and in some of the areas served by its smaller systemsthe Partnership is the sole gatherer.  Inaddition, MarkWest Energy owns four lateral pipelines in Texas and New Mexico.

 

•      ***Appalachia*.**  The Partnership is a processor of natural gasin the Appalachian basin with fully integrated processing, fractionation,storage and marketing operations.  TheAppalachian basin is a large natural gas producing region characterized bylong-lived reserves and modest decline rates. The Partnership’s Appalachian assets include five natural gas processingplants, a NGL pipeline, a NGL fractionation plant and two caverns storingpropane.

 

•      ***Michigan*. **The Partnership owns the largestintrastate crude oil pipeline in Michigan. The Partnership refers to this system as the Michigan CrudePipeline.  MarkWest Energy also owns a naturalgas gathering system and a natural gas processing plant in Michigan.

 

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# ***ThePartnership’s Southwest Assets***

#  

*Gatheringand Processing Facilities*

 

*East Texas*

 

Thetable below describes the Partnership’s East Texas gathering and processingassets:

 
| ** **                         | ** ** | ** **         | ** ** | ** **                                | ** ** | ** **                                | ** ** | **Year Ended December 31, 2004**    | ** ** |
|------------------------------------|------------|--------------------|------------|-------------------------------------------|------------|-------------------------------------------|------------|------------------------------------------|------------|
| **Facility**                       | ** ** | **Location**       | ** ** | **Year of****Initial  Construction** | ** ** | **Design  Throughput  Capacity  (Mcf/d)** | ** ** | **Natural  Gas  Throughput  (Mcf/d)(1)** | ** ** | **Utilization  of Design  Capacity** | ** ** | **NGL****Throughput  (gal/day)** | ** ** |
| East Texas  gathering system(2)(3) |       | Panola County, TX  |       | 1990                                      |       | 350,000                                   |       | 259,300                                  |       | 74 | % | NA |   |
| East Texas  processing plant(4)    |       | Panola, County, TX |       | 2005, anticipated                         |       | 200,000                                   |       | NA                                       |       | NA |   | NA |   |

 

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(1)   Throughputvolumes are for the calendar year ended December 31, 2004, and not justfor the period of time the Partnership owned each facility.

(2)   MarkWestEnergy acquired the East Texas gathering system on July 30, 2004.

(3)   Thedesign throughput capacity for the East Texas gathering system includes the throughputcapacity upon completion of the 18 miles of natural gas pipeline underconstruction.

(4)   Constructionis anticipated to be completed in 2005.

 

*East Texas gathering system.*  The Partnership acquired the East TexasSystem in July 2004.  The system isa low-pressure regional gathering system consisting of approximately 210 milesof natural gas gathering pipeline connected to approximately 1,730 upstreamwell connections, with approximately 20 additional miles of pipeline currentlyunder construction, and includes 15 centralized compressor stations with anaggregate of approximately 74,000 horsepower of compression, with an additional16,000 horsepower of new compression and processing plant recompressioncurrently being installed.  The systemgathers natural gas from the Carthage Field in east Texas from approximately 20producers.

 

*East Texas processing plant and NGL transportation*.  In conjunction with the Partnership’s EastTexas System acquisition in July 2004, MarkWest Energy is currentlyconstructing a 200 MMcf/d skid-mounted cryogenic processing plant in east Texasdesigned to recover ethane and heavier hydrocarbons.  The plant is designed to operate efficientlyin an ethane recovery or rejection mode. Plant residue natural gas is expected to be delivered to a thirdparty.  The Partnership also expects toconstruct a NGL pipeline to deliver the recovered plant products to MountBelvieu for fractionation and sale.  Theplant and related pipeline are scheduled for completion by the end of December 2005.

 

ThePartnership generates revenues in East Texas through fixed fee gathering andcompression, settlement margin and condensate sales contracts, which aredescribed in more detail under Item 7, *Management’sDiscussion and Analysis of Financial Condition and Results of Operations – OurContracts*.

 

*Oklahoma*

 

Thetable below describes the Partnership’s Oklahoma gathering and processingassets:

 
| ** **                     | ** ** | ** **                        | ** ** | ** **                              | ** ** | ** **                                | ** ** | **Year Ended December 31, 2004**    | ** ** |
|--------------------------------|------------|-----------------------------------|------------|-----------------------------------------|------------|-------------------------------------------|------------|------------------------------------------|------------|
| **Facility**                   | ** ** | **Location**                      | ** ** | **Year of  Initial  Construction** | ** ** | **Design  Throughput  Capacity  (Mcf/d)** | ** ** | **Natural  Gas  Throughput  (Mcf/d)(1)** | ** ** | **Utilization  of Design Capacity** | ** ** | **NGL  Throughput  (gal/day) (1)** | ** ** |
| Foss Lake  Gathering System(2) |       | Roger Mills and Custer County, OK |       | 1998                                    |       | 70,000                                    |       | 60,900                                   |       | 87 | % | NA |   |
| Arapaho  Processing Plant(2)   |       | Custer County, OK                 |       | 2000                                    |       | 75,000                                    |       | 60,900                                   |       | 81 | % | 124,000 |   |

 

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(1)   Throughputvolumes are for the calendar year ended December 31, 2004.

(2)   ThePartnership acquired the Foss Lake gathering system and the Arapaho processingplant on December 1, 2003.

 

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*Foss Lake Gathering System.*  The Partnership acquired the Foss LakeGathering System as part of the western Oklahoma acquisition in December 2003.The system is a low-pressure gathering system consisting of approximately 240miles of four to 20-inch pipeline connected to approximately 310 wells andincludes approximately 16,000 horsepower of owned-compression and approximately3,000 horsepower of leased-compression. The system gathers natural gas from theAnadarko Basin in western Oklahoma from approximately 75 producers. ThePartnership generates revenues by charging fixed-fees per Mcf of natural gasgathered and through settlement margin arrangements. All of the natural gasgathered into the system is dehydrated at our Butler compression station fordelivery to the Partnership’s Arapaho processing plant.

 

*Arapaho Processing Plant.*  The Partnership acquired the ArapahoProcessing Plant, located in Custer County, Oklahoma, as part of the westernOklahoma acquisition in December 2003. The Arapaho gas processing plant isa cryogenic plant completed in early 2000. The plant is designed to recoverethane and heavier NGLs, including propane. The plant can also reject ethaneand continue to recover high levels of propane. The plant delivers processednatural gas into the Panhandle Eastern Pipe Line (“PEPL”) and recovered NGLsare sold into the Conway, Kansas NGL market via a pipeline system owned by athird-party.  The Partnership generatesrevenues through keep-whole contracts. Under these keep-whole arrangements, thePartnership processes the natural gas and sells the resulting NGLs to thirdparties at market prices. Because the extraction of the NGLs from the naturalgas stream during processing reduces the Btu content of the natural gas, thePartnership must either purchase natural gas at market prices for return toproducers or make a cash payment to the producers. Accordingly, under thesearrangements, the Partnership’s revenues and gross margins increase as theprice of NGLs increases relative to the price of natural gas, and thePartnership’s revenues and gross margins decrease as the price of natural gasincreases relative to the price of NGLs. In the latter case, however, MarkWest Energy has the option of notoperating the plant in a low processing margin environment because the Btucontent of the inlet natural gas meets the PEPL Btu specification.  Approximately 45% of the Foss Lake gasgathering contracts include additional fees to cover plant operating costs,fuel costs and shrinkage costs in a low processing margin environment.  Because of the Partnership’s ability tooperate the plant in several recovery modes, or to turn it off, as well as theadditional fees provided for in the gas gathering contracts, the Partnership’sexposure is limited to a portion of the operating costs of the plant.

 

*Other Southwest*

 

Thetable below describes the Partnership’s Other Southwest gathering andprocessing assets:

 
| ** **                   | ** ** | ** **                | ** ** | ** **                              | ** ** | ** **                                | ** ** | **Year Ended December 31, 2004**    | ** ** |
|------------------------------|------------|---------------------------|------------|-----------------------------------------|------------|-------------------------------------------|------------|------------------------------------------|------------|
| **Facility**                 | ** ** | **Location**              | ** ** | **Year of  Initial  Construction** | ** ** | **Design  Throughput  Capacity  (Mcf/d)** | ** ** | **Natural  Gas  Throughput  (Mcf/d)(1)** | ** ** | **Utilization  of Design Capacity** | *** *** | **NGL****Throughput  (gal/day)** | *** *** |
| Appleby  Gathering System(2) |       | Nacogdoches County, TX    |       | 1990                                    |       | 40,000                                    |       | 27,100                                   |       | 68 | % | NA |   |
| Other Gathering  Systems(2)  |       | Various in TX, LA, MS, NM |       | Various                                 |       | 53,000                                    |       | 17,000                                   |       | 32 | % | NA |   |

 

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(1)   Throughput volumesare for the calendar year ended December 31, 2004.

(2)   The Partnershipacquired the Appleby gathering system, along with 20 other gathering systems,as part of its March 28, 2003 Pinnacle acquisition.

 

*Appleby Gathering System.*  The Partnership acquired the ApplebyGathering System as part of the Pinnacle acquisition in March 2003. Thesystem is a low-pressure gathering system consisting of approximately 100 milesof three to eight-inch pipeline connected to approximately 160 wells andincludes approximately 4,000 horsepower of leased-compression and 4,000horsepower of owned compression. The system gathers natural gas from the TravisPeak basin in Texas from approximately seven producers, with one produceraccounting for approximately 50% of the volumes. The Partnership sells the gasto marketing companies and to an industrial user under short-term marketingcontracts. MarkWest Energy generates a majority of its revenues throughpercent-of-index contracts with the remaining revenue generated throughfee-based contracts, which are described in more detail under Item 7, *Management’s Discussion and Analysis of FinancialCondition and Results of Operations – Our Contracts*.

 

*Other Gathering Systems.* As part of thePinnacle acquisition, the Partnership acquired 20 other natural gas gatheringsystems, primarily located in Texas one of which was disposed of in December 2003for an insignificant

 

12

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amount and two of which have been subsequently sold in 2004 forproceeds of approximately $0.1 million. The systems typically gather naturalgas from mature producing wells. The Partnership generates revenues from thesesystems through percent-of-index, percent-of-proceeds and fixed-fee contracts,which are described in more detail under Item 7, *Management’s Discussion and Analysis of Financial Condition and Resultsof Operations – Our Contracts*.

 

*Lateral Pipelines.*  MarkWest Energy acquired the Lake Whitneylateral, the Rio Nogales lateral and the Blackhawk lateral as part of thePinnacle acquisition in March 2003. The Partnership acquired the Lubbock lateral in September 2003 andthe Hobbs lateral in April 2004. The Lubbock and Hobbs lateral pipelines are the only laterals we ownthat produce revenue on a per-unit-of-throughput basis.  The other lateral pipelines operate on afixed-fee contract basis, under which the Partnership’s customer pays a fixedmonthly fee for the dedicated volume on that pipeline, independent of thevolume of gas it transports.

 

•              TheLake Whitney lateral, constructed in 2000, is a 30-mile intrastate natural gaspipeline that transports natural gas to a third party’s 560-megawatt Bosquepower plant, located near Waco, Texas. The lateral transports natural gas fromthe El Paso Field Services Pipeline and is the only pipeline connected to, andthe sole source of natural gas for, the Bosque power plant. The Partnership hasa 30-year fixed-fee contract with its largest customer in this region fornatural gas transportation on this lateral pipeline.  This contract expires in 2030.

 

•              TheRio Nogales lateral, constructed in 2001, consists of two natural gas lateralpipelines, which in aggregate total approximately 30 miles in length. Thelaterals transport natural gas to a third party’s Rio Nogales power plant,located near Seguin, Texas. The Partnership has a 20-year fixed-fee contractwith this customer.  This contractexpires in 2022.

 

•              TheBlackhawk lateral is a six-mile intrastate natural gas pipeline that serves asa back-up natural gas supply source for a third party’s’ 200-megawattcogeneration power facility, located in Borger, Texas.  The lateral is connected to the El PasoNatural Gas pipeline.  The Partnershiphas a fixed-fee contract to operate the pipeline through September 2005.  Prior to the transfer of the ownership of thelateral to a third party in April 2004, the Partnership leased thefacility to the third party under a financing lease arrangement.

 

•              The Partnership acquired theLubbock lateral from the Power-Tex Joint Venture in September 2003. Itconsists of one 12-inch, 50-mile pipeline and one six-inch, 20-mile pipelineserving several industrial users and municipalities in and around Lubbock,Texas. The Partnership has fixed-fee contracts with terms ranging from one tofive years.  The lateral has a capacityof 100 MMcf/d and throughput was approximately 54 MMcf/d for the year ended December 31,2004.

 

•              The Partnership acquired the Hobbslateral pipeline in April 2004.  TheHobbs lateral consists of a four-mile segment of 10-inch and 12-inch naturalgas pipeline connecting the Northern Natural Gas interstate pipeline toSouthwestern Public Service’s Cunningham and Maddox power generating stationsin Hobbs, New Mexico.  The Partnershiphas a fixed-fee contract with the customer through 2008.  The Hobbs lateral was recently expanded to acapacity of approximately 170 MMcf/d and throughput was approximately 42 MMcf/dfor the nine months ended December 31, 2004 (since its acquisition).

 

13

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*ThePartnership’s Appalachian Assets*

 

*Appalachian Gathering and Processing Facilities*

 

Thetable below describes the Partnership’s processing assets in the Appalachianregion:

 
| ** **                    | ** ** | ** **         | ** ** | ** **            | ** ** | **Design**                        | ** ** | **Year Ended December 31, 2004** | ** ** |
|-------------------------------|------------|--------------------|------------|-----------------------|------------|-----------------------------------|------------|---------------------------------------|------------|
| **Facility**                  | ** ** | **Location**       | ** ** | **Year  Constructed** | ** ** | **Throughput  Capacity  (Mcf/d)** | ** ** | **Natural Gas  Throughput  (Mcf/d)**  | ** ** | **Utilization of  Design  Capacity** | ** ** |
| Kenova Processing Plant(1)    |       | Wayne County, WV   |       | 1996                  |       | 160,000                           |       | 138,000                               |       | 86 | % |
| Boldman Processing Plant(1)   |       | Pike County, KY    |       | 1991                  |       | 70,000                            |       | 41,000                                |       | 59 | % |
| Maytown Processing Plant      |       | Floyd County, KY   |       | 2000                  |       | 55,000                            |       | 57,500                                |       | 105 | % |
| Cobb Processing Plant(2)      |       | Kanawha County, WV |       | 1968                  |       | 35,000                            |       | 23,000                                |       | 66 | % |
| Kermit Processing Plant(1)(3) |       | Mingo County, WV   |       | 2001                  |       | 32,000                            |       | NA                                    |       | NA |   |

 

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(1)   A portion of the Boldman volumes and all of the Kermitvolumes are included in Kenova throughput, as these volumes require furtherprocessing at the Partnership’s Kenova facility.

(2)   In 2004, thePartnership began construction of a new 24 MMcf/d processing plant. This newplant replaces the Partnership’s existing Cobb plant.  It was completed in the first quarter of2005.

(3)   The Kermitprocessing plant is operated by a third party producer and MarkWest Energy doesnot receive inlet volume information.

 

*Kenova Processing Plant. *The Partnership’s Kenova cryogenic facility wasexpanded by 40 MMcf/d in 2001 to accommodate expected new production from athird party producer. The cryogenic process utilizes a turbo-expander and heatexchangers to cool the gas, which condenses the NGLs. The NGLs are thenseparated from condensed gaseous components by distillation. This facilityreceives all of its intake of natural gas from Columbia Gas’ transmissionpipeline and processes gas from adjoining counties. NGLs extracted at thisfacility are transported to our Siloam fractionator via pipeline.

 

*Boldman Processing Plant.*  The Partnership’s Boldman straightrefrigeration processing plant processes gas using a propane refrigerationsystem to cool the gas and condense the NGLs. The NGLs are then separated fromcondensed gaseous components by distillation. This facility receives all of its intake of natural gas from ColumbiaGas’ transmission pipelines and processes gas produced in Pike, Floyd, Letcherand Knott Counties, Kentucky.  NGLsextracted at this facility are first delivered by truck to the Partnership’sMaytown facility and transported via pipeline to its Siloam fractionator.

 

*Maytown Processing Plant.*  Pursuant to contract, a third party producerprovides certain operating services at the Partnership’s Maytown facility, astraight refrigeration plant, on its behalf. While providing operating services, this third party is responsible forthe day-to-day operation of the Maytown plant. Under the Partnership’s GasProcessing Agreement with this third party, the Partnership has the right toassume the role of operator upon providing them with a 30-day written notice.Like the Boldman plant, the Maytown plant also processes gas using a propanerefrigeration system to cool the gas and condense the NGLs. The NGLs are thenseparated from condensed gaseous components by distillation. This facilityreceives all of its intake of natural gas from the third party’s gatheringsystem in Kentucky. NGLs extracted at this facility are transported to Siloamvia pipeline.  The plant also contains atruck unloading facility that allows for the delivery of NGLs into thePartnership’s pipeline system for transportation to its Siloam fractionator.

 

*Cobb Processing Plant.*  The Partnership’s Cobb facility, arefrigerated lean oil processing plant, was acquired in 2000.  The refrigerated lean oil process utilizes apropane refrigeration system to cool the gas and the lean oil.  The chilled lean oil then absorbs the NGLs,which are then separated from the lean oil by distillation.  This facility receives its intake of naturalgas from Columbia Gas’ transmission lines and processes gas produced inKanawha, Clay, Roane and Jackson Counties, West Virginia.  NGLs extracted at this facility aretransported to the Partnership’s Siloam facility by tanker truck.  During 2004, MarkWest Energy began replacingits existing Cobb facility with a newly constructed 24 MMcf/d processingplant.  The Partnership completed theprocessing plant in the first quarter of 2005.

 

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*Kermit Processing Plant.*  Our Kermit facility, a straight refrigerationplant, was constructed in connection with the expansion at the Partnership’sKenova facility and in anticipation of increased demand for its services.  This facility was designed and constructed toincrease the volume of natural gas transported to the Partnership’s Kenovafacility by decreasing the liquid content of the natural gas in a third party’s’transmission lines. The Kermit plant processes gas using the same straightrefrigeration process used at the Partnership’s Boldman plant. NGLs extractedat this facility are transported to the Partnership’s Siloam facility viatanker truck.

 

*Appalachian NGL Pipelines*

 

ThePartnership’s Appalachia liquids pipeline includes the following segments:

 
| ** **              | ** ** | ** **                             | ** ** | ** ** | ** ** | ** **            | ** ** | **Design**                         | ** ** | **Year Ended December 31, 2004** | ** ** |
|-------------------------|------------|----------------------------------------|------------|------------|------------|-----------------------|------------|------------------------------------|------------|---------------------------------------|------------|
| **Pipeline**            | ** ** | **Location**                           | ** ** | **Miles**  | ** ** | **Year  Constructed** | ** ** | **Throughput Capacity  (gal/day)** | ** ** | **NGL Throughput  (gal/day)**         | ** ** | **Utilization of Design  Capacity** | ** ** |
| Maytown to Institute(1) |       | Floyd County, KY to Kanawha County, WV |       | 100        |       |                  | 1956       |                               | 250,000    |                                  | 152,000    |   | 61 | % |
| Ranger to Kenova(2)     |       | Lincoln County, WV to Wayne County, WV |       | 40         |       |                  | 1976       |                               | 831,000    |                                  | 152,000    |   | 18 | % |
| Kenova to Siloam        |       | Wayne County, WV to South Shore, KY    |       | 40         |       |                  | 1957       |                               | 831,000    |                                  | 425,000    |   | 51 | % |

 

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(1)   Includes 40 milesof currently unused pipeline extending from Ranger to Institute.

(2)   NGLs transportedthrough the Ranger to Kenova pipeline are included in the Kenova to Siloamvolumes.

 

The Partnership earns fees for transportingthe NGLs recovered from the Kenova, Maytown and Boldman plants to Siloam viaits Appalachian pipeline.  Prior to 2000,the Partnership owned and operated the line between Kenova and Siloam.  This pipeline system was expanded in 2000 byleasing from a third party the 100 mile segment from Maytown to Ranger toInstitute and purchasing the 40 mile segment from Ranger to Kenova and the 40mile segment from Kenova to Siloam. These segments provide a contiguous pipeline system from the Partnership’sMaytown plant to Kenova and Kenova to Siloam. The segment from Ranger to Institute is not required for the NGLpipeline operation and is currently idle.

 

NGLs extracted from the Partnership’s Maytownand Kenova plants are injected directly into this pipeline system andtransported to its Siloam fractionator. NGLs extracted from the Partnership’s Boldman plant are trucked to theMaytown plant and transported via the NGL pipeline to Siloam.

 

In November of 2004, a failure occurredon the section of leased pipeline from Maytown to Ranger.  The U.S. Department of Transportation Officeof Pipeline Safety (“OPS”) issued an order requiring among other thingshydrostatic testing of the line prior to its return to service.  Until the pipeline is returned to service,Maytown and Boldman NGLs are being trucked to Siloam for fractionationresulting in an increase to our NGL transportation costs.  The Partnership has submitted claims for andis pursuing business interruption insurance to cover the increasedtransportation costs incurred and lost income due to the pipeline being out ofservice as a result of the fire and explosion and OPS order.  From November 2004 through December 31,2004, the Partnership’s interruption loss was approximately $0.5 million.  The Partnership expects to incur theseadditional transportation costs until the pipeline is returned to service.

 

15

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*Appalachian Fractionation Facility*

 

The Partnership’s Siloam fractionation plantreceives substantially all of its NGLs via pipeline or tanker truck from itsfive Appalachia processing plants, with the balance received from tanker truckand rail car deliveries from other third-party NGL sources. The NGLs are thenseparated into NGL products, including propane, isobutane, normal butane andnatural gasoline. The typical composition of the NGL throughput in thePartnership’s Appalachian operations has been approximately 64% propane, 18%normal butane, 6% isobutene and 12% natural gasoline. The Partnership does notcurrently produce or sell any ethane. The Partnership generates revenues by charging fees for fractionatingNGLs that it receives from the Partnership’s processing plants and thirdparties.

 

Thefollowing table provides additional detail regarding the Partnership’s Siloamfractionation plant:

 
| ** **                 | ** ** | ** **      | ** ** | ** **            | ** ** | **Design**                         | ** ** | **Year Ended December 31, 2004** | ** ** |
|----------------------------|------------|-----------------|------------|-----------------------|------------|------------------------------------|------------|---------------------------------------|------------|
| **Facility**               | ** ** | **Location**    | ** ** | **Year  Constructed** | ** ** | **Throughput Capacity  (gal/day)** | ** ** | **NGL Throughput  (gal/day)**         | ** ** | **Utilization  of Design Capacity** | ** ** |
| Siloam Fractionation Plant |       | South Shore, KY |       | 1957                  |       | 600,000                            |       | 475,000                               |       | 79 | % |

 

*AppalachianStorage Facilities*

 

InAppalachia, the Partnership’s Siloam facility has both above ground,pressurized storage facilities, with capacity of three million gallons andunderground storage facilities, with capacity of 11 million gallons.Product can be received by truck, pipeline or rail car and can be transportedfrom the facility by truck, rail car or barge. There are eight automated 24-hour-a-daytruck loading and unloading slots, a modern rail loading/unloading rack with 12unloading slots, and a river barge facility capable of loading barges with acapacity of up to 840,000 gallons. The Partnership generates revenues from theunderground storage facilities by charging an annual fee.

 

*ThePartnership’s Michigan Assets*

 

*Michigan Gathering and Processing Facilities*

 

Thetable below describes the Partnership’s Michigan gathering and processingassets:

 
| ** **                      | ** ** | ** **                              | ** ** | ** **            | ** ** | **Design**                            | ** ** | **Year Ended December 31, 2004** | ** ** |
|---------------------------------|------------|-----------------------------------------|------------|-----------------------|------------|---------------------------------------|------------|---------------------------------------|------------|
| **Facility**                    | ** ** | **Location**                            | ** ** | **Year  Constructed** | ** ** | **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                                |       | 12,300                                |       | 35 | % | NA |   |
| Fisk Processing  Plant          |       | Manistee County, MI                     |       | 1998                  |       | 35,000                                |       | 12,300                                |       | 35 | % | 26,900 |   |

 

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(1)   MarkWestHydrocarbon has retained a 70% net profits interest in all gathering andprocessing fees generated by throughput volumes in excess of 10 MMcf/d,calculated quarterly.

 

The Partnership’s Michigan gathering pipelinegathers and transports sour gas produced by third parties in Oceana, Mason andManistee Counties for sulfur removal at a treatment plant that is owned andoperated by one of the Partnership’s customers. MarkWest Energy’s Fiskprocessing plant is located adjacent to the Partnership’s customer’s treatmentplant. The Partnership’s gathering pipeline serves approximately 30 wells andfour producers in this three county area. The Fisk plant processes all of thenatural gas gathered by the Partnership’s pipeline and produces propane and abutane-natural gasoline mix.  MarkWestEnergy processes natural gas under a number of third-party agreements containingboth fee and percent-of-proceeds components. Under these agreements, productionfrom all of the acreage adjacent to the Partnership’s pipeline and processingfacility is dedicated to its gathering and processing facilities.  Fee arrangements represent approximatelyone-half of the Partnership’s gathering and processing gross margin inMichigan.

 

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The Partnership generates revenues from itsMichigan natural gas and NGL operations primarily by charging a fee for thegathering and processing services that the Partnership provides.  MarkWest Energy contracts in Michigan alsoprovide that we retain a portion of the proceeds from the sale of NGLs that areproduced at the Partnership’s Michigan facility.  MarkWest Energy’s propane and butane-naturalgasoline production is usually sold at the plant.

 

*Michigan Crude Pipeline*

 

The Michigan Crude Pipeline consists ofapproximately 150 miles of eight to 16-inch main pipeline, approximately 100miles of four to ten-inch gathering pipeline, four truck loading facilities and15 storage tanks.  The pipeline, whichserves over 1,000 oil and gas wells on the Niagaran Reef Trend, delivers crudeoil to the Enbridge Pipeline.  ThePartnership generates operating margins by charging a pipeline transportationfee based on volumes.  The pipeline has acapacity of 60,000 bbl/d and transported approximately 14,700 bbl/d of crudeoil for the year ended December 31, 2004.

 

***MarkWestHydrocarbon Assets***

 

***Marketing***

 

Ourmarketing group markets our NGL production in Appalachia.  In 2004, we sold approximately 174 milliongallons 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 madeon best-efforts basis and are priced in reference to Mt. Belvieu index prices orplant posting prices.  In addition to ourNGL product sales, our marketing operations are also responsible for thepurchase of natural gas delivered for the account of producers pursuant to ourkeep-whole processing contracts.

 

Westrive to maximize the value of our NGL output by marketing directly to ourcustomers.  We minimize the use of third-partybrokers, preferring instead to support a direct marketing staff focused onmulti-state and independent dealers. Additionally, we use our own trailer and railcar fleet, as well as ourown terminal and owned and leased storage facilities, to enhance supplyreliability to our customers. These efforts have allowed us to generallymaintain premium pricing for the majority of our NGL products compared to GulfCoast spot prices.

 

InAppalachia, we have entered into operating agreements with Columbia GasTransmission Corporation (“Columbia Gas”) with respect to natural gas deliveredinto its transmission facilities upstream of MarkWest Energy’s Kenova, Boldmanand Cobb facilities. Under the terms of these operating agreements, ColumbiaGas has agreed to use reasonable, diligent efforts to supply these facilitieswith consistent volumes of natural gas shipped by Columbia Gas on behalf of theAppalachian producers. The initial terms of our agreements with Columbia Gasrun through December 31, 2015, with annual renewals thereafter.

 

Ouroperating agreements with Columbia Gas require us to enter into contracts withthe natural gas producers for their production to be processed in thePartnership’s Kenova, Boldman and Cobb facilities prior to delivery of theproducer’s natural gas to Columbia. We have contractual commitments withapproximately 260 such producers in Appalachia. Approximately 54% of thesecontracts representing approximately 27% of the committed volumes expire in2009. The remaining balance of approximately 46% of the contracts representingapproximately 73% of the committed volumes expires in 2015.  Under the provisions of our contracts withthe Appalachian producers, the producers have committed all of the natural gasthey deliver into Columbia Gas’ transmission facilities upstream of MarkWestEnergy’s Kenova, Boldman and Cobb facilities for processing.

 

As compensationfor providing processing services to our Appalachian producers (we have sinceoutsourced these services to MarkWest Energy as discussed below), we earn botha fee and retain the NGLs produced.  Inreturn, we are required to replace, in dry natural gas, the energy content ofthe NGLs extracted. This Btu replacement obligation is referred to in theindustry as a “keep-whole” arrangement. In keep-whole arrangements, ourprincipal cost is the replacement of the Btus extracted from the gas stream inthe form of NGLs or consumed as fuel during processing with dry gas of anequivalent Btu content. Generally, the value of the NGLs

 

17

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extracted is greater than thecost of replacing those Btus with dry gas, resulting in positive operatingmargins under these contracts.  In theevent natural gas becomes more expensive, on a Btu equivalent basis, than NGLproducts, the cost of keeping the producer “whole” results in operatinglosses.  The spread between the NGLproduct sales price and the purchase price of natural gas with an equivalentBtu content is called the “frac spread”.

 

In September 2004,we entered into several new and amended agreements with one of the largestAppalachia producers, which allow us to significantly reduce our exposure tocommodity price risk for approximately 25% of our keep-whole gas volumes.  Under these agreements, the Company islimited on the amount of costs it would have to pay to the producer in theevent natural gas becomes more expensive than NGL product sales price, therebymitigating the risk of incurring operating losses.

 

At theclosing of MarkWest Energy’s initial public offering on May 24, 2002, weoutsourced our midstream services to the Partnership, which performs naturalgas gathering and processing and NGL transportation, fractionation and storageservices for us for a fee pursuant to the terms of our operating agreementswith the Partnership.  Under thoseagreements, we retained all the benefits and associated risks of our keep-wholecontracts with producers.  Our NGL andgas marketing operations were not contributed to MarkWest Energy.

 

Ourkeep-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 ourmarketing results and cash flows volatile. From time to time, we attempt tomitigate our commodity price risk through our hedging program. You should readItem 7A, Q*uantitative and QualitativeDisclosures About Market Risk*for further details about ourcommodity price risk management program.

 

Our natural gasmarketing group markets natural gas for MarkWest Energy’s facilities, purchasesour replacement Btu gas requirements and assists with our business developmentefforts.  We also purchase and resellnatural gas obtained from third parties. Historically, a significant percentage of our overall revenue came fromgas marketing, although the contribution to gross margin is generallymodest.  With the growth of MarkWestEnergy, the percentage of revenue derived from gas marketing has decreasedsignificantly.  For the years ended December 31,2004, 2003, and 2002, 8%, 17%, and 37%, respectively, of gathering, processingand marketing revenue stemmed from gas marketing. However, the gas marketinggross margin as a percent of gathering, processing and marketing gross marginwas 1%, 0%, and 12%, respectively.

 

Beginning in February 2004,we initiated a wholesale propane marketing business through an agencyrelationship with a third party marketer located in Kansas City, Missouri.  We buy propane on a wholesale basis andresell it to third parties, primarily propane retailers.  This operation is fundamentally ahigh-dollar, low margin business.    Forthe year ended December 31, 2004 the percentage of our revenue and grossmargin derived from our wholesale propane marketing business was 7% and 1%,respectively.

 

***Explorationand Production***

 

We discontinued ourexploration and production business during 2003.  As of December 31, 2004, our explorationand production assets had been reduced to a minority interest in three wells inMichigan.

 

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*Reserves*

 

Please reviewNote 21 of the accompanying Notes to Consolidated Financial Statements includedin Item 8 of this Form 10-K,for information regarding our proved and developed oil and gas reserves and thestandardized measure of discounted future net cash flows and changes therein.

 

We have notfiled any oil or natural gas reserve estimates or included any such estimatesin reports to a federal or foreign government authority or agency, other than theSecurities and Exchange Commission (SEC) and the Department of Energy (DOE).There were no differences between the reserve estimates included in the SECreport, the DOE report and those included herein, except for production andadditions and deletions due to the difference in the “as of” dates of suchreserve estimates.

 

*Production*

 

Thefollowing table sets forth information regarding net oil and natural gasproduction, average sales prices and other production information. Hedginggains and losses are disclosed separately for the years ended December 31,2004, 2003 and 2002.

 
| ** **                                   | ** ** | **United States** | ** ** | **Canada** | ** ** |
|----------------------------------------------|------------|-------------------|------------|------------|------------|
| ** **                                   | ** ** | **2004**          | ** ** | **2003**   | ** ** | **2002** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| Quantities produced and sold:                |       |              |       |       |       |   |   |   |   |   |   |   |   |
| Natural gas  (MMcf)                          |       | 106               |       | 1,981      |       | 3,228 |   | — |   | 5,341 |   | 7,098 |   |
| Oil and liquids  (MBbl)                      |       | 4                 |       | 24         |       | 23 |   | — |   | 87 |   | 45 |   |
| Total MMcfe (1)                              |       | 128               |       | 2,125      |       | 3,367 |   | — |   | 5,866 |   | 7,370 |   |
| Average Mcfe/d                               |       | —            | (2)        | 5,800      |       | 9,200 |   | — |   | 16,100 |   | 20,200 |   |
|                                         |       |              |       |       |       |   |   |   |   |   |   |   |   |
| Average sales price:                         |       |              |       |       |       |   |   |   |   |   |   |   |   |
| Natural gas  ($/Mcf) sales price received    |       | $                 | 5.89       |       | $          | 4.51 |   | $ | 2.54 |   | $ | — |   | $ | 4.29 |   | $ | 2.55 |   |
| Natural gas  ($/Mcf) effects of energy swaps |       | $                 | —     |       | $          | (0.12 | ) | $ | 0.44 |   | $ | — |   | $ | (0.71 | ) | $ | 0.26 |   |
| Oil and liquids  ($/Bbl)                     |       | $                 | 25.12      |       | $          | 14.92 |   | $ | 15.61 |   | $ | — |   | $ | 23.42 |   | $ | 18.20 |   |
| Average  production (lifting) costs ($/Mcfe) |       | $                 | 2.26       |       | $          | 1.57 |   | $ | 1.24 |   | $ | — |   | $ | 1.22 |   | $ | 0.96 |   |

 

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(1)   Oil and liquidproduction is converted to natural gas equivalents (Mcfe) at a rate of onebarrel to six Mcf.

(2)   The average Mcfe/dis not meaningful for 2004 as the majority of our exploration and productionbusiness was discontinued in 2003.  Withthe sale of our San Juan properties in the first quarter of 2004, our onlyremaining production is from interests in three wells in Michigan.

 

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### *Productive Wells*

### * *

The followingtable sets forth information regarding the number of productive wells in whichwe held a working interest at December 31, 2004:

 
| ** **     | ** ** | **2004 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 |   | — |   | — |   |

 

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

(2)   A gross well is awell in which a working interest is owned.

(3)   One net well isdeemed to exist when the sum of fractional ownership working interests in grosswells equals one.  The number of netwells is the sum of the fractional working interest owned in gross wells.

 

*Drilling and Recompletion Activity*

 

The following tablesets forth our gross and net interest in exploration and developmental wellsdrilled and wells recompleted during the periods indicated.

 
| ** **                          | ** ** | **United States** | ** ** | **Canada** | ** ** |
|-------------------------------------|------------|-------------------|------------|------------|------------|
| ** **                          | ** ** | **2004**          | ** ** | **2003**   | ** ** | **2002** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|                                |       |              |       |       |       |   |   |   |   |   |   |   |   |
| Gross (1) (Net) (2) wells |       |              |       |       |       |   |   |   |   |   |   |   |   |
| Development                         |       |              |       |       |       |   |   |   |   |   |   |   |   |
| Natural gas                         |       | —            | (—    | )          | 10         | (4.2 | ) | 14 | (8.0 | ) | — | (— | ) | 21 | (16.7 | ) | 13 | (12.3 | ) |
| Oil                                 |       | —            | (—    | )          | —     | (— | ) | — | (— | ) | — | (— | ) | 2 | (1.5 | ) | 1 | (— | ) |
| Non-productive (3)                  |       | —            | (—    | )          | —     | (— | ) | — | (— | ) | — | (— | ) | 2 | (1.4 | ) | 3 | (2.5 | ) |
|                                |       |              |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Total                               |       | —            | (—    | )          | 10         | (4.2 | ) | 14 | (8.0 | ) | — | (— | ) | 25 | (19.6 | ) | 17 | (14.8 | ) |
|                                |       |              |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Exploratory                         |       |              |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Natural gas                         |       | —            | (—    | )          | —     | (— | ) | 2 | (0.3 | ) | — | (— | ) | 23 | (18.4 | ) | 13 | (10.6 | ) |
| Oil                                 |       | —            | (—    | )          | —     | (— | ) | — | (— | ) | — | (— | ) | 4 | (3.1 | ) | 2 | (2.0 | ) |
| Non-productive                      |       | —            | (—    | )          | 2          | (0.5 | ) | — | (— | ) | — | (— | ) | 6 | (4.4 | ) | 6 | (5.5 | ) |
|                                |       |              |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Total                               |       | —            | (—    | )          | 2          | (0.5 | ) | 2 | (0.3 | ) | — | (— | ) | 33 | (25.9 | ) | 21 | (18.1 | ) |
|                                |       |              |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Recompletion (4)                    |       |              |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Natural gas                         |       | —            | (—    | )          | 1          | (0.8 | ) | 5 | (2.5 | ) | — | (— | ) | 21 | (17.2 | ) | 12 | (11.0 | ) |
| Oil                                 |       | —            | (—    | )          | —     | (— | ) | — | (— | ) | — | (— | ) | — | (— | ) | — | (— | ) |
| Non-productive                      |       | —            | (—    | )          | —     | (— | ) | — | (— | ) | — | (— | ) | 2 | (1.6 | ) | 4 | (4.0 | ) |
|                                |       |              |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Total                               |       | —            | (—    | )          | 1          | (0.8 | ) | 5 | (2.5 | ) | — | (— | ) | 23 | (18.8 | ) | 16 | (15.0 | ) |
|                                |       |              |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Total gross (net) wells             |       | —            | (—    | )          | 13         | (5.5 | ) | 21 | (10.8 | ) | — | (— | ) | 81 | (64.3 | ) | 54 | (47.9 | ) |

 

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(1)   A gross well is a well in which a working interest is owned.

(2)   One net well is deemed to exist when the sum of the fractional ownershipworking interest in gross wells equals one producing well, in addition to theexisting producing horizon.  These aredually completed wells.

(3)   A non-productive well is a well deemed to be incapable of producing eithernatural gas or oil in sufficient quantities to justify completion as a naturalgas or oil well.

(4)   A recompletion well is a well which within an existing wellbore, adifferent geological horizon with proved reserves is completed as a

 

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producing well, in addition to the existing producinghorizon.  These are dually completedwells.

 

*Acreage*

 

The following tablesets forth the leasehold acreage held by MarkWest Hydrocarbon at December 31,2004.

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

 

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(1)   Developed acres are those acres that are spaced or assigned to productivewells.

(2)   Undeveloped acres are considered to be those acres on which wells have notbeen drilled or completed to a point that would permit the production ofcommercial quantities of oil and natural gas regardless of whether such acreagecontains proved reserves.  It should notbe confused with undrilled acreage held by production under the terms of alease.

(3)   On December 12, 2003, the Company assigned all of its remainingundeveloped acreage located in Michigan to M & M Exploration Partners,LLC.  After the second anniversary of theassignment, the Company has the right to receive re-assignment of any acreagenot committed to an exploration venture.

(4)   A gross acre is an acre in which a working interest is owned.  The number of gross acres is the total numberof acres in which a working interest is owned.

(5)   A net acre is deemed to exist when the sum of the fractional ownershipworking interests in gross acres equals one. The number of net acres is the sum of the fractional working interestsowned in gross acres.

 

**FactorsAffecting our Operations**

 

***Seasonality***

 

Asubstantial portion of our revenues and, as a result, our gross margin, remainsdependent upon the volume and sales price of NGL products, particularlypropane. The volume and sales price of NGL products fluctuate with the winterweather conditions and other changes in supply and demand. The strongest demandfor propane and the highest propane sales margins generally occur during the winterheating season.  As a result, werecognize a significant amount of our annual income from our marketing segmentduring the first and fourth quarters of the year.

 

***Competition***

 

*MarkWest Hydrocarbon*

 

MarkWest Hydrocarbon faces competition formarketing products and purchasing natural gas supplies. Competition forcustomers and purchases of natural gas are based primarily on price, deliverycapabilities, flexibility and maintenance of quality customerrelationships.  The Company’s competitorsare similar to those of MarkWest Energy (described below).

 

*MarkWest Energy*

 

The Partnership faces competition for naturalgas and crude oil transportation and in obtaining natural gas supplies for itsprocessing and related services operations, in obtaining unprocessed NGLs forfractionation, and in marketing our products and services. Competition fornatural gas supplies is based primarily on the location of gas gatheringfacilities and gas processing plants, operating efficiency and reliability andability to obtain a satisfactory price for products recovered. Competitivefactors affecting our fractionation services include availability of capacity,proximity to supply and to industry marketing centers and cost efficiency andreliability of service. Competition for customers is based primarily on price,delivery capabilities, flexibility and maintenance of quality customerrelationships.

 

Incompeting for new business opportunities, the Partnership faces strongcompetition in acquiring natural gas and crude oil supplies and in competingfor service fees. MarkWest Energy’s competitors include:

 

•              majorintegrated oil companies;

 

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•              mediumand large sized independent E&P companies;

 

•              majorinterstate and intrastate pipelines;

 

•              otherlarge natural gas gatherers that gather, process and market natural gas andNGLs; and

 

•              arelatively large number of smaller gas gatherers of varying financial resourcesand experience.

 

Many of the Partnership’s competitors operateas master limited partnerships and enjoy a cost of capital comparable, and insome cases lower, than the Partnerships. Other competitors, such as major oil and gas and pipeline companies,have capital resources and control supplies of natural gas substantially greaterthan MarkWest Energy Partners.  Smallerlocal distributors may enjoy a marketing advantage in their immediate serviceareas.

 

***OperationalRisks and Insurance***

 

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

 

We maintain generalpublic liability, property and business interruption insurance in amounts thatwe consider to be adequate for such risks. Such insurance is subject todeductibles that we consider reasonable and not excessive.  Consistent with insurance coverage generallyavailable to the industry, our insurance policies provide coverage for lossesor liabilities related to sudden occurrences of pollution or otherenvironmental damage.

 

The occurrence of asignificant event that we are not fully insured or indemnified against, and/orthe failure of a party to meet its indemnification obligations to us, couldmaterially and adversely affect our operations and financial condition.  Moreover, we cannot provide assurance that wewill be able to maintain adequate insurance in the future at rates we considerreasonable.  To date, however, we havenot experienced difficulty in acquiring insurance coverage in amounts webelieve to be adequate.

 

##### ***Title to Properties***

##### * *

Webelieve we have satisfactory title to all of our assets.   We also believe that the Partnership hassatisfactory title to all its assets.

 

Substantially all of MarkWest Energy’spipelines are constructed on rights-of-way granted by the apparent recordowners of the property.  Lands over whichpipeline rights-of-way have been obtained may be subject to prior liens that havenot been subordinated to the right-of-way grants. The Partnership has obtained,where necessary, easement agreements from public authorities and railroadcompanies to cross over or under, or to lay facilities in or along,watercourses, county roads, municipal streets, railroad properties and statehighways, as applicable.  Many of thesepermits are revocable at the election of the grantor.  In some cases, property on which the Partnership’spipelines were built was purchased in fee. The Partnership’s Siloamfractionation plant and Kenova processing plant is on land that the Partnershipowns in fee.

 

Some of the leases, easements, rights-of-way,permits, licenses and franchise ordinances that were transferred to thePartnership required the consent of the then-current landowner to transferthese rights, which in some instances was a governmental entity.  The Partnership believes that it has obtainedsufficient third-party consents, permits and authorizations for the transfer ofthe assets necessary for the Partnership to operate its business in allmaterial respects.

 

The Partnership’s general partner believesthat it has satisfactory title to all of its assets.  To the extent certain defects in title to theassets contributed to the Partnership or failures to obtain certain consentsand permits necessary to conduct its business arise within three years afterthe closing of the Partnership’s initial public offering, MarkWest

 

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Energy is entitledto indemnification from MarkWest Hydrocarbon under the Omnibus Agreement.  Title to property may be subject toencumbrances.  The Partnership’s generalpartner does not believe that any of these encumbrances materially detract fromthe value of its properties or from the Partnership’s interest in theseproperties or should materially interfere with their use in the operation ofthe Partnership’s business.

 

The Partnership has pledged substantially allof its assets to secure the debt of the Partnership’s subsidiary MarkWestEnergy Operating Company, L.L.C. (the “Operating Company”) as discussed in Note9 of the accompanying Notes to Consolidated and Combined Financial Statementsincluded in Item 8 of this Form 10-K.

 

We have pledged substantially all of ourassets to secure borrowings under our credit facility as discussed in Note 9 ofthe accompanying Notes to Consolidated and Combined Financial Statementsincluded in Item 8 of this Form 10-K.

 

***Regulatory Matters***

 

Theactivities of MarkWest Hydrocarbon and MarkWest Energy are subject to variousstate 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 the Partnership’s gas, liquids andcrude oil gathering and transmission operations are subject to regulation byvarious regulatory bodies.  In manycases, various phases of the Partnership’s gas, liquids and crude oiloperations in the states in which it operates are subject to rate and serviceregulation. Applicable statutes generally require that the Partnership’s ratesand terms and conditions of service provide no more than a fair return on theaggregate value of the facilities used to render services.

 

The Partnership’s Appalachian pipelinecarries NGLs across state lines. The primary shipper on the pipeline isMarkWest Hydrocarbon, who has entered into agreements with the Partnershipproviding 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 thePartnership does not operate the Appalachian pipeline as a common carrier anddoes not hold the pipeline out for service to the public generally, there arecurrently no third-party shippers on this pipeline and the pipeline is and willcontinue to be operated as a proprietary facility and consequently should notbe subject to regulation by the Federal Energy Regulatory Commission, (“FERC”).  However, we cannot provide assurance thatFERC would not determine that such transportation is within itsjurisdiction.  In such a case, MarkWestEnergy would be required to file a tariff for such transportation with FERC andprovide a cost justification for the transportation charge.  MarkWest Hydrocarbon has agreed to notchallenge the status of the Partnership’s Appalachian pipeline or thetransportation charge during the term of its agreements with MarkWestHydrocarbon.  Moreover, the likelihood ofother entities seeking to utilize the Partnership’s Appalachian pipeline isremote.  However, the Partnership cannotpredict whether an assertion of FERC jurisdiction might be made with respect tothis pipeline, nor provide assurance that such an assertion would not adverselyaffect its results of operations.  Withrespect to the Michigan Crude Pipeline, one shipper recently contacted FERC toinquire about a transportation rate increase and the pipeline’s regulatory ratestructure.  In response, FERC requestedthat the Partnership contact the shipper to initiate a discussion regarding theshipper’s questions.  The Partnership ispresently in discussions with all shippers regarding rate structures and isattempting to resolve any issues they may have. FERC also requested that the Partnership file a tariff.  While the Michigan Crude Pipeline operationsare entirely within the state of Michigan and have been regulated by the Stateof Michigan, the Partnership has calculated and determined that its current andproposed rate structures are well below rates that would be allowed under FERC’scost of service rate-making structure. However, the Partnership cannot predict whether a FERC jurisdictionalassertion might be made with respect to the Michigan Crude Pipeline, norprovide assurance that such a development would not adversely affect theCompany’s results of operations.

 

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

 

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*Safety Regulation.*  The Partnership’s pipelines are subject toregulation by the U.S. Department of Transportation under the Hazardous LiquidPipeline Safety Act (“HLPSA”), as amended relating to the design, installation,testing, construction, operation, replacement and management of pipelinefacilities. The HLPSA covers crude oil, carbon dioxide, NGL and petroleumproducts pipelines and requires any entity which owns or operates pipelinefacilities to comply with the regulations under the HLPSA, to permit access toand allow copying of records and to make certain reports available and provideinformation as required by the Secretary of Transportation. The Partnershipbelieves that its pipeline operations are in substantial compliance withapplicable HLPSA requirements; however, due to the possibility of new oramended laws and regulations or reinterpretation of existing laws andregulations, there can be no assurance that future compliance effortsassociated with the HLPSA will not have a material adverse effect on theCompany’s results of operations or financial position.

 

The Pipeline Safety Improvement Act of 2002includes numerous provisions that tighten federal specifications and safetyrequirements for natural gas and hazardous liquids pipeline facilities. Many ofthe statute’s provisions build on existing statutory requirements andstrengthen regulations of the Research and Special Programs Administration andthe OPS, in particular, with respect to operator qualifications programs,natural mapping system and safe excavation practices. Management of thePartnership believes that compliance efforts associated with the PipelineSafety Improvement Act of 2002 will not have a material effect on MarkWestHydrocarbon’s operations.

 

On November 8, 2004, a leak and releaseof vapors occurred in a pipeline transporting NGLs from the Maytown gasprocessing plant to the Partnership’s Siloam fractionator.  This pipeline is owned by a third party, andleased and operated by the Partnership’s subsidiary, MarkWest EnergyAppalachia, LLC.  A subsequent ignitionand fire from the leaked vapors resulted in property damage to five homes andinjuries to some of the residents.  Theexact cause of the leak and resulting fire is unknown and is being investigatedby the OPS, the owner and the Partnership. Pursuant to a Corrective Action Order issued by the OPS on November 18,2004 and amended November 24, 2004, pipeline and valve integrity evaluation,testing and repair efforts are required and are being conducted on the affectedpipeline segment before service can be resumed. Both the Partnership and the pipeline owner are working with OPS toassure compliance with the Order.

 

***EnvironmentalMatters***

 

***MarkWest Hydrocarbon***

 

We are subject to environmental risksnormally incident to our operations and construction activities including, butnot limited to, uncontrollable flows of natural gas, fluids and othersubstances into the environment, explosions, fires, pollution and otherenvironmental and safety risks.  Ourbusiness is subject to comprehensive state and federal environmentalregulations.  For example, we, withoutregard to fault, could incur liability under the Comprehensive EnvironmentalResponse, Compensation, and Liability Act of 1980, as amended (also known asSuperfund), or state counterparts, in connection with the disposal or otherreleases of hazardous substances, including sour gas, and for natural resourcedamages.  Further, the recent trend inenvironmental legislation and regulations is toward stricter standards, andthis will likely continue in the future.

 

Our activities aresubject to environmental and safety regulation by federal and stateauthorities, including, without limitation, the state environmental agenciesand the federal Environmental Protection Agency, which can increase the costsof designing, installing and operating our facilities. In most instances, theregulatory requirements relate to the discharge of substances into theenvironment and include measures to control water and air pollution.

 

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

 

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***MarkWest Energy***

 

*General.* The Partnership’s processing and fractionation plants, pipelines andassociated facilities in connection with the gathering and processing ofnatural gas, the transportation, fractionation and storage of NGLs and thestorage and gathering and transportation of crude oil are subject to multipleenvironmental obligations and potential liabilities under a variety of federal,state and local laws and regulations, including without limitation, theComprehensive Environmental Response, Compensation, and Liability Act, theResource Conservation and Recovery Act, the Clean Air Act, the Federal WaterPollution Control Act or the Clean Water Act, the Oil Pollution Act, andanalogous state and local laws and regulations. Such laws and regulations affect many aspects of the Partnership’spresent and future operations and generally require the Partnership to obtainand comply with a wide variety of environmental registrations, licenses,permits, inspections and other approvals, with respect to air emissions, waterquality, wastewater discharges, solid and hazardous waste management.  Failure to comply with these laws,regulations, permits and licenses may expose the Partnership to fines,penalties and/or interruptions in its operations that could be material to theCompany’s results of operations.  If anaccidental leak, spill or release of hazardous substances occurs from thePartnership’s lines or facilities, in the process of transporting natural gas,or at any facilities that the Partnership owns, operates or otherwise uses, orwhere the Partnership sends materials for treatment or disposal, MarkWestEnergy could be held jointly and severally liable for all resultingliabilities, including investigation, remedial and clean up costs.  Likewise, the Partnership could be requiredto remove or remediate previously disposed wastes or property contamination,including groundwater contamination or to perform remedial operations toprevent future contamination for properties owned, leased or acquired by thePartnership which may have been previously operated by third parties and whomay have released or disposed of hazardous substances or wastes, all of whichcould materially affect the our results of operations and cash flows.

 

Nevertheless, we believe that the Partnership’soperations and facilities are in substantial compliance with applicableenvironmental laws and regulations and that the cost of compliance with suchlaws and regulations will not have a material adverse effect on the our resultsof operations or financial condition. However, we cannot ensure that existing environmental regulations willnot be revised or that new regulations will not be adopted or become applicableto the Partnership.  The clear trend inenvironmental regulation is to place more restrictions and limitations onactivities that may be perceived to affect the environment, and thus there canbe no assurance as to the amount or timing of future expenditures forenvironmental regulation compliance or remediation, and actual futureexpenditures may be different from the amounts the Partnership currentlyanticipates.  Revised or additionalregulations that result in increased compliance costs or additional operatingrestrictions, particularly if those costs are not fully recoverable from thePartnership’s customers, could have a material adverse effect on its business,financial condition, results of operations and cash flow.

 

*Ongoing Remediation and Indemnification from a Third Party.*  The previous owner/operator of thePartnership’s Boldman and Cobb facilities has been or is currently involved ininvestigatory or remedial activities with respect to the real propertyunderlying these facilities pursuant to an “Administrative Order by Consent forRemoval Actions” with EPA Regions II, III, IV, and V in September 1994and an “Agreed Order” entered into with the Kentucky Natural Resources andEnvironmental Protection Cabinet in October 1994.  The previous owner/operator has agreed toretain sole liability and responsibility for, and indemnify MarkWestHydrocarbon against, any environmental liabilities associated with the EPAAdministrative Order, the Kentucky Agreed Order or any other environmentalcondition related to the real property prior to the effective dates of MarkWestHydrocarbon’s agreements pursuant to which MarkWest Hydrocarbon leased or purchasedthe real property.  In addition, theprevious owner/operator has agreed to perform all the required response actionsat its cost and expense in a manner that minimizes interference with MarkWestHydrocarbon’s use of the properties.  On May 24,2002, MarkWest Hydrocarbon assigned to the Partnership the benefit of thisindemnity from the previous owner/operator. To date, the previous owner/operator has been performing all actionsrequired under these agreements, and, accordingly, we do not believe that theremediation obligation of these properties will have a material adverse impacton our financial condition or results of operations.

 

*Notice of Violation and Corrective Action Order.*  On April 14, 2005, the West VirginiaDepartment of Environmental Protection (“WVDEP”) issued a Notice of Violationand Cease and Desist Order (“NOV”) to MarkWest Hydrocarbon alleging variousmonitoring, recordkeeping and reporting violations of the Cobb Processing

 

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Plant’s Clean Air Act permit.  MarkWest Energy has filed written responsesto the NOV with the WVDEP and is in the process of negotiating a resolution ofthe alleged violations.  We do notbelieve that the resolution of these allegations will have a material adverseimpact on our financial condition or results of operations.

 

***EmployeeSafety***

 

The workplaces associated with the processingand storage facilities and the pipelines we operate are also subject to therequirements of the federal Occupational Safety and Health Act, (“OSHA”), andcomparable state statutes that regulate the protection of the health and safetyof workers.  In addition, the OSHA hazardcommunication standard requires that information be maintained about hazardousmaterials used or produced in operations and that this information be providedto employees, state and local government authorities, and citizens. We believethat we have conducted our operations in substantial compliance with OSHArequirements, including general industry standards, record keeping requirementsand monitoring of occupational exposure to regulated substances.

 

In general, we expect industry and regulatorysafety standards to become stricter over time, thereby resulting in increasedcompliance expenditures. While these expenditures cannot be accuratelyestimated at this time, we do not expect such expenditures will have a materialadverse effect on our results of operations.

 

***Employees***

 

As of December 31, 2004, we had 166employees who operate our facilities and provide general and administrativeservices.  The Paper, Allied Industrial,Chemical and Energy Workers International Union Local 5-372 represents 15employees at the Partnership’s Siloam fractionation facility in South Shore,Kentucky.  The collective bargaining agreementwith this Union expired on June 28, 2004 and a new agreement was signed onAugust 12, 2005. The agreement covers only hourly, non-supervisoryemployees. We consider labor relations to be satisfactory at this time.

 

***AvailableInformation***

 

You can find more information about us at ourInternet 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-Kand any amendments to those reports are available free of charge through ourinternet website as soon as is reasonably practicable after we electronicallyfile such material with the SEC.

 

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

 

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**ITEM 3.  LEGAL PROCEEDINGS**

 

MarkWest Hydrocarbon,in the ordinary course of business, is a defendant in various lawsuits and aparty to various other legal proceedings, some of which are covered in whole orin part by insurance.  In the opinion ofmanagement, none of these actions, either individually or in the aggregate,will have a material adverse effect on our financial condition, liquidity orresults of operations.

 

TheCompany, the Partnership and several of its affiliates were served in early2005 with two lawsuits captioned as follows:

 

RickyJ. Conn, *et al*. v. MarkWestHydrocarbon, Inc. *et al*.,(Floyd Circuit Court, Commonwealth of Kentucky, Civil Action No. 05-CI-00137),filed February 2, 2005, as Removed to the U.S. District Court for theEastern District of Kentucky, Pikeville Division, Civil Action No. 7: 5-CV-67-DLB,on February 24, 2005.

 

CharlesC. Reid, *et al.* v. MarkWestHydrocarbon, Inc. *et al.*,(Floyd Circuit Court, Commonwealth of Kentucky, Civil Action No. 05-CI-00156),filed February 8, 2005.

 

These actions assert claims for recovery forproperty and personal injury damages sustained as a result of a pipelinefailure and ensuing explosion and fire occurring November 8, 2004 in a NGLpipeline owned by a third party, and leased and operated by the Partnership’ssubsidiary, MarkWest Energy Appalachia, LLC. The pipeline transported NGLs from the Maytown gas processing plant tothe Partnership’s Siloam fractionator.  Asubsequent ignition and fire from the leaked vapors resulted in property damageto five homes and injuries to some of the residents.  The cause of the pipeline failure, andresulting explosion and fire, is being investigated by the pipeline owner, theU.S. Department of Transportation, Office of Pipeline Safety and the Company.

 

While investigation into the incident anddefense of the action continues, settlement has been reached with respect toseveral of the plaintiffs and claims, and at this time the Company believesthat it has adequate insurance coverage for third-party property damage andpersonal injury liability resulting from the incident. The deductible for theinsurance is $0.3 million, which has been accrued as a charge to operations in2004.

 

The Company has also been involved in alawsuit captioned Ross Bros. Construction v. MarkWest Hydrocarbon, Inc.,(U.S. District Court Eastern District of Kentucky, Ashland Division, Civ.Action No. 01-CV-205).  This lawsuitinvolved the construction of the Siloam Kentucky plant and a dispute as to themonetary value of additional work beyond the contract’s lump sum priceperformed by the contractor.  Thislawsuit involved a claim of approximately $700,000 in additional costs.  The Company was recently granted SummaryJudgment on its defense asserting accord and satisfaction.  Plaintiffs have filed an appeal of theSummary Judgment to the U.S. Court of Appeals for the 6th Circuit.

 

The Company along with several other defendantsare defending a lawsuit captioned Merrimans v. Atlas Gas Company, et al.,(Columbia County Court of Common Pleas, Ohio, case number 2003 CV 0202).  This case involves a claim that propane ormethane gas escaped into the basement of a residence and ignited causinginjuries to the plaintiff.  The claimagainst the Company concerns proper oderization of propane product whichplaintiff had used.  The Company deniesplaintiff’s claims and among other defenses, the Company also asserts that theresidential supplier had responsibility for proper oderization, and has filed across-claim for indemnity against such party, together with a third partycomplaint against such party’s insurer. Discovery is continuing and settlement discussions are beingpursued.  A trail date has beenrescheduled several times but has been vacated and a trial date is presentlyunscheduled.  The Company is activelydefending the action, and believes that it has valid defenses to plaintiff’sclaims, and a valid cross-claim for indemnity against the residential supplier,and a bad faith claim against the insurer. The court recently granted Summary Judgment in favor of the Companyregarding its cross-claim for indemnification. However, the Company is unable to determine at this time, whether itwill ultimately be successful in its defenses with regard to the plaintiffs,its remaining bad faith claim, or any appeals of the Summary Judgmentcross-claims in the action. Notwithstanding, at this time, the Company believes that it has adequateinsurance coverage for any liability resulting from the incident.

 

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**ITEM4.  SUBMISSION OF MATTERS TO A VOTE OFSECURITY HOLDERS**

 

There were no matters submitted to a vote of securityholders during the fourth quarter of the year ended December 31, 2004.

 

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PART II

 

## **ITEM5.  MARKET FOR THE REGISTRANT’S COMMONEQUITY AND RELATED STOCKHOLDER MATTERS**

## ** **

Our common stock tradeson the American Stock Exchange (“AMEX”) national market under the symbol “MWP”.  As of September 9, 2005, there were10,794,729 shares of common stock outstanding held by approximately 40 holdersof record. The following table sets forth quarterly high and low sales pricesas reported by the American Stock Exchange, as retroactively restated to giveeffect to the 2004 and 2003 stock dividends (see below), for the periodsindicated, as well as the amount of cash dividends paid per share per quarterfor 2004 and 2003.

 
| **Quarter Ended**       | ** ** | **High** | ** ** | **Low** | ** ** | **Dividend** | ** ** | **Record Date** | ** ** | **Payment Date** | ** **             |
|-------------------------|------------|----------|------------|---------|------------|--------------|------------|-----------------|------------|------------------|------------------------|
|                    |       |     |       |    |       |         |       |            |       |             |                   |
| December 31, 2004  |       | $        | 18.18      |    | $          | 13.86        |       | $               | 0.068      |             | February 9, 2005  |   | February 21, 2005 |   |
| September 30, 2004 |       | $        | 13.92      |    | $          | 10.45        |       | $               | 0.045      |             | November 24, 2004 |   | December 6, 2004 |   |
| June 30, 2004      |       | $        | 12.00      |    | $          | 9.10         |       | $               | 0.023      |             | August 5, 2004    |   | August 19, 2004 |   |
| March 31, 2004     |       | $        | 11.70      |    | $          | 9.20         |       | $               | 0.023      |             | May 5, 2004       |   | May 19, 2004 |   |
|                    |       |     |       |    |       |         |       |            |       |             |                   |
| December 31, 2003  |       | $        | 11.94      |    | $          | 6.68         |       | $               | —     |             |                   |   |   |   |
| September 30, 2003 |       | $        | 6.82       |    | $          | 6.18         |       | $               | —     |             |                   |   |   |   |
| June 30, 2003      |       | $        | 6.76       |    | $          | 5.00         |       | $               | —     |             |                   |   |   |   |
| March 31, 2003     |       | $        | 5.17       |    | $          | 4.47         |       | $               | —     |             |                   |   |   |   |

 

**Dividend Policy**

 

The Company does nothave a formal dividend policy. However, the Company’s objective is to maintaina regular quarterly dividend.  Payment ofdividends in the future will depend on our earnings, financial condition andcontractual restrictions, including those under our bank line of credit orimposed by law and other factors deemed relevant by our Board of Directors.

 

**StockDividends**

 

On October 28,2004, the Board of Directors declared a stock dividend of one share for eachten shares owned by stockholders of record as of the close of business on November 9,2004.  The stock dividend was paid on November 19,2004, with an ex-dividend date of November 5, 2004.

 

On July 10, 2003,the Board of Directors declared a stock dividend of one share for each tenshares 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.

 

29

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## **ITEM 6.  SELECTED FINANCIAL DATA**

## ** **

The following table setsforth selected consolidated historical financial and operating data forMarkWest Hydrocarbon.  Certain prior yearamounts have been reclassified to conform to the 2004 presentation. Theselected consolidated statement of operations and balance sheet data for theyears ended December 31, 2004, 2003 and 2002, and as of December 31,2004 and 2003, are derived from, and are qualified by reference to, our auditedConsolidated Financial Statements included elsewhere in this Form 10-K.  The selected consolidated statement ofoperations and balance sheet data set forth below for the years ended December 31,2001 and 2000, and as of December 31, 2002, 2001 and 2000, have beenderived from audited financial statements not included in this Form 10-K. Youshould read this in conjunction with *Management’sDiscussion and Analysis of Financial Condition and Results of Operations*and our Consolidated Financial Statements and accompanying Notes includedelsewhere in this Form 10-K.

 

OnApril 11, 2005, management, after discussion with the Audit Committee ofour Board of Directors, determined that previously issued financial statementsfor the years ended December 31, 2002 and 2003 and for each of the firstthree quarters of 2003 and 2004 should be restated to reflect compensationexpense attributable to the sale of subordinated Partnership units andinterests in the Partnership’s general partner to certain employees anddirectors of MarkWest Hydrocarbon that occurred during 2002, 2003 and 2004.  These transactions were previously reflectedas sales of assets.  In addition,an adjustment of $2.5 million was also made to restate restricted marketablesecurities from restricted cash. Finally, the Company adjusted the income tax provision (benefit) for therestatement adjustments.

 

The Company has alsorestated revenue for 2003 by $0.1 million to record natural gas inventory atcost.  Previously the inventory wasincorrectly identified as a pipeline imbalance and was recorded at marketvalue.

 

Refer to Note 23, *Restatement of Consolidated Financial Statements*,to the consolidated financial statements in Item 8 of this Form 10-K forfurther information regarding the restatement of our previously issuedfinancial statements.

 

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| ** **                                             | ** ** | **Year Ended December 31,**                                | ** ** |
|--------------------------------------------------------|------------|-----------------------------------------------------------------|------------|
| ** **                                             | ** ** | **2004**                                                        | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** | **2000** | ** ** |
| ** **                                             | ** ** | **(in thousands, except per share amounts and operating data)** | ** ** |
| ** **                                             | ** ** | ** **                                                      | ** ** | **(as restated)(1)** | ** ** | **(as restated)(1)** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Statement  of Operations Data:**                     |       |                                                            |       |   |   |   |   |   |   |   |   |
| Revenue                                                |       | $                                                               | 460,113    |   | $ | 209,268 |   | $ | 155,787 |   | $ | 173,890 |   | $ | 217,567 |   |
| Income (loss)  from continuing operations              |       | $                                                               | (903       | ) | $ | (22,420 | ) | $ | (4,775 | ) | $ | 315 |   | $ | 8,493 |   |
| Net income  (loss)                                     |       | $                                                               | (903       | ) | $ | (11,006 | ) | $ | (3,009 | ) | $ | 2,810 |   | $ | 8,878 |   |
| Earnings (loss)  from continuing operations per share: |       |                                                            |       |   |   |   |   |   |   |   |   |
| Basic                                                  |       | $                                                               | (0.08      | ) | $ | (2.17 | ) | $ | (0.46 | ) | $ | 0.03 |   | $ | 0.83 |   |
| Diluted                                                |       | $                                                               | (0.08      | ) | $ | (2.17 | ) | $ | (0.46 | ) | $ | 0.03 |   | $ | 0.83 |   |
| Earnings (loss)  per share:                            |       |                                                            |       |   |   |   |   |   |   |   |   |
| Basic                                                  |       | $                                                               | (0.08      | ) | $ | (1.07 | ) | $ | (0.29 | ) | $ | 0.27 |   | $ | 0.87 |   |
| Diluted                                                |       | $                                                               | (0.08      | ) | $ | (1.07 | ) | $ | (0.29 | ) | $ | 0.27 |   | $ | 0.86 |   |
| Weighted average  shares outstanding:                  |       |                                                            |       |   |   |   |   |   |   |   |   |
| Basic                                                  |       | 10,686                                                          |       | 10,328 |   | 10,285 |   | 10,259 |   | 10,227 |   |
| Diluted                                                |       | 10,740                                                          |       | 10,347 |   | 10,301 |   | 10,284 |   | 10,275 |   |
|                                                   |       |                                                            |       |   |   |   |   |   |   |   |   |
| **Balance  Sheet Data (as of December 31):**      |       |                                                            |       |   |   |   |   |   |   |   |   |
| Total assets                                           |       | $                                                               | 593,574    |   | $ | 280,495 |   | $ | 257,503 |   | $ | 250,511 |   | $ | 147,287 |   |
| Long-term debt                                         |       | $                                                               | 225,000    |   | $ | 126,200 |   | $ | 64,223 |   | $ | 104,850 |   | $ | 43,000 |   |
| Stockholders’  equity                             |       | $                                                               | 49,761     |   | $ | 50,914 |   | $ | 53,139 |   | $ | 69,033 |   | $ | 61,594 |   |

 

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(1)  See note 23 inNotes to Consolidated Financial Statements.

 

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***Operating Data***

 
| ** **                                          | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------|------------|----------------------------------|------------|
| ** **                                          | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** | **2000** | ** ** |
|                                                |       |                             |       |   |   |   |   |   |   |   |   |
| ** Operating  Data:**                          |       |                             |       |   |   |   |   |   |   |   |   |
| **Marketing:**                                      |       |                             |       |   |   |   |   |   |   |   |   |
| NGL product  sales (gallons) (1)                    |       | 178,000,000                      |       | 177,000,000 |   | 183,000,000 |   | 152,200,000 |   | 153,000,000 |   |
|                                                |       |                             |       |   |   |   |   |   |   |   |   |
| **Wholesale:**                                      |       |                             |       |   |   |   |   |   |   |   |   |
| NGL product  sales (gallons) (2)                    |       | 42,154,000                       |       | NA |   | NA |   | NA |   | NA |   |
|                                                |       |                             |       |   |   |   |   |   |   |   |   |
| **MarkWest  Energy:**                               |       |                             |       |   |   |   |   |   |   |   |   |
| ***Southwest:***                                    |       |                             |       |   |   |   |   |   |   |   |   |
| *East  Texas (3)*                                   |       |                             |       |   |   |   |   |   |   |   |   |
| Gathering  systems throughput (Mcf/d)               |       | 259,300                          |       | NA |   | NA |   | NA |   | NA |   |
| NGL product  sales (gallons)                        |       | 41,478,000                       |       | NA |   | NA |   | NA |   | NA |   |
|                                                |       |                             |       |   |   |   |   |   |   |   |   |
| *Oklahoma*                                          |       |                             |       |   |   |   |   |   |   |   |   |
| Foss Lake  gathering systems throughput (Mcf/d) (4) |       | 60,900                           |       | 57,000 |   | NA |   | NA |   | NA |   |
| Arapaho NGL  product sales (gallons) (5)            |       | 45,273,000                       |       | 2,910,000 |   | NA |   | NA |   | NA |   |
|                                                |       |                             |       |   |   |   |   |   |   |   |   |
| *Other*                                             |       |                             |       |   |   |   |   |   |   |   |   |
| Appleby  gathering systems throughput (Mcf/d) (6)   |       | 27,100                           |       | 23,800 |   | NA |   | NA |   | NA |   |
| Other gathering  systems throughput (Mcf/d) (6)     |       | 17,000                           |       | 20,500 |   | NA |   | NA |   | NA |   |
| Lateral  throughput volumes (Mcf/d) (7)             |       | 75,500                           |       | 32,100 |   | NA |   | NA |   | NA |   |
|                                                |       |                             |       |   |   |   |   |   |   |   |   |
| ***Appalachia:***                                   |       |                             |       |   |   |   |   |   |   |   |   |
| Natural gas  processed for a fee (Mcf/d) (8)        |       | 203,000                          |       | 202,0000 |   | 202,000 |   | 192,000 |   | 196,000 |   |
| NGLs  fractionated for a fee (Gal/day)              |       | 475,000                          |       | 458,0000 |   | 476,000 |   | 423,000 |   | 406,000 |   |
| NGL product  sales (gallons)                        |       | 42,105,000                       |       | 40,305,0000 |   | 38,813,000 |   | — |   | — |   |
|                                                |       |                             |       |   |   |   |   |   |   |   |   |
| ***Michigan:***                                     |       |                             |       |   |   |   |   |   |   |   |   |
| Natural gas  processed for a fee (Mcf/d)            |       | 12,300                           |       | 15,0000 |   | 13,800 |   | 8,800 |   | 11,000 |   |
| NGL product  sales (gallons)                        |       | 9,818,000                        |       | 11,800,000 |   | 11,100,000 |   | 8,000,000 |   | 9,200,000 |   |
| Crude oil  transported for a fee (Bbl/d) (9)        |       | 14,700                           |       | 15,100 |   | — |   | — |   | — |   |

 

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(1)   Represents sales at the Siloam fractionator.

(2)   Represents sales from our wholesalebusiness.  Volumes are from the periodsince the Company started the line of business in February 2004.

(3)   The Partnership acquired its East Texas System inlate July 2004.  Volumes are for theperiod of time the Partnership owned the facility during 2004.

(4)   The Partnership acquired its Foss Lake gatheringsystem in December 2003.

(5)   The Partnership acquired its Arapaho processingplant in December 2003.

(6)   The Partnership acquired its Pinnacle gatheringsystems in late March 2003.

(7)   The Partnership acquired its Lubbock pipeline(a/k/a the Power-tex Lateral Pipeline) in September 2003 and its Hobbslateral pipeline in April 2004.  TheLubbock and Hobbs pipelines are the only laterals the Partnership owns thatproduce revenue on a per-unit-of-throughput basis.  The Partnership receives a flat fee from itsother lateral pipelines and, consequently, the throughput data from theselateral pipelines are excluded from this statistic.

(8)   Includes throughput from the Partnership’sKenova, Cobb and Boldman processing plants.

(9)   The Partnership acquired its Michigan CrudePipeline in December 2003.

 

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**ITEM 7.****                             MANAGEMENT’SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

 

Thefollowing discussion and analysis relates to factors that have affected ourconsolidated financial condition and results of operations for the three yearsended December 31, 2004, 2003 and 2002. In conjunction with the followingdiscussion and analysis, you should also read our Consolidated FinancialStatements and related Notes thereto and the *SelectedFinancial Data* included elsewhere in this Form 10-K.

 

**RecentDevelopments**

 

Duringthe year ended December 31, 2003, we discontinued our exploration andproduction business.  Through a series ofdispositions, we sold off substantially all of our U.S. and Canadian oil andgas properties.   For the years ended December 31,2003 and 2002, revenues from our discontinued operations were $30.1 million and$31.5 million, respectively, and income (loss) from discontinued operationsbefore income taxes was $2.1 million and $2.9 million, respectively.

 

The dispositions wereas follows:

 

*Salesof San Juan Basin Properties*

 

During the second andthird quarters of 2003, we completed the sale of our San Juan Basin (U.S.) oiland gas properties for net proceeds aggregating approximately $55.3 million. Werecognized an aggregate net pretax gain of $23.3 million on these sales for theyear ended December 31, 2003.  Theproceeds from the sales were used for working capital and general corporatepurposes.

 

*Salesof Canadian Properties*

 

During December 2003,we completed the sales of all of our Canadian oil and gas properties for netproceeds aggregating approximately $49.1 million. We recognized an aggregatepretax loss of $4.8 million on these sales for the year ended December 31,2003. The proceeds from the sales were primarily used to pay off our remainingoutstanding debt, exclusive of MarkWest Energy’s debt.

 

*Saleof Eastern Michigan Properties*

 

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

 

Prior to the fourthquarter of 2002, we classified our operations into two reportable segments -exploration and production and gathering, processing and marketing. With theformation and initial public offering of MarkWest Energy (the initial publicoffering closed on May 24, 2002), the subsequent change to the structureof our internal organization and discontinuance of our exploration andproduction business in 2003, the composition of our reportable segmentschanged.  Currently, our operations areclassified into two reportable segments, - Managing MarkWest Energy andMarketing.

 

During the year ended December 31,2004, we also continued to transform MarkWest Hydrocarbon into a companyfocused on growing MarkWest Energy. During 2004 and 2003, MarkWest Energycompleted a number of acquisitions of midstream assets.

 

### ***MarkWestEnergy Acquisitions***

### * *

*EastTexas System Acquisition. *InJuly 2004, the Partnership acquired natural gas gathering and processingassets located in east Texas for $240.7 million.  The assets consisted of approximately 210miles of natural gas gathering system pipelines, natural gas gathering systempipelines currently under construction, 15 centralized compressor stationsrepresenting 74,000 horsepower of compression and a natural gas processingfacility, also currently under construction.

 

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*Hobbs Lateral Pipeline Acquisition. *In April 2004, thePartnership acquired a lateral pipeline in Hobbs, New Mexico for approximately$2.3 million. The Hobbs lateral consists of a four-mile segment of 10-inch and12-inch natural gas pipeline connecting the Northern Natural Gas interstatepipeline to Southwestern Public Service’s Cunningham and Maddox powergenerating stations in Hobbs, New Mexico. The Hobbs lateral was recently expanded to a capacity of approximately170 MMcf/d and throughput was approximately 42 MMcf/d for the nine months endedDecember 31, 2004 (since its acquisition).

 

*MichiganCrude Pipeline Acquisition.*OnDecember 18, 2003, the Partnership completed the acquisition ofapproximately 250 miles of intrastate crude oil gathering pipeline, for $21.3million in cash. The pipeline serves over 1,000 oil and gas wells on theNiagaran Reef Trend and has 487,000 barrels of storage capacity in 15 storagetanks. This acquisition further diversifies the Partnership’s lines of businesswith the addition of crude oil gathering and transportation services. Theacquisition also provides the Partnership with the opportunity to leverage offits existing infrastructure and personnel in Michigan while adding additionalfee-based cash flows.

 

*WesternOklahoma Acquisition. *OnDecember 1, 2003, MarkWest Energy completed the acquisition ofsubstantially all of the assets of American Central Western Oklahoma GasCompany, LLC for approximately $38.0 million in cash. These assets include 167miles of natural gas gathering pipeline, known as the Foss Lake gatheringsystem, and the associated Arapaho gas processing plant in western Oklahoma.The Foss Lake gathering system, which, as of December 31, 2004, had acapacity of 65.0 MMcf/d, connects to approximately 270 wells. The Arapaho gasprocessing plant, as of December 31, 2004, had a capacity of 75.0 MMcf/d.By establishing a presence in Oklahoma, this acquisition significantly expandedthe Partnership’s Southwest operations.

 

*Lubbock Pipeline Acquisition.*EffectiveSeptember 2, 2003, MarkWest Energy completed the acquisition of anintrastate gas transmission pipeline and related assets near Lubbock, Texas,from Power-Tex Joint Venture, a subsidiary of ConocoPhillips, for $12.2 millionin cash. This gas pipeline is the only connection between the Northern NaturalGas and El Paso interstate pipelines and the City of Lubbock.  This acquisition allowed the Partnership tofurther expand its operations in the Southwest with an additional lateralsystem while providing an added source of fee-based cash flows.

 

*Pinnacle Merger.*OnMarch 28, 2003, the Partnership completed the acquisition of PinnacleNatural Gas Company, or Pinnacle. The aggregate purchase price of $39.9 millionwas comprised of $23.4 million in cash plus the assumption of $16.6 million ofbank indebtedness. The assets are primarily located in Texas and include threelateral natural gas pipelines and twenty natural gas gathering systems. One ofthe gathering systems was subsequently disposed of in December 2003 for aninsignificant amount and two of which have been subsequently sold in 2004 forproceeds of approximately $0.1 million. The three lateral natural gas pipelinesconsist of approximately 67 miles of pipeline that deliver natural gas underfirm contracts to power plants. This acquisition provided MarkWest Energy witha new area for growth in the Southwest and diversified its lines of businessand revenues.

 

**Initial and Subsequent EquityOfferings of MarkWest Energy Partners**

 

*Initial Public Offering*

 

## **On May 24, 2002, MarkWest Hydrocarbon contributed most of theassets, liabilities and operations of its midstream business to the Partnershipin exchange for 3,000,000 subordinated units, a 2% general partner interest inthe Partnership, incentive distribution rights (as defined in the PartnershipAgreement), and $63.5 million in cash (which was used to pay down bankdebt).  The Partnership closed itsinitial public offering on that date selling 2,415,000 common units (includingthe underwriters’ exercise of their over-allotment option) for gross proceedsof $49.0 million and net proceeds (after fees and expenses) of $43.0million.  Concurrent with its initialpublic offering the Partnership borrowed $21.4 million. MarkWest Energy’slimited partnership structure is designed to reduce its cost of capital therebyenhancing its ability to grow more efficiently.**

 

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*Secondary Offering – January 12,2004*

 

On January 12, 2004, the Partnershipcompleted a secondary offering of 1,100,444 common units, at $39.90 per unitfor gross proceeds of $43.9 million.  Inaddition, of the 172,200 common units available to underwriters to coverover-allotments, 72,500 were sold for gross proceeds of $2.9 million.  Aggregate gross proceeds of $46.8 millionwere reduced by underwriters’ fees of $2.5 million and professional fees andother offering costs of $1.3 million, resulting in net proceeds of $43.0million.  The net proceeds of $43.0million and the $0.9 million contributed by the general partner to maintain its2% interest resulted in total net proceeds associated with the offering of$43.9 million.  The funds were used torepay a portion of the outstanding indebtedness under the Partnership’s creditfacility.

 

###### *SecondaryOffering – September 21, 2004*

###### * *

On September 21, 2004, the Partnershippriced its offering of 2,157,395 common units at $43.41 per unit.  Of the 2,157,395 common units, 2,000,000 weresold by the Partnership for gross proceeds of $86.8 million. The remaining157,395 were sold by certain selling unitholders, proceeds of which have beenretained by them.  Inconnection with the over-allotment provisions of the underwriting agreement,the Partnership issued an additional 323,609 common units for gross proceeds of$14.1 million.  Aggregate gross proceeds of$100.9 million were reduced by underwriters’ fees of $4.8 million andprofessional fees and other offering costs of $0.4 million, resulting in netproceeds of $95.7 million. The net proceeds of $95.7 million and the $2.1million contributed by the general partner to maintain its 2% interest resultedin total net proceeds associated with the offering of $97.8 million, which wereused to repay a portion of the outstanding indebtedness under the Partnership’samended and restated credit facility.

 

*PrivatePlacement – June 27 and July 10, 2003*

 

The Partnership sold 375,000 common units in twoinstallments at a price of $26.23 per unit in a private placement to certainaccredited investors. The first installment of 300,031 units was completed on June 27,2003, for proceeds of approximately $7.9 million. The second installment of74,969 units was completed on July 10, 2003, for proceeds of approximately$1.9 million. Transaction costs for both installments were less than $0.1million. The Partnership’s general partner paid its pro rata contribution in July 2003after the second installment was completed.

 

*PrivatePlacement – July 30, 2004*

 

The Partnership sold 1,304,438 common units in aprivate placement to certain accredited investors for $34.50 per common unitthat resulted in gross proceeds of $45.0 million.  The aggregate gross proceeds of $45.0 millionwere reduced by offering costs of $0.9 million resulting in net proceeds of$44.1 million.  The net proceeds of $44.1million and the $0.9 million contributed by the general partner to maintain its2% interest resulted in total net proceeds associated with the privateplacement of $45.0 million.

 

**OurOwnership in MarkWest Energy Partners**

 

As of December 31,2004, MarkWest Hydrocarbon’s partnership interests consisted of the following:

 

•      2,469,496 subordinated units, representing a 23% limited partner interestin the Partnership; and a

•      90% ownership interestin the general partner of the Partnership. The general partner owns a 2%general partner interest in the Partnership.

 

MarkWest Hydrocarbon’sconsolidated financial statements reflect the consolidation of MarkWest Energy,with the public unitholders’ interest being reflected as a non-controllinginterest in the consolidated statement of operations and in the consolidatedbalance sheet.

 

**Our Contracts**

 

Excluding the revenues and gross marginsderived by MarkWest Energy, the majority of our revenues and gross margins aregenerated from providing processing services, and from our marketing of NGLsand, to a lesser extent, natural gas.  Ascompensation for providing processing services to Appalachian producers, weearn a fee and receive title to the NGLs produced.  In return, we are required to replace, in drynatural gas, the energy content of

 

35

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the NGLsextracted.  This Btu replacementobligation is referred to in the industry as a “keep-whole” arrangement.  In keep-whole arrangements, our principalcost associated with the arrangement is the replacement of the Btus extractedfrom the gas stream in the form of NGLs or consumed as fuel during processing,with dry gas of an equivalent Btu content. The spread between the NGL product sales price and the purchase price ofthe replacement natural gas with an equivalent Btu content is called the “fracspread.”  In the event natural gasbecomes more expensive, on a Btu equivalent basis, when compared to the salesprice of NGL products, the cost of keeping the producer “whole”, could resultin operating losses.

 

Our keep-whole contracts expose us to commodity pricerisk, both on the sales side (of NGLs) and on the purchase side (of naturalgas), which may increase the volatility of our marketing results and cashflows.  However, in September, 2004, weentered into several new and amended agreements with one of the largestAppalachia producers, which allow us to significantly reduce our exposure tocommodity price risk for approximately 25% of our keep-whole gas volumes. Underthese agreements, the Company is limited in the amount of costs it would haveto pay to the producer in the event natural gas becomes more expensive thanNGLs, thereby mitigating the risk of incurring operating losses.

 

**MarkWest Energy Contracts**

 

The Partnership generates the majority of itsrevenues and gross margin from natural gas gathering, processing andtransmission, NGL transportation, fractionation and storage, and crude oilgathering and transportation.  In thePartnership’s current areas of operations, it has a combination of contracttypes.  In many cases, the Partnershipprovides services under contracts that contain a combination of more than oneof the arrangements described below. While all of these services constitute midstream energy operations, thePartnership provides its services pursuant to five different types ofcontracts:

 

•      *Fee-based contracts.* Under fee-based contracts, the Partnership receives a fee or fees forone or more of the following services: gathering, processing, and transmissionof natural gas, transportation, fractionation and storage of NGLs, andgathering and transportation of crude oil. The revenue the Partnership earns from these contracts is directlyrelated to the volume of natural gas, NGLs or crude oil that flows through itssystems and facilities and is not directly dependent on commodity prices. Incertain cases, the contracts provide for minimum annual payments.  To the extent a sustained decline incommodity prices results in a decline in volumes, however, the Partnership’srevenues from these contracts would be reduced.

 

•      *Percent-of-proceeds contracts.* Under percent-of-proceeds contracts, the Partnership generally gathersand processes natural gas on behalf of producers, sells the resulting residuegas and NGLs at market prices and remits to producers an agreed upon percentageof the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, MarkWestEnergy delivers an agreed upon percentage of the residue gas and NGLs to theproducer and sells the volumes it keeps to third parties at market prices.Under these types of contracts, the Partnership’s revenues and gross marginsincrease as natural gas prices and NGL prices increase, and its revenues andgross margins decrease as natural gas prices and NGL prices decrease.

 

•      *Percent-of-index contracts.* Under percent-of-index contracts, the Partnership generally purchasesnatural gas at either (1) a percentage discount to a specified indexprice, (2) a specified index price less a fixed amount or (3) apercentage discount to a specified index price less an additional fixed amount.MarkWest Energy then gathers and delivers the natural gas to pipelines where itresells the natural gas at the index price. With respect to (1) and (3) above, the gross margins thePartnership realizes under the arrangements decrease in periods of low naturalgas prices because these gross margins are based on a percentage of the indexprice.  Conversely, our gross marginsincrease during periods of rising natural gas prices.

 

•      *Keep-whole contracts.* Under keep-whole contracts, the Partnership gathers natural gas from theproducer, processes the natural gas and sells the resulting NGLs to thirdparties at market prices.  Because theextraction of the NGLs from the natural gas during processing reduces the Btucontent of the natural gas, the Partnership must either purchase natural gas atmarket prices for return to producers or make cash payment to the producersequal to the energy content of this natural gas. Accordingly, under thesearrangements, the Partnership’s revenues and gross margins increase as theprice of NGLs increase relative to the price of

 

36

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naturalgas, and its revenues and gross margins decrease as the price of natural gasincreases relative to the price of NGLs.

 

•      *East Texas System gathering arrangements.* The Partnership gathers volumes on the East Texas System under contractswith fee arrangements that are unique to that system.  These contracts typically contain one or moreof the following revenue components:

 

•       *Fixed gathering and compression fees.* Typically, gathering and compression fees are comprised of a fixed feeportion in which producers pay a fixed rate per unit to transport their naturalgas through the gathering system.  Underthe majority of these arrangements, fees are adjusted annually based on theConsumer Price Index.

 

•       *Settlement margin. *Typically, the terms of the Partnership’s East Texas Systemgathering arrangements specify that it is allowed to retain a fixed percentageof the volume gathered to cover the compression fuel charges and deemed linelosses.  To the extent the East TexasSystem is operated more efficiently than provided for by contracted allowances,MarkWest Energy is entitled to retain the difference for its own account.

 

•       *Condensate sales.* During the gathering process, thermodynamic forces contribute to changesin operating conditions of the natural gas flowing through the pipelineinfrastructure.  As a result, hydrocarbondew points are reached, causing condensation of hydrocarbons in thehigh-pressure pipelines.  The East TexasSystem sells the condensate collected in the system at a monthly crude-oilbased price.

 

Inthe Partnership’s current areas of operations, it has a combination of contracttypes and limited keep-whole arrangements. In many cases, the Partnership provides services under contracts thatcontain a combination of more than one of the arrangements described above. Theterms of the Partnership’s contracts vary based on gas quality conditions, thecompetitive environment at the time the contracts are signed and customerrequirements. Our contract mix and, accordingly, our exposure to natural gasand NGL prices, may change as a result of changes in producer preferences, thePartnership’s expansion in regions where some types of contracts are morecommon and other market factors.  Anychange in mix will impact our financial results.

 

AtDecember 31, 2004, the Partnership’s primary exposure to keep-wholecontracts was limited to our Arapaho (Oklahoma) processing plant and our EastTexas processing contracts.  At theArapaho plant inlet, the Btu content of the natural gas meets the downstreampipeline specifications; however, we have the option of extracting NGLs whenthe processing margin environment is favorable. In addition, approximately half, as measured in volumes, of the relatedgas gathering contracts include additional fees to cover plant operating costs,fuel costs and shrinkage costs in a low processing margin environment.  Because of our ability to operate the plantin several recovery modes, including turning it off, coupled with theadditional fees provided for in the gas gathering contracts, our overallkeep-whole contract exposure is limited to a portion of the operating costs ofthe plant.

 

Forthe year ended December 31, 2004, the Partnership generated the followingpercentages of its revenue and gross margin from the following types ofcontracts:

 
| ** **   | ** ** | **Fee-Based** | ** ** | **Percent-of  Proceeds(1)** | ** ** | **Percent-of  Index(2)** | ** ** | **Keep-Whole(3)** | ** ** | **Total** | ** ** |
|--------------|------------|---------------|------------|-----------------------------|------------|--------------------------|------------|-------------------|------------|-----------|------------|
| Revenue      |       | 17            | %          | 14                          | %          | 27                       | %          | 42                | %          | 100       | %          |
| Gross Margin |       | 56            | %          | 9                           | %          | 25                       | %          | 10                | %          | 100       | %          |

 

----

(1)  Includes othertypes of contracts tied to NGL prices.

(2)  Includes othertypes of contracts tied to natural gas prices.

(3)  Includes othertypes of contracts tied to both NGL and natural gas prices.

 

37

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**Restatement of Financial Statements**

 

We have determined that, in certain cases, wedid not comply with generally accepted accounting principles in the preparationof our 2002 and 2003 consolidated financial statements and, accordingly, wehave restated our 2002 and 2003 annual financial statements through the filingof this Form 10-K.  The Company hasalso filed Form 10-Q/A’s for the first three quarters of 2004 to restateits quarterly financial statements for 2003 and 2004.

 

Therestatements result from MarkWest Hydrocarbon’s sale of a portion of itssubordinated Partnership units and interest in the Partnership’s generalpartner to certain employees and directors from 2002 through 2004.  MarkWest Hydrocarbon had historicallyrecorded the sale of the subordinated Partnership units and interests in thegeneral partner to certain of the Company’s employees and directors as a saleof an asset.  These arrangements arereferred to as the Participation Plan. However, the Company determined that these transactions should beaccounted for as compensatory arrangements, consistent with the guidance in APBNo. 25, *Accounting for Stock Issued toEmployees* and EITF No. 95-16, *Accountingfor Stock Compensation Arrangements with Employer Loan Features under APBOpinion No. 25.*  This guidance requires the Company to recordcompensation expense based on the market value of the subordinated Partnershipunits and the formula value of the general partner interests held by theemployees and directors at the end of each reporting period.  The formula value is the amount MarkWestHydrocarbon would pay to repurchase the interests if the employee exercises itsput option or the Company exercises its call option for the interests held bythe employees and directors.  In additionto these adjustments, we have also made an adjustment to record natural gasinventory at cost in the fourth quarter of 2003.  Previously, the inventory was incorrectlyidentified as a pipeline imbalance and was recorded at fair value.  We have also adjusted non-controllinginterest in consolidated subsidiary to reflect the portion of the restatementadjustments attributable to the non-controlling interest in MarkWest Energy Partners,and to eliminate the effect of the subordinated units and general partnerinterests owned by the employees and directors which were previously accountedfor as non-controlling interest.  Incometaxes have been adjusted to reflect the tax effect of these restatementadjustments.  The impact of theserestatements was to increase net loss by $1.1 million for the year ended December 31,2003 and $0.2 million for the year ended December 31, 2002.

 

In addition, the Companyhas restated its financial position by decreasing its originally reportedassets and liabilities and equity by $0.2 million at December 31, 2003,the details of which are shown in Note 23, *Restatement of Consolidated Financial Statements*, to theconsolidated financial statements in Part II, Item 8 of this Form 10-K.

 

The information containedin this Managements Discussion and Analysis of Financial Condition and Resultsof Operations has been changed to reflect these restatement adjustments.  All amounts reported in this Managements Discussionand Analysis of Financial Condition and Results of Operations are as restated,unless otherwise stated.

 

**Segments**

 

The Company’s operations are classified into tworeportable segments:

 

(1)   Managing MarkWest Energy —The Company operates MarkWest Energy, a publiclytraded limited partnership engaged in the gathering, processing andtransmission of natural gas, the transportation, fractionation and storage ofnatural gas liquids, and the gathering and transportation of crude oil.

(2)   Marketing —The Company sells its equity and third party NGLs, purchasesthird party natural gas and sells its equity and third-party natural gas.  Since February 2004, the Company is alsoengaged in the wholesale marketing of propane.

 

During 2003, theCompany discontinued its exploration and production business segment.

 

38

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**Resultsof Operations**

 

***Year Ended December 31, 2004 Compared to the Year EndedDecember 31, 2003***

 
| ** **                                              | ** ** | **Marketing**      | ** ** | **MarkWest  Energy** | ** ** | **Eliminating****Entries** | ** ** | **Total**  | ** ** |
|---------------------------------------------------------|------------|--------------------|------------|----------------------|------------|----------------------------|------------|------------|------------|
| ** **                                              | ** ** | **(in thousands)** | ** ** |
| **Year  Ended December 31, 2004:**                 | ** ** | ** **         | ** ** | ** **           | ** ** | ** **                 | ** ** | ** ** | ** ** |
| Revenues                                                |       | $                  | 218,337    |                 | $          | 301,314                    |       | $          | (59,538    | ) | $ | 460,113 |   |
|                                                    |       |               |       |                 |       |                       |       |       |       |
| Purchased  product costs                                |       | 185,951            |       | 211,534              |       | (34,224                    | )          | 363,261    |       |
| Facility  expenses                                      |       | 23,983             |       | 29,911               |       | (25,314                    | )          | 28,580     |       |
| Selling, general  and administrative expenses           |       | 11,999             |       | 16,133               |       | —                     |       | 28,132     |       |
| Depreciation                                            |       | 1,339              |       | 15,556               |       | —                     |       | 16,895     |       |
| Amortization of  intangible assets                      |       | —             |       | 3,640                |       | —                     |       | 3,640      |       |
| Accretion of  asset retirement obligation               |       | 2                  |       | 13                   |       | —                     |       | 15         |       |
| Impairments                                             |       | —             |       | 130                  |       | —                     |       | 130        |       |
| Total operating  expenses                               |       | 223,274            |       | 276,917              |       | (59,538                    | )          | 440,653    |       |
|                                                    |       |               |       |                 |       |                       |       |       |       |
| Operating income  (loss)                                |       | $                  | (4,937     | )                    | $          | 24,397                     |       | $          | —     |   | $ | 19,460 |   |
|                                                    |       |               |       |                 |       |                       |       |       |       |
| **Year  Ended December 31, 2003(as restated)(1):** |       |               |       |                 |       |                       |       |       |       |
| Revenues                                                |       | $                  | 142,569    |                 | $          | 117,430                    |       | $          | (50,731    | ) | $ | 209,268 |   |
|                                                    |       |               |       |                 |       |                       |       |       |       |
| Purchased  product costs                                |       | 142,633            |       | 70,832               |       | (25,921                    | )          | 187,544    |       |
| Facility  expenses                                      |       | 25,304             |       | 20,463               |       | (24,810                    | )          | 20,957     |       |
| Selling, general  and administrative expenses           |       | 7,267              |       | 8,598                |       | —                     |       | 15,865     |       |
| Depreciation                                            |       | 1,247              |       | 7,548                |       | —                     |       | 8,795      |       |
| Impairments                                             |       | 1,039              |       | 1,148                |       | —                     |       | 2,187      |       |
| Total operating  expenses                               |       | 177,490            |       | 108,589              |       | (50,731                    | )          | 235,348    |       |
|                                                    |       |               |       |                 |       |                       |       |       |       |
| Operating income  (loss)                                |       | $                  | (34,921    | )                    | $          | 8,841                      |       | $          | —     |   | $ | (26,080 | ) |

 
| ** **                                                                                                                           | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                                                                           | ** ** | **2004**                         | ** ** | **2003  (as restated) (1)** | ** ** |
| ** **                                                                                                                           | ** ** | **(in thousands)**               | ** ** |
| Operating income  (loss)                                                                                                             |       | $                                | 19,460     |   | $ | (26,080 | ) |
| Interest income                                                                                                                      |       | 647                              |       | 106 |   |
| Interest expense                                                                                                                     |       | (9,383                           | )          | (4,347 | ) |
| Amortization of  deferred financing costs                                                                                            |       | (5,281                           | )          | (2,104 | ) |
| Dividend income                                                                                                                      |       | 259                              |       | — |   |
| Miscellaneous  income (expense)                                                                                                      |       | 788                              |       | (92 | ) |
| Income (loss)  from continuing operations before non-controlling interest in net income of  consolidated subsidiary and income taxes |       | 6,490                            |       | (32,517 | ) |
|                                                                                                                                 |       |                             |       |   |   |
| Provision  (benefit) for income taxes                                                                                                |       | 78                               |       | (13,085 | ) |
|                                                                                                                                 |       |                             |       |   |   |
| Non-controlling  interest in net income of consolidated subsidiary                                                                   |       | (7,315                           | )          | (2,988 | ) |
|                                                                                                                                 |       |                             |       |   |   |
| Loss from  continuing operations                                                                                                     |       | $                                | (903       | ) | $ | (22,420 | ) |

 

----

(1)  See Note 23 in Notes to Consolidated FinancialStatements.

 

39

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***Marketing***

 

*Revenues.*  Revenues increased $75.8 million, or 53%,over 2003 revenue primarily due to increases in NGL product sale prices and a4% increase in volumes in Appalachia, which combined to increase revenue byapproximately $37.1 million.  Inaddition, revenue increased $33.2 million due to the commencement of awholesale propane marketing business in 2004. Revenues in 2003 was reduced by losses on crude oil derivatives of $15.9million, which effects the comparison from year to year.  These increases were offset, in part, by adecrease in third party NGL sales of $10.1 million as a result of the sale ofthe two terminals in 2003.

 

*PurchasedProduct Costs.* Purchased product costs increased $43.3 million, or 30%, in 2004primarily due to costs from our wholesale propane marketing business introducedin 2004 adding $32.6 million and an increase in product costs from ourAppalachian natural gas liquids business of $20.1 million as a result of a 4%increase in volume and an increase in price of 27%.  These increases were offset in part by adecrease in third party NGL product costs of $10.2 million as a result of thesale of the two terminals in 2003.

 

*FacilityExpenses.*  Facilityexpenses decreased by approximately $1.3 million, or 5%, as a result of adecrease in costs associated with two terminals in Appalachia that were sold in2003.

 

*Selling, general and administrative expenses. *Selling, general andadministrative expenses increased by $4.7 million, or 65%, as a result of stockoption compensation of $2.0 million, increased incentive compensation andseverance related expenses of $1.0 million and an increase in Sarbanes Oxleycompliance expenses and audit fees of $0.9 million.  In addition, compensation expenseresulting from the sale of the subordinated Partnership units and interests inthe general partner to certain of MarkWest Hydrocarbon’s employees anddirectors from 2002 through 2004 increased selling, general and administrativeexpenses by $1.0 million.  Theseincreases were partially offset by a decrease in selling, general andadministrative expenses attributed to discontinued operations that were sold in2003.

 

*Depreciation*.  The increase in depreciation expense of $0.1million, or 7%, was principally due to the increase in software and hardwareadditions associated with the upgrade of our information technologyinfrastructure as well as the acceleration of deprecation of our facilities inMichigan to more closely match our declining reserves.

 

*Impairments. *Impairmentsdecreased by $1.0 million, or 100%, as a result of a 2003 write down in thevalue of the Company’s remaining western Michigan oil and gas operations.

 

***MarkWest Energy***

 

*Revenues. *2004 Revenues were higher than our 2003 revenues primarily due to thePartnership’s 2003 and 2004 acquisitions, which increased its revenues by$168.6 million.  The increase was alsodue to higher Appalachia NGL product sales prices and volumes, which increasedrevenues by $9.5 million.  In addition,higher margins due to higher gas prices in the Southwest, along with increasedSouthwest processing margins from an increase in liquid prices, contributed$6.3 million.  These increases werepartially offset by a reduction in the Partnership’s Michigan Pipeline throughputvolumes, which decreased revenue by $0.5 million.

 

*Purchased Product Costs.* Purchased product costs were higher in 2004 by $140.7 million primarilydue to the Partnership’s late 2003 and 2004 acquisitions, which increased itspurchased product costs by $128.3 million. The remainder of the increase is primarily attributable to price andvolume increases for our Appalachia NGL product sales.  Price increases contributed $7.8 million andvolume increases contributed an additional $4.6 million to purchased productcosts.

 

*Facility Expenses. *Facility expenses increased approximately $9.4 million during 2004relative to the same period in 2003 primarily due to the Partnership’s 2003 and2004 acquisitions.

 

*Selling,*G*eneral and Administrative Expenses.*  Selling, general and administrative expensesincreased by $7.5 million during the year ended December 31, 2004 comparedto 2003 because MarkWest Hydrocarbon was contractually limited in the amount itcould charge the Partnership to $4.9 million annually, from May 24, 2002,the date of the Partnership’s initial public offering, through May 23,2003.  In addition, selling, general andadministrative expenses have increased due to increased administrative costs of$2.1 million associated with the Partnership’s

 

40

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acquisitions, increased Sarbanes-Oxley compliance related expenses andaudit fees of $1.4 million, an increase in incentive compensation and severanceexpense of $1.0 million and professional services costs of $0.8 million.  In addition, the allocation of compensationexpense to the Partnership resulting from the sale of the subordinatedPartnership units and interests in the Partnership’s general partner to certainof MarkWest Hydrocarbon’s employees and directors from 2002 through 2004increased selling, general and administrative expenses by $1.4 million.  The charge did not affect management’sdetermination of the Partnership’s distributable cash flow for any period, anddid not affect net income attributed to the limited partners.

 

*Depreciation. *Depreciation expense increased during 2004 primarily due to thePartnership’s 2003 and 2004 acquisitions, which increased depreciation byapproximately $5.4 million. Additionally, commencing January 1, 2004 the Partnershipaccelerated the rate of depreciation of its Michigan gathering pipeline andprocessing plant by reducing the estimated useful lives of the related assetsfrom 20 years to 15 years to more closely match expected lives of contractuallydedicated reserves behind the Partnership’s facilities.

 

*Amortization of IntangibleAssets. *Amortization expense increased during 2004primarily due to the East Texas System acquisition in July 2004.  On July 30, 2004, the Partnershipcompleted the acquisition of American Central Eastern Texas’ Carthage gatheringsystem and gas processing assets located in east Texas for approximately $240.7million.  Of the total purchase price,$165.4 million was allocated to customer contracts, of which $3.4 million wasamortized during 2004.

 

*Impairments. *During the fourth quarter of 2004, the Partnership recorded a write-offof $0.1 million of costs associated with an isomerization unit taken out ofservice.  During the fourth quarter of2003, the Partnership’s general partner’s board of directors approved a plan toreplace the Partnership’s existing Cobb extraction facility with a newfacility.  Consequently, in accordancewith Statement of Financial Accounting Standards (“SFAS”) No. 144, *Accounting for the Impairment or Disposal of LongLived Assets,*the Partnership wrote down the carrying value of thecurrent Cobb facility by $1.1 million to its estimated fair value.

 

***Other Income andExpenses***

 

*InterestExpense.*  Interest expense increased $5.0 million, or 116%,during 2004 relative to 2003 primarily due to increased debt levels resultingfrom the Partnership’s financing of its 2003 and 2004 acquisitions.  A significant amount of the Partnership’s2004 acquisitions were financed through additional borrowings under its creditfacility and the issuance of its senior notes.

 

*Amortization of deferred financing costs. *The increase in amortization of deferred financing costs in 2004 relativeto 2003 primarily is attributable to the debt refinancings completed in 2004 aswell as an increase in deferred financing cost as a result of the issuance ofthe Partnership’s senior notes.  During2004, we amortized approximately $5.2 million of deferred financing costsrelated to debt issuance costs incurred to finance the Partnership’s 2004acquisitions, of which $1.5 million represented accelerated amortization due tothe refinancing of the Partnership’s credit facility in July and again in October 2004.  Deferred financing costs are being amortizedover the estimated term of the related obligations, which approximates theeffective interest method.

 

*Dividend income. *Dividendincome increased to $0.3 million during 2004 as a result of investments inmarketable securities of midstream master limited Partnerships.  The Company did not have these investments in2003.

 

*Income**from Discontinued Operations.*The income from discontinuedoperations in 2003 is primarily attributable to the net gain on sales of ouroil and gas properties during 2003.

 

*Provision (benefit) for Incometaxes. *The Company’s results of operations reflecteda $0.1 million provision for 2004 compared to a $13.1 million benefit for2003.  The change was due primarily tothe $34.7 million increase in earnings from continuing operations, includingnon-controlling interest in net income of consolidated subsidiary.

 

*Non-controlling interest in netincome of consolidated subsidiary. *Non-controlling interest in net income ofconsolidated subsidiary increased by $4.3 million, or 145%, as a result of theincrease in earnings of MarkWest

 

41

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Energy and an increase in ownership ofnon-controlling interests commensurate with private placements and publicofferings to finance acquisitions.

 

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

 
| ** **                                               | ** ** | **Marketing**      | ** ** | **MarkWest Energy** | ** ** | **Eliminating****Entries** | ** ** | **Total**  | ** ** |
|----------------------------------------------------------|------------|--------------------|------------|---------------------|------------|----------------------------|------------|------------|------------|
| ** **                                               | ** ** | **(in thousands)** | ** ** |
| **Year  Ended December 31, 2003 (as restated)(1):** | ** ** | ** **         | ** ** | ** **          | ** ** | ** **                 | ** ** | ** ** | ** ** |
| Revenues                                                 |       | $                  | 142,569    |                | $          | 117,430                    |       | $          | (50,731    | ) | $ | 209,268 |   |
|                                                     |       |               |       |                |       |                       |       |       |       |
| Purchased  product costs                                 |       | 142,633            |       | 70,832              |       | (25,921                    | )          | 187,544    |       |
| Facility  expenses                                       |       | 25,304             |       | 20,463              |       | (24,810                    | )          | 20,957     |       |
| Selling, general  and administrative expenses            |       | 7,267              |       | 8,598               |       | —                     |       | 15,865     |       |
| Depreciation                                             |       | 1,247              |       | 7,548               |       | —                     |       | 8,795      |       |
| Impairments                                              |       | 1,039              |       | 1,148               |       | —                     |       | 2,187      |       |
| Total operating  expenses                                |       | 177,490            |       | 108,589             |       | (50,731                    | )          | 235,348    |       |
|                                                     |       |               |       |                |       |                       |       |       |       |
| Operating income  (loss)                                 |       | $                  | (34,921    | )                   | $          | 8,841                      |       | $          | —     |   | $ | (26,080 | ) |
|                                                     |       |               |       |                |       |                       |       |       |       |
| **Year  Ended December 31, 2002 (as restated)(1):** |       |               |       |                |       |                       |       |       |       |
| Revenues                                                 |       | $                  | 112,049    |                | $          | 70,246                     |       | $          | (26,508    | ) | $ | 155,787 |   |
|                                                     |       |               |       |                |       |                       |       |       |       |
| Purchased  product costs                                 |       | 100,334            |       | 38,906              |       | (11,714                    | )          | 127,526    |       |
| Facility  expenses                                       |       | 16,838             |       | 15,101              |       | (14,794                    | )          | 17,145     |       |
| Selling, general  and administrative expenses            |       | 4,203              |       | 5,411               |       | —                     |       | 9,614      |       |
| Depreciation                                             |       | 1,036              |       | 4,980               |       | —                     |       | 6,016      |       |
| Total operating  expenses                                |       | 122,411            |       | 64,398              |       | (26,508                    | )          | 160,301    |       |
|                                                     |       |               |       |                |       |                       |       |       |       |
| Operating income  (loss)                                 |       | $                  | (10,362    | )                   | $          | 5,848                      |       | $          | —     |   | $ | (4,514 | ) |

 
| ** **                                                                                                                  | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                                                                  | ** ** | **2003  (as restated) (1)**      | ** ** | **2002  (as restated) (1)** | ** ** |
| ** **                                                                                                                  | ** ** | **(in thousands)**               | ** ** |
| Operating loss                                                                                                              |       | $                                | (26,080    | ) | $ | (4,514 | ) |
| Interest income                                                                                                             |       | 106                              |       | 65 |   |
| Interest expense                                                                                                            |       | (4,347                           | )          | (2,474 | ) |
| Amortization of  deferred financing costs                                                                                   |       | (2,104                           | )          | (4,343 | ) |
| Gain on sale of  non-operating assets                                                                                       |       | —                           |       | 5,454 |   |
| Miscellaneous expense                                                                                                       |       | (92                              | )          | (73 | ) |
| Loss from  continuing operations before income taxes and non-controlling interest in net  income of consolidated subsidiary |       | (32,517                          | )          | (5,885 | ) |
|                                                                                                                        |       |                             |       |   |   |
| Benefit for  income taxes                                                                                                   |       | (13,085                          | )          | (3,057 | ) |
|                                                                                                                        |       |                             |       |   |   |
| Non-controlling  interest in net income of consolidated subsidiary                                                          |       | (2,988                           | )          | (1,947 | ) |
|                                                                                                                        |       |                             |       |   |   |
| Loss from  continuing operations                                                                                            |       | $                                | (22,420    | ) | $ | (4,775 | ) |

 

----

(1)  See Note 23 in Notes to Consolidated FinancialStatements.

 

***Marketing***

 

*Revenues.*The increase of $30.5 million, or 27%, to revenues was primarily due to a $41.4million increase in our NGL products sales prices in Appalachia offset byapproximately $11.2 million in hedge losses above 2002 levels.

 

42

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*Purchased Product Costs.* Purchased product costs increased by $42.3 million, or 42%, in 2003primarily due to an increase in the weighted average price of our Appalachianreplacement natural gas from our keep-whole and percent-of-proceeds contractbased business.

 

*FacilityExpenses.*  Facilityexpenses increased $8.5 million during 2003 primarily due to the Partnership’s2003 acquisitions, which added $3.2 million. Increased fuel expenses in Appalachia and increased throughput at thePartnership’s Michigan operations also increased facility expenses.

 

*Selling,*g*eneral and administrative expenses.*  Selling, general and administrative expensesincreased $3.1 million, or 73%, because MarkWest Hydrocarbon was contractuallylimited in the amount it could charge the Partnership to $4.9 million annually,from May 24, 2002, the date of the Partnership’s initial public offering,through May 23, 2003.  In addition,the allocation of compensation expense to the Partnership resulting from thesale of subordinated Partnership units and interests in the general partner tocertain of MarkWest Hydrocarbon’s employees and directors from 2002 through2003 increased selling, general and administrative expenses by $0.3 million.

 

*Depreciation.*  The increase in depreciation expense of $0.2million, or 20%, was principally due to computer and software additions relatedto the upgrade of our information technology infrastructure.

 

*Impairments. *Impairmentsdecreased by $1.0 million, or 100%, as a result of a 2003 write down in thevalue of the Company’s remaining western Michigan oil and gas operations.

 

***MarkWest Energy***

 

*Revenues. *The Partnership’s 2003revenues were higher than its 2002 revenues primarily due to its 2003acquisitions, which increased its revenues by $54.8 million, partially offsetby the impact of the terms of the new contracts entered into by the Partnershipwith MarkWest Hydrocarbon concurrent with the closing of its May 2002initial public offering.

 

*Purchased Product Costs.*  Purchased product costs were higher in 2003by $31.9 million primarily due to the Partnership’s 2003 acquisitions, whichincreased its purchased product costs by $44.8 million, partially offset by theimpact of the terms of the new contracts entered into by the Partnership withMarkWest Hydrocarbon concurrent with the closing of its May 2002 initialpublic offering.

 

*Facility Expenses. *Facilityexpenses increased $5.4 million during 2003 primarily due to the Partnership’s2003 acquisitions, which added $3.2 million. Increased fuel expenses in Appalachia and increased throughput at thePartnership’s Michigan operations also increased facility expenses.

 

*Selling,*g*eneral and administrative expenses.*  Selling, general and administrative expensesincreased $3.2 million, or 59%, principally due to increased non-cash, phantomunit compensation expense, a result of an increase in the Partnership’s commonunit price and the number of units granted and vested during 2003, and thePartnership’s incremental costs associated with being a publicly tradedcompany.  In addition, the allocation ofcompensation expense to the Partnership resulting from the sale of subordinatedPartnership units and interests in the general partner to certain of MarkWestHydrocarbon’s employees and directors from 2002 through 2003 increased selling,general and administrative expenses by $0.8 million.

 

*Depreciation.*  Depreciation expense increased $2.6 million,or 52%, during 2003 primarily due to the Partnership’s 2003 acquisitions.

 

*Impairments. *Duringthe fourth quarter of 2003, the Partnership’s general partner’s board ofdirectors approved a plan to replace its existing Cobb extraction facility witha new facility.  Consequently, inaccordance with SFAS No. 144, *Accountingfor the Impairment or Disposal of Long Lived Assets,*the Partnershipwrote down the carrying value of the current Cobb facility by $1.1 million toits estimated fair value.

 

43

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***Other Income andExpenses***

 

*Interestexpense.*  The increaseto interest expense of $1.9 million, or 76%, was primarily attributable toborrowings by MarkWest Energy to finance its 2003 acquisitions.

 

*Amortization of Deferred Financing Costs. *Amortization of deferredfinancing costs was $2.1 million for the year ended December 31, 2003,compared to $4.3 million for the year ended December 31, 2002, a decreaseof 52%.  The 2003 write-down of deferredfinancing costs eliminated the remaining deferred financing costs associatedwith the MarkWest Hydrocarbon credit facility that was terminated in December 2003.

 

*Income from Discontinued Operations.*Theincrease to income from discontinued operations is primarily attributable tothe net gain on sales of our oil and gas properties during 2003.

 

*Income tax benefit. *Income tax benefit increased $10.0 million for the year ended December 31,2003, compared to the same period in 2002, due primarily to the $27.7 million increasein loss from continuing operations, including non-controlling interest in netincome of consolidated subsidiary.

 

*Non-controlling interest in netincome of consolidated subsidiary. *Non-controlling interest in net income ofconsolidated subsidiary increased by $1.0 million, or 53%, as a result of theincrease in earnings of MarkWest Energy and an increase in ownership ofnon-controlling interests commensurate with private placements and publicofferings to finance acquisitions.

 

44

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# **Seasonality**

 

A portion of our revenue and, as a result, our grossmargin, is dependent upon the sales prices of natural gas and NGL products,particularly propane, and the purchase price of natural gas, both of whichfluctuate with winter weather conditions, and other changes in supply anddemand.  The strongest demand for propaneand the highest propane sales margins generally occur during the winter heatingseason.  As a result, we historicallyrecognize a significant amount of our annual income during the first and fourthquarters of the year.

 

**Liquidityand Capital Resources**

 

**MarkWest Hydrocarbon**

 

Our primary source of liquidity to meet operatingexpenses and fund capital expenditures is cash flow from operations,principally from the marketing of natural gas and NGLs, and quarterlydistributions received from MarkWest Energy. Based on current volume, price and expense assumptions, we expect cashon hand, cash flow from operations and distributions from the Partnership tofund our operations and capital expenditures in 2005.  Most of our future capital expenditures arediscretionary in nature.  During 2005, wehave budgeted $0.8 million for capital expenditures, consisting principally ofcomputer hardware and software.

 

We had $3.6 million in unrestricted cash on hand and $14.8million in marketable securities at December 31, 2004, exclusive ofMarkWest Energy’s $24.3 million cash on hand. Exclusive of MarkWest Energy’s debt, we had no debt outstanding as of December 31,2004.  In February 2004, wedisbursed approximately $4.8 million to pay a special one-time dividend of $0.45per share to our common stockholders. In May 2004, we disbursedapproximately $0.2 million to pay the first quarter dividend of $0.023 percommon share to our common shareholders. On August 19, 2004, we disbursedapproximately $0.2 million to pay the second quarter dividend of $0.023 pershare to our common stockholders.  On December 6,2004, we disbursed approximately $0.5 million to pay the third quarter dividendof $0.05 per share of our common stock. On January 21, 2005, our Board of Directors announcedthat it declared a quarterly cash dividend of $0.075 per share of our commonstock.  The dividend was paid on February 21,2005, to the stockholders of record as of the close of business on February 9,2005.  We disbursed $0.8 million to paythis dividend.    On April 28, 2005,our Board of Directors announced that it declared a quarterly cash dividend of$0.10 per share of our common stock.  Thedividend was paid on May 23, 2005, to the stockholders of record as of theclose of business on May 16, 2005. We disbursed $1.1 million to pay this dividend.  On July 22, 2005, our Board of Directorsannounced that it declared a quarterly cash dividend of $0.10 per share of ourcommon stock.  The dividend was paid on August 22,2005 to the stockholders of record as of the close of business on August 15,2005.  We disbursed $1.1 million to paythis dividend.

 

We own90% of the general partner of MarkWest Energy. The general partner of MarkWest Energy owns the 2% general partnerinterest and all of the incentive distribution rights.  The incentive distribution rights entitle usto receive an increasing percentage of cash distributed by the Partnership ascertain target distribution levels are reached. Specifically, they entitle usto receive 13% of all cash distributed in a quarter after each unit hasreceived $0.55 for that quarter, 23% of all cash distributed after each unithas received $0.625 for that quarter and 48% of all cash distributed after eachunit has received $0.75 for that quarter. For the year ended December 31,2004, we received $7.1 million in distributions for our subordinated units, andthe general partner received $1.8 million, including $1.3 million representingpayments on incentive distribution rights. If the Partnership continues to growand increase its quarterly distributions per limited partner unit, we expectour distributions to increase accordingly. If the partnership distribution remains at its current level of $0.80per limited unit per quarter, we expect to receive $7.9 million indistributions for our subordinated units and we expect the general partner toreceive $4.4 million, including $3.7 million representing payments on incentivedistribution rights, for the year ended December 31, 2005.

 

Cash flowsgenerated from our marketing operations are subject to volatility in energyprices, especially prices for NGLs and natural gas. Our cash flows are enhancedin periods when the prices received for NGLs are high relative to the price ofnatural gas we purchase to satisfy our “keep-whole” contractual arrangements inAppalachia, and are reduced in periods when the prices received for NGLs arelow relative to the price of natural gas we purchase to satisfy suchcontractual arrangements.  Under “keep-whole”contracts, we retain and sell the NGLs produced in our processing operationsfor third-party producers, and then reimburse or “keep whole” the producers

 

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for the energy content of theNGLs 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 extractedis greater than the cost of replacing those Btus with dry gas, resulting inpositive operating margins under these contracts. Periodically, when naturalgas becomes more expensive, on a Btu equivalent basis, than NGL products, thecost of keeping the producer “whole” can result in operating losses. We enteredinto several new and amended agreements in September with one of thelargest Appalachia producers that allow us to significantly reduce our exposureto commodity price risk for approximately 25% of our keep-whole gasvolumes.  Under these agreements, theCompany is limited on the amount of costs it would have to pay to the producerin the event natural gas becomes more expensive than NGL product sales price,thereby mitigating the risk of incurring operating losses.  In connection with these agreements, we paid$3.3 million of consideration to the producer that is being amortized asadditional cost of the gas purchased over the term of the contracts, October 1,2004 through February 9, 2015.  Forthe year ended December 31, 2004, our loss from continuing operationsbefore income taxes was $0.8 million compared with a loss from continuingoperations before income taxes of $35.5 million for the same period in 2003.  The improvement in income from operations wasdue, in part, to a favorable pricing environment in 2004.

 

***Debt***

 

On October 25, 2004, we entered into a $25.0million senior credit facility with a term of one year.  The $25.0 million revolving facility has avariable interest rate based on the base rate, which is equal to the higher ofa) the Federal Funds Rate plus 1⁄2 of 1%, and b) the rate of interest in effectfor such day as publicly announced from time to time by the AdministrativeAgent as its prime rate, plus the applicable rate, which is based on autilization percentage.  The amountavailable to be drawn under the credit facility is based upon the amount of oureligible accounts receivable and inventory. We are required to pay a commitment fee equal to the applicable rate (asdefined in the agreement and determined by a utilization percentage) times theactual daily amount by which the aggregate commitment exceeds the sum of (i) theoutstanding amount of loans plus (ii) the outstanding amount of our letterof credit obligations.  Substantially allof our assets and our subsidiaries (other than excluded MarkWest Energy’sentities) are pledged to the lender to secure the repayment of the outstandingborrowings under the credit facility. The proceeds from this facility are expected to be used to financeinventory and accounts receivable and to support letters of credit issued bythe lender.

 

In connection with the credit facility, we are subjectto a number of restrictions on our business, including restrictions on ourability to grant liens on assets; merge, consolidate or sell assets; incurindebtedness; make acquisitions; engage in other businesses; enter intooperating leases; enter into certain swap contracts; engage in transactionswith affiliates; make dispositions; make restricted payments, distributions andredemptions and other usual and customary covenants.  As of December 31, 2004, we had nooutstanding borrowings and we had a borrowing capacity of $19.0 million.  At December 31, 2004, $6.0 million ofthis facility was used for a letter of credit issued in support of one of ourproducer agreements.

 

The credit facility also contains covenants requiringthe Company to maintain:

 

•     apositive consolidated EBITDA (including cash distributions from thePartnership) for the four consecutive fiscal quarters most recently completed;

•     aminimum net worth of $40.0 million plus 50% of proceeds of equity issuedsubsequent to October 25, 2004; and

•     aminimum available cash and marketable securities reserve of $15.0 million,which is to be reduced to zero in the event we restructure a keep-wholecontract restructuring with one of our significant customers.

 

As we were unable to deliver our 2004 audited consolidated financialstatements within 90 days of December 31, 2004, we were not in compliancewith our debt covenants.  The lendinginstitutions have waived the delivery requirement until November 15, 2005.

 

Webelieve that cash on hand, cash received from quarterly distributions(including the incentive distribution rights) from MarkWest Energy, andprojected cash generated from our marketing operations will be sufficient tomeet our working capital requirements and fund our required capitalexpenditures, if any, for the next 12 months. Cash generated from our marketing operations will depend on ouroperating performance, which will be affected by prevailing commodity pricesand other factors, some of which are beyond our control.

 

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**MarkWest Energy**

 

***Overview***

 

The Partnership’s primary source of liquidityto meet operating expenses and fund capital expenditures (other than for largeracquisitions) is cash flow from operations. The public and institutional markets have been the Partnership’sprincipal source of capital to finance a majority of its growth (includingacquisitions).  During 2004, thePartnership increased its capital through the issuance of $187.0 million ofadditional equity and $225.0 million of long-term fixed rate debt.  Since the Partnership has sold debt andequity in both public and private offerings in the past, the Partnershipexpects that these sources of capital will continue to be available to it inthe future as it continues to grow and expand its operations.  However, we caution that ready access tocapital on reasonable terms and the availability of desirable acquisitiontargets at attractive prices are subject to many uncertainties.

 

The Partnership’s objective is to maintain a capitalstructure with approximately equal amounts of debt and equity.  At December 31, 2004, thePartnership had long-term debt outstanding of $225.0 million.  Total partners’ capital at that date was$241.1 million, which resulted in a long-term debt-to-total-capital ratio of48%.

 

***Equity***

 

During January 2004, the Partnership completed asecondary public offering of 1,100,444 of common units, at $39.90 per unit forgross proceeds of $43.9 million.  Inaddition, of the 172,200 common units available to underwriters to coverover-allotments, 72,500 were sold for gross proceeds of $2.9 million. Tomaintain its 2% interest, the general partner of the Partnership contributed$0.9 million.  Total gross proceeds were$47.7 million less associated offering costs of $3.8 million netting thePartnership approximately $43.9 million. As approximately $0.4 million of the offering costs had been incurredduring fiscal 2003, net cash generated from the offering during 2004 wasapproximately $44.3 million.  The fundswere used to repay a portion of the outstanding indebtedness under thePartnership’s credit facility.

 

During July 2004, the Partnership completed aprivate placement of 1,304,438 common units, at $34.50 per unit for grossproceeds of $45.0 million.  To maintainits 2% interest, the general partner contributed $0.9 million.  Total gross proceeds were $45.9 million lessassociated offering costs of $0.9 million netting the Partnership approximately$45.0 million, which were used to finance the East Texas System acquisition.

 

On September 21, 2004, the Partnership completed asecondary public offering of 2,323,609 common units at $43.41 per unit forgross proceeds of $100.9 million and 157,395 common units were sold by certainselling unitholders.  Of the 2,323,609common units sold by the Partnership, 323,609 common units were sold pursuantto the underwriter’s over-allotment option. The Partnership did not receive any proceeds from the common units soldby the selling unitholders.  ThePartnership’s total net proceeds from the offering, after deducting transactioncosts of $5.2 million and including its general partner’s capital contributionof $2.1 million to maintain its 2% interest, were $97.8 million, which wereused to repay a portion of the outstanding indebtedness under the Partnership’samended and restated credit facility.

 

The inability of the Partnership to file its AnnualReport on Form 10-K for the year ended December 31, 2004 and itsquarterly report on Form 10-Q for the quarterly periods ending March 31,2005 and June 30, 2005 on time may impact the timing of the Partnership’sefforts to raise equity in the future. The Partnership will no longer have the ability to incorporate byreference information from its filings into a new registration statement forone year following the later of the filing of this Form 10-K and its Form 10-Qif the Partnership seeks to raise capital through a public offering ofregistered debt or equity securities.  Ifthe Partnership raises additional capital through public debt or equityofferings, the Partnership will be required to file a Form S-1registration statement, which is a long form type of registrationstatement.  The requirement to file a Form S-1registration statement may affect the Partnership’s ability to access thecapital markets on a timely basis and may increase the costs of doing so.

 

The Partnership has the ability to issue an unlimitednumber of units to fund immediately accretive acquisitions.  Under the provisions of the PartnershipAgreement, an immediately accretive acquisition is one that in the generalpartner’s good faith determination would have, if acquired by the Partnershipas of the date that is one

 

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year prior to the first day of the quarter inwhich such acquisition is consummated, resulted in an increase to the amount ofoperating surplus generated by the Partnership on a per-unit basis (for alloutstanding units) with respect to each of the four most recently completedquarters (on a pro forma basis) as compared to the actual amount of operatingsurplus generated by the Partnership on a per-unit basis (for all outstandingunits), excluding operating surplus generated by the Partnership on a per-unitbasis (for all outstanding units), excluding operating surplus attributable tothe acquisition with respect to each of such four most recently completedquarters.  During 2003 and 2004, thePartnership consummated six acquisitions aggregating approximately $354.4million that were partially funded by equity and debt offerings.  For acquisitions that are not immediatelyaccretive, the Partnership has the ability to issue up to 1,207,500 commonunits without unitholder approval.

 

***Debt***

 

*Credit Facility. *The Partnership amended and restated its credit facility in July 2004,increasing the maximum lending limit from $140.0 million to $315.0million.  The proceeds from the secondarypublic offering and borrowings under the credit facility were used to financethe East Texas System acquisition.  Thecredit facility included a $265.0 million revolving facility and a $50.0million term-loan facility.  Theterm-loan portion of the amended and restated credit facility was originallyscheduled to mature in December 2004 and the revolving-portion wasoriginally scheduled to mature in May 2005.

 

On October 25, 2004, the credit facility was, once again, amendedand restated, thereby decreasing the maximum lending limit from $315.0 millionto $200.0 million and increasing the term of the facility to five years.  The credit facility includes a revolvingfacility up to $200.0 million (subject to the restrictive covenants discussedbelow) with the potential to increase the maximum lending limit to $300.0million.  The credit facility matures on October 23,2009. At that time, the credit facility terminates and all outstanding amountsthereunder are due and payable.  Thecredit facility is guaranteed by the Partnership and all of its present andfuture subsidiaries and is collateralized by substantially all of its existingand future assets and those of its subsidiaries.  At the Partnership’s option, the borrowingunder the credit facility bears interest at a variable interest rate basedeither (i) LIBOR plus an applicable margin, which is fixed at a rate of2.75% for the first two quarters following the closing of the credit facilityor (ii) Base Rate (as defined for any day, a fluctuating rate per annumequal to the higher of (a) the Federal Funds Rate plus 1⁄2 of 1% or (b) therate of interest in effect for such day as publicly announced from time to timeby the Administrative Agent of the debt as its “prime rate”) plus an applicablemargin, which is fixed at a rate of 2.00% for the first two quarters followingthe closing of the credit facility. After that period, the applicable margin adjusts quarterly based on thePartnership’s ratio of funded debt to EBITDA (as defined in the agreement).  The Partnership incurs a commitment fee onthe unused portion of the credit facility at a rate ranging from 37.5 to 50.0basis points based upon the ratio of the Partnership’s consolidated funded debt(as defined in the Partnership credit facility) to consolidated EBITDA (asdefined in the Partnership credit facility) for the four most recentlycompleted fiscal quarters.  For the yearsended December 31, 2004 and 2003, the weighted average interest rate was4.48% and 4.69%, respectively.

 

Under the provisions of the credit facility, thePartnership is subject to a number of restrictions on its business, includingrestrictions on its ability to grant liens on assets; make or own certain investments;enter into swap contracts other than in the ordinary course of business; merge,consolidate or sell assets; incur indebtedness (other than subordinatedindebtedness); make acquisitions; engage in other businesses; enter intocapital or operating leases; engage in transactions with affiliates; makedistributions on equity interests; declare or make, directly or indirectly anyrestricted payments.   In addition, thePartnership is subject to certain financial maintenance covenants, includingits ratios of total debt to EBITDA, total senior secured debt to EBITDA, EBITDAto interest and a minimum net worth requirement.  Failure to comply with the provisions of anyof these covenants could result in acceleration of the Partnership’s debt andother financial obligations.  There wasno debt outstanding under the facility at December 31, 2004 and, based onthe covenants below, the Partnership had available borrowing capacity ofapproximately $63.3 million. Thecovenants are used to calculate the available borrowing capacity on a quarterlybasis.

 

The creditfacility also contains covenants requiring the Partnership to maintain:

 

•      a ratio ofnot less than 3.00 to 1.00 of consolidated EBITDA to consolidated interestexpense for the prior four fiscal quarters;

 

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•      a ratio ofnot more than 5.0 to 1.00 of total consolidated debt to consolidated EBITDA forthe prior four fiscal quarters;

•      a ratio of not more than 3.5 to 1.00 of consolidated seniordebt to consolidated EBITDA for the prior four fiscal quarters; and

•      a minimum net worth of $200.0 millionplus 50% of proceeds of equity issued subsequent to October 25, 2004.

 

As the Partnership was unable to deliver its 2004audited consolidated financial statements within 90 days of December 31, 2004,the Partnership was not in compliance with its debt covenants.  The lending institutions for the creditfacility waived the 90-day delivery requirement until June 30, 2005.  The Partnership’s Form 10-K for the yearended December 31, 2004 and its Quarterly Report on Form 10-Q for thefirst quarter of 2005 were filed on June 24, 2005.

 

*Senior Notes.*On October 25, 2004, the Partnership and itssubsidiary MarkWest Energy Finance Corporation issued $225.0 million of seniornotes at a fixed rate of 6.875% and with a maturity date of November 1,2014 pursuant to Rule 144A and Regulation S under the Securities Act of1933.  Subject to compliance with certaincovenants, the Partnership may issue additional notes from time to time underthe indenture.  Interest on the notesaccrues at the rate of 6.875% per year and is payable semi-annually in arrearson May 1 and November 1, commencing on May 1, 2005.  The Partnership may redeem some or all of thenotes at any time on or after November 1, 2009 at certain redemptionprices together with accrued and unpaid interest to the date of redemption, andthe Partnership may redeem all of the notes at any time prior to November 1,2009 at a make-whole redemption price. In addition, prior to November 1, 2007, the Partnership may redeemup to 35% of the aggregate principal amount of the notes with the proceeds ofcertain equity offerings at a specified redemption price.  If the Partnership sells certain assets anddoes not reinvest the proceeds or repay senior indebtedness, or if thePartnership experiences specific kinds of changes in control, the Partnershipmust offer to repurchase notes at a specified price.  Each of the Partnership’s existingsubsidiaries, other than MarkWest Energy Finance Corporation, has guaranteedthe notes jointly and severally and unconditionally.  The notes are senior unsecured obligationsequal in right of payment with all of the Partnership’s existing and futuresenior debt.  These notes are senior inright of payment to all of the Partnership’s future subordinated debt buteffectively junior in right of payment to the Partnership’s secured debt to theextent of the assets securing the debt, including its obligations in respect ofthe Partnership’s credit facility.  Theproceeds from these notes were used to pay down the Partnership’s outstandingdebt under its credit facility.

 

Theindenture governing the senior notes limits the activity of the Partnership andits restricted subsidiaries.  Theindenture places limits, on the ability of the Partnership and the restrictedsubsidiaries to incur additional indebtedness; declare or pay dividends ordistributions or redeem, repurchase or retire equity interests or subordinatedindebtedness; make investments; incur liens; create any consensual limitationon the ability of the restricted subsidiaries to pay dividends, make loans ortransfer property to the Partnership; engage in transactions with thePartnership’s affiliates; sell assets, including equity interest of the Partnership’ssubsidiaries; make any payment on or with respect to, or purchase, redeem,defease or otherwise acquire or retire for value any subordinated obligation orguarantor subordination obligation (except principal and interest at maturity);and consolidate, merge or transfer assets.

 

ThePartnership agreed to file an exchange offer registration statement, or undercertain circumstances, a shelf registration statement, pursuant to aregistration rights agreement relating to the 2004 senior notes.  On February 22, 2005, the Partnershipfiled the exchange offer registration statement relating to the 2004 seniornotes.  The Partnership is offering toexchange up to $225.0 million aggregate principal amount of new 6.875% seniornotes due 2014 that have been registered under the Securities Act for an equalprincipal amount of the 2004 senior notes. The Partnership failed to complete the exchange offer in the timeprovided for in the subscription agreements (April 19, 2005) and as aconsequence is incurring an interest rate penalty of 0.5%, increasing 0.25%every 90 days thereafter up to 1%, until such time as the exchange offer iscompleted.

 

In addition, the indenture governing the Partnership’soutstanding senior notes contains restrictions on its ability to make cashdistributions.  Under the indenture, thePartnership is restricted from making distributions (a “Restricted Payment”) ifat the time of making the Restricted Payment, a default or an event of defaulthas occurred and is continuing.  ThePartnership’s failure to file its Annual Report on Form 10-K for the yearended December 31, 2004 and its Quarterly Report on Form 10-Q for thefirst quarter of 2005 within the time periods specified in the

 

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Securities and Exchange Commission’s rules andregulations constituted a default under the indenture, and the failure to filethe Form 10-K within thirty days after the April 8, 2005 notice fromthe indenture trustee constituted an event of default under the indenture.  On May 16, 2005, the Partnership paid acash distribution to unitholders for the first quarter of 2005.  This cash distribution, made while the eventof default for failure to file its Form 10-K had occurred and wascontinuing, constituted a default under the indenture, and this default maturedinto an event of default thirty days after such Restricted Payment was made, orJune 15, 2005.  Both of these eventsof default were cured upon the filing of the Partnership’s Form 10-K andthe Quarterly Report on Form 10-Q for the first quarter of 2005 on June 24,2005 prior to any declaration of acceleration of the senior notes by thetrustee as a result of such events of default.

 

***LiquidityRequirements***

 

The Partnership has budgeted $47.8 million for capitalexpenditures for the year ending December 31, 2005, exclusive of anyacquisitions, consisting of $46.3 million for expansion capital and $1.5million for sustaining capital. Sustaining capital includes expenditures to replace partially or fullydepreciated assets in order to maintain the existing operating capacity of thePartnership’s assets and to extend their useful lives.  Expansion capital includes expenditures madeto expand or increase the efficiency of the existing operating capacity of the Partnership’sassets.  Expansion capital expendituresinclude expenditures that facilitate an increase in volumes within thePartnership’s operations.

 

We believe that the Partnership’s available cash, cashprovided by operating activities and funds available under the Partnership’scredit facility will be sufficient to fund the Partnership’s operating,interest and general and administrative expenses, the Partnership’s capitalexpenditures budget, short-term contractual obligations and distributionpayments at current levels for the foreseeable future.  However, the Partnership’s ability to financeadditional acquisitions will likely require the issuance of additional commonunits, the expansion of the credit facility, additional debt financing or acombination thereof.  In the event thatthe Partnership desires or needs to raise additional capital, we cannotguarantee that additional funds will be available at times or on termsfavorable to the Partnership, if at all.

 

The Partnership’s ability to pay distributions to itsunitholders and to make acquisitions will depend upon the future operatingperformance, and more broadly, on the availability of debt and equity financingwhich will be affected by prevailing economic conditions in our industry andfinancial, business and other factors, some of which are beyond our control.

 

***Subsequent Event***

 

On March 31,2005, the Partnership acquired a 50% non-operating membership interest inStarfish Pipeline Company, LLC, from an affiliate of Enterprise ProductsPartners, L.P. for $41.7 million. Starfish owns the FERC regulated Stingray natural gas pipeline and theunregulated Triton natural gas gathering system and West Cameron dehydrationfacility, all located in the Gulf of Mexico and southwestern Louisiana.  The acquisition was financed through thePartnership’s existing credit facility and will be accounted for under theequity method of accounting in the first quarter of 2005.

 

**CashFlows**

 
| ** **                                          | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------|------------|----------------------------------|------------|
| ** **                                          | ** ** | **2004**                         | ** ** | **2003  (as restated) (1)** | ** ** | **2002  (as restated) (1)** | ** ** |
| ** **                                          | ** ** | **(in thousands)**               | ** ** |
|                                                |       |                             |       |   |   |   |   |
| Net cash provided by (used in) operating activities |       | $                                | 26,616     |   | $ | (6,411 | ) | $ | 36,301 |   |
| Net cash provided by (used in) investing activities |       | $                                | (303,017   | ) | $ | (36,887 | ) | $ | (22,719 | ) |
| Net cash provided by (used in) financing activities |       | $                                | 247,101    |   | $ | 78,956 |   | $ | (9,520 | ) |

 

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(1)  See Note 23 in Notes to Consolidated andCombined Financial Statements.

 

Netcash provided by operating activities was higher****in 2004 than in 2003 by $33.0 million, primarily due to anincrease in operating income contributed by the Partnership’s 2003 and 2004acquisitions before certain non-cash charges. The increase is also attributable to higher realized NGL prices andhigher volumes.  We expect that overallour 2005 NGL volumes will be higher than in 2004, principally due to a fullyear of activity from the Partnership’s July 2004 East Texas acquisition,and that cash provided by operating activities in 2005 will exceed 2004levels.  However, a precipitous declinein natural gas or NGL prices in 2005 would significantly affect the amount ofcash flow that would be generated from operations.

 

Netcash used in investing activities was higher in 2004 than 2003 by $266.1million because of the Partnership’s two 2004 acquisitions, which aggregatedapproximately $243.0 million.  We alsopurchased marketable securities of $15.1 million in 2004 and increased ourrestricted cash by $15.0 million.  Weused approximately $30.7 million of cash in 2004 for capital expenditures,primarily for the construction of the Partnership’s new Cobb processingreplacement facility and construction of new processing plants and gatheringsystems in East Texas to handle the Partnership’s future contractualcommitments.  Total cash expenditures forour 2003 acquisitions were approximately $110.0 million.  We also had capital expenditures of $31.0million in 2003.  These expenditures wereoffset by proceeds of $104.3 million from the sale of our San Juan Basinproperties, MarkWest Resources Canada Corp. and MarkWest MidstreamServices.  In 2005, we expect to use cashof $47.8 million for capital expenditures (excluding acquisitions) and we planto continue to expand the Partnership’s operations in 2005 throughacquisitions.  In the first quarter of2005, the Partnership acquired a 50% non-operating membership interest inStarfish Pipeline Company, LLC for $41.7 million.

 

Netcash provided by financing activities during the year ended December 31,2004 was $247.1 million. The Partnership’s equity financings and borrowingsunder its credit facility and bond offering were primarily responsible for theinflow.  The Partnership raised fundsthrough two public offerings and one private offering generating net proceedsof $183.8 million.  In addition, theCompany issued a net of $83.4 million of debt to finance the Partnership’s twoacquisitions.  Distributions to thePartnership’s unitholders and payment of dividends were $21.2 million.

 

Netcash used in operations during 2003 resulted primarily from losses fromoperations.  The loss from operations wasprimarily caused by the combination of an unfavorable pricing environment(primarily in the first half of 2003) and unfavorable crude oil hedges(throughout 2003).  Net cash flows usedin investing activities increased during 2003 relative to 2002 principally dueto property acquisitions. Net cash provided by financing activities during 2003was primarily the result of borrowings and equity raised through privateplacements and public offerings by the Partnership to fund its 2003acquisitions.

 

**Total Contractual Cash Obligations**

 

A summary ofour total contractual cash obligations as of December 31, 2004, is asfollows, in thousands:

 
| ** **                          | ** ** | **Payment Due by Period** | ** ** |
|-------------------------------------|------------|---------------------------|------------|
| **Type of obligation**              | ** ** | **Total  obligation**     | ** ** | **Due in  2005** | ** ** | **Due in  2006-2007** | ** ** | **Due in  2008-2009** | ** ** | **Thereafter** | ** ** |
|                                |       |                      |       |   |   |   |   |   |   |   |   |
| Long-term debt  (1)                 |       | $                         | 377,111    |   | $ | 15,469 |   | $ | 30,938 |   | $ | 30,938 |   | $ | 299,766 |   |
| Operating leases                    |       | 13,262                    |       | 4,212 |   | 5,388 |   | 2,836 |   | 826 |   |
| Purchase  obligations               |       | 6,122                     |       | 6,122 |   | — |   | — |   | — |   |
| Total  contractual cash obligations |       | $                         | 396,495    |   | $ | 25,803 |   | $ | 36,326 |   | $ | 33,774 |   | $ | 300,592 |   |

 

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(1) Includes interestexpense on our 6.875% senior notes through 2014 of $152.1 million.

 

Annual rent expense was $5.2 million, $2.2million and $2.3 million for the yearsended December 31, 2004, 2003 and 2002, respectively.

 

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### ***Critical Accounting Policies***

### * *

A summary of the significant accounting policies thatwe have adopted and followed in the preparation of our consolidated financialstatements is detailed in Note 2 of accompanying Notes to the ConsolidatedFinancial Statements included in Item 8 of this Form 10-K.  Certain of these accounting policies requirethe use of estimates. We have identified the following estimates that, in ouropinion, are subjective in nature, require the exercise of judgment, andinvolve complex analysis.  Theseestimates are based on our knowledge and understanding of current conditionsand actions that we may take in the future. Changes in these estimates will occur as a result of the passage of timeand the occurrence of future events. Subsequent changes in these estimates may have a significant impact onour financial condition and results of operations.

 

###### ***Impairment of Long-Lived Assets***

###### * *

Inaccordance with SFAS No. 144, *Accountingfor the Impairment or Disposal of Long-Lived Assets*, we evaluate thelong-lived assets, including related intangibles, of identifiable businessactivities for impairment when events or changes in circumstances indicate, inmanagement’s judgment, that the carrying value of such assets may not berecoverable. The determination of whether impairment has occurred is based onmanagement’s estimate of undiscounted future cash flows attributable to theassets as compared to the carrying value of the assets. If impairment hasoccurred, the amount of impairment recognized is determined by estimating thefair value of the assets and recording a provision for the amount by which thecarrying value exceeds fair value.  Forassets identified to be disposed of in the future, the carrying value of theseassets is compared to the estimated fair value less the cost to sell todetermine if impairment is required. Until the assets are disposed of, an estimate of the fair value isrecalculated when related events or circumstances change.

 

Whendetermining whether impairment of one of our long-lived assets has occurred, wemust estimate the undiscounted cash flows attributable to the asset or assetgroup.  Our estimate of cash flows isbased on assumptions regarding the volume of reserves behind the asset andfuture NGL product and natural gas prices. The amount of reserves and drillingactivity are dependent in part on natural gas prices.  Projections of reserves and future commodityprices are inherently subjective and contingent upon a number of variablefactors, including:

 

•      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 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; and

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

 

Anysignificant negative variance in any of the above assumptions or factors couldmaterially affect our cash flows, which could require us to record animpairment of an asset.

 

###### ***Valuation of Intangibles***

###### * *

Significantjudgment is required in establishing the fair value and determining appropriateamortization periods for our intangible assets. Intangible assets acquired in a business combination are recorded underthe purchase method of accounting at their estimated fair values at the date ofacquisition, in accordance with SFAS No. 141, *Business Combinations.* The fair values of acquired intangible assets are determined bymanagement using relevant information and assumptions.  Fair value is generally calculated as thepresent value of estimated future cash flows using a risk-adjusted discountrate, which requires significant management judgment with respect to revenueand expense growth rates, and the selection and use of an appropriate discountrate.  Amortization of intangible assetswith finite useful lives is recorded over the estimated useful life of theasset.  We assess the impairment ofidentifiable intangible assets whenever events or changes in circumstancesindicate that the carrying value may not be recoverable.  At December 31, 2004, we had $162.0million of net intangible assets.  An

 

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impairment of our intangible assets could result in a material,non-cash expense in our consolidated statement of operations.

 

Weapply SFAS No. 142, *Goodwill and OtherIntangible Assets* in determining the life of our intangible assets.  In establishing the amortization period forthe customer contract intangible asset for the East Texas acquisition, whichaccounts for $161.9 million of the intangible assets, the Partnershipconsidered the life of the assets to which the contracts relate, anticipateddrilling activity in the area, likelihood of renewals, competitive factors,regulatory or legal provisions, and maintenance and renewal costs.  As a result of an analysis of these factors,the customer contracts are expected to have an average life of 20 years,including anticipated renewals.  Based onan independent third party analysis of the reserves in the area and thepertinent terms of the customer contracts, the Partnership has determined thata straight-line amortization method is appropriate and representative of theeconomic benefits of the intangible asset.

 

Becauseof the significant judgment required in determining the fair value and life andrelated method of amortization of customer contract intangible assets, actualcash flows could differ significantly from estimated amounts used to determinethe fair value, life and amortization method of these intangible assets.

 

## **Commodity Price Risk Management Activities**

## ** **

We usecommodity price and financial risk management instruments to mitigate ourexposure to price fluctuations in crude oil, natural gas and interestrates.  Recognized gains and losses onderivative contracts are reported as a component of the related transaction.  Results of oil and natural gas derivativetransactions are reflected in revenue, and results of interest rate hedgingtransactions are reflected in interest expense. The changes in the fair value of derivative instruments not qualifyingfor designation as either cash flow or fair value hedges that occur prior tomaturity are reported in the consolidated statement of operations as unrealizedgains (losses) within revenue or interest expense.

 

SFAS No. 133,*Accounting for Derivative Instruments and HedgingActivities* establishes accounting and reporting standards requiringthat derivative instruments (including certain derivative instruments embeddedin other contracts) be recorded at fair value and included in the consolidatedbalance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrumentdepends on the intended use of the derivative and the resulting designation,which is established at the inception of a derivative.  For derivative instruments designated as cashflow hedges, changes in fair value, to the extent the hedge is effective, arerecognized in other comprehensive income until the hedged item is recognized inearnings.  Any change in the fair valueresulting from ineffectiveness, as defined in SFAS 133, is recognizedimmediately in earnings.  For derivativeinstruments designated as fair value hedges, changes in fair value, as well asthe offsetting changes in the estimated fair value of the hedged itemattributable to the hedged risk, are recognized currently in earnings.  Differences between the changes in the fairvalues of the hedged item and the derivative instrument, if any, representgains or losses on ineffectiveness and are reflected currently inearnings.  Hedge effectiveness ismeasured at least quarterly based on the relative changes in fair value betweenthe derivative contract and the hedged item over time.  Changes in fair value of contracts that donot qualify as hedges or are not designated as hedges are also recognizedcurrently in earnings.  See Item 7A *Quantitative and Qualitative Disclosures about MarketRisk* for additional information regarding our hedging activities.

 

Oneof the primary factors that can have an impact on our results of operations isthe method used to value our derivatives. We have established the fair value of our derivative instruments usingestimates determined by our counterparties and subsequently evaluated theminternally using established index prices and other sources.  These values are based upon, among otherthings, futures prices, volatility, time to maturity and credit risk.  The values we report in our financialstatements change as these estimates are revised to reflect actual results,changes in market conditions or other factors, many of which are beyond ourcontrol.

 

Anotherfactor that can impact our results of operations each period is our ability toestimate the level of correlation between future changes in the fair value ofthe hedge instruments and the transactions being hedged, both at the inceptionand on an ongoing basis.  Thiscorrelation is complicated since energy commodity prices, the risk we usuallyhedge, have quality and location differences that can be difficult to hedgeeffectively.  The factors underlying ourestimates of fair value and our assessment of correlation of our hedging derivativesare impacted by

 

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actual results and changes inconditions that affect these factors, many of which are beyond ourcontrol.  Due to the volatility of crudeoil and natural gas prices and, to a lesser extent, interest rates, the Company’sfinancial condition and results of operations can be significantly impacted bychanges in the market value of our derivative instruments.   The net market value of our derivatives wasa liability of $1.1 million at December 31, 2004.

 

**Recent Accounting Pronouncements**

 

In December 2004,the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123(revised 2004), *Share-Based Payment*.  This statement addresses the accounting forshare-based payment transactions in which an enterprise receives employeeservices in exchange for (a) equity instruments of the enterprise, or (b) liabilitiesthat are based on the fair value of the enterprise’s equity instruments or thatmay be settled by the issuance of such equity instruments.  SFAS No. 123(R) requires an entity torecognize the grant-date fair-value of stock options and other equity-basedcompensation issued to employees in the income statement.  The revised Statement requires that an entityaccount for those transactions using the fair-value-based method, andeliminates the intrinsic value method of accounting in APB No. 25, *Accounting for Stock Issued to Employees,*which was permitted under SFAS No. 123, as originally issued.  The revised Statement requires entities todisclose information about the nature of the share-based payment transactionsand the effects of those transactions on the financial statements.  SFAS No. 123(R) is effective for publiccompanies for the first fiscal year beginning after June 15, 2005.  All public companies must use either themodified prospective or the modified retrospective transition method.  We have not yet evaluated the impact of theadoption of this pronouncement on our financial statements.  On March 29, 2005, the SEC staff issuedSAB No. 107, *Share-Based Payment,*to express the views of the staff regarding the interaction between SFAS No. 123(R)and certain SEC rules and regulations and to provide the staff’s viewsregarding the valuation of share-based payment arrangements for publiccompanies.  The Company will take intoconsideration the additional guidance provided by SAB 107 in connection withthe implementation of SFAS No. 123(R).

 

In March 2005,the FASB issued FIN No. 47, *Accountingfor Conditional Asset Retirement Obligations,*which clarifies theaccounting for conditional asset retirement obligations as used in SFAS No. 143,*Accounting for Asset Retirement Obligations.*  A conditional asset retirement obligation isan unconditional legal obligation to perform an asset retirement activity inwhich the timing and (or) method of settlement are conditional on a futureevent that may or may not be within the control of the entity.  Therefore, an entity is required to recognizea liability for the fair value of a conditional asset retirement obligationunder SFAS No. 143 if the fair value of the liability can be reasonablyestimated.  FIN 47 permits, but does notrequire, restatement of interim financial information.  The provisions of FIN 47 are effective forreporting periods ending after December 15, 2005.  The Company is currently evaluating theimpact of adopting FIN 47 on its consolidated financial statements.

 

In May 2005, the FASB issued SFAS No. 154, *Accounting Changes and Error Corrections—areplacement of APB Opinion No. 20 and FASB Statement No. 3*.SFAS No. 154 replaces Accounting**PrinciplesBoard Opinion No. 20, *AccountingChanges*, and SFAS No. 3, *ReportingAccounting Changes in Interim Financial Statements*, and changes therequirements for the accounting for and reporting of a**change in accounting principle. Thisstatement applies to all voluntary changes in accounting principle**and also applies to changes required byan accounting pronouncement in the unusual instance that the**pronouncement does not include specifictransition provisions. The statement is effective for accounting**changes and corrections of errors made infiscal years beginning after December 15, 2005. The**Company will adopt the provisions of SFASNo. 154 beginning in calendar year 2006. Management**believes that the adoption of theprovisions of SFAS No. 154 will not have a material impact on the**Company’s consolidated financialstatements.

 

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**Risk Factors**

 

*In addition to the other information set forth elsewhere inthis Form 10-K, you should carefully consider the following factors whenevaluating MarkWest Hydrocarbon.*

 

**RisksInherent in Our Business**

 

***If we are unable to successfully integratethe Partnership’s recent or future acquisitions, our future financial performancemay be negatively impacted.***

 

Ourfuture growth will depend in part on our ability to integrate the Partnership’srecent acquisitions and the Partnership’s ability to make future acquisitionsof assets and businesses at attractive prices. The Partnership completed the East Texas System, western Oklahoma andMichigan Crude Pipeline acquisitions, which geographically expanded itsoperations in the Southwest, particularly east Texas and Oklahoma, and expandedits operations in Michigan.  We cannotassure you that the Partnership will successfully integrate these or any otheracquisitions into its operations, or that the Partnership will achieve thedesired profitability from such acquisitions. Failure to successfully integrate these substantial or futureacquisitions could adversely affect our financial condition and results ofoperations.

 

Theintegration of acquisitions with our existing business involves numerous risks,including:

 

•      operating a significantly larger combinedorganization and integrating additional midstream operations into our existingoperations;

•      difficulties in the assimilation of theassets and operations of the acquired businesses, especially if the assetsacquired are in a new business segment or geographical area;

•      the loss of customers or key employeesfrom the acquired businesses;

•      the diversion of management’s attentionfrom other business concerns;

•      the failure to realize expected synergiesand cost savings;

•      coordinating geographically disparateorganizations, systems and facilities;

•      integrating personnel from diversebusiness backgrounds and organizational cultures; and

•      consolidating corporate andadministrative functions.

 

Further,unexpected costs and challenges may arise whenever businesses with differentoperations or management are combined, and we may experience unanticipateddelays in realizing the benefits of an acquisition.  Following an acquisition, the Partnership maydiscover previously unknown liabilities associated with the acquired assets thatwill be subject to the same stringent environmental laws and regulationsrelating to releases of pollutants into the environment and environmentalprotection as the Partnership’s existing plants, pipelines and facilities.  Thus, the operation of these new assets couldcause the Partnership to incur increased costs to attain or maintain compliancewith such laws and regulations.  If thePartnership consummates any future acquisition, its capitalization and results ofoperation may change significantly, and you will not have the opportunity toevaluate the economic, financial and other relevant information that thePartnership will consider in determining the application of these funds andother resources.

 

ThePartnership’s acquisition strategy is based in part on the Partnership’sexpectation of ongoing divestitures of assets within the midstreamindustry.  A material decrease in suchdivestitures will limit the Partnership’s opportunities for future acquisitionsand could adversely affect its operations and cash flows available fordistribution to its unitholders (including MarkWest Hydrocarbon).

 

***A significant decrease in natural gasproduction in our areas of operation due to the decline in production fromexisting wells, depressed commodity prices, reduced drilling activities orother factors otherwise could adversely affect our revenues and operatingincome and cash flow.***

 

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Ourprofitability is materially impacted by the volume of natural gas the Partnershipgathers, transmits and processes and NGLs the Partnership transports andfractionates at its facilities.  Amaterial decrease in natural gas production in the Partnership’s areas ofoperation would result in a decline in the volume of natural gas delivered toits pipelines and facilities for gathering, transporting and processing andNGLs delivered to its pipelines and facility for fractionation andtransportation.  The effect of such amaterial decrease would be to reduce our revenue and operating income.  Fluctuations in energy prices can greatlyaffect production rates and investments by third parties in the development ofnew oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas pricesdecrease.  We have no control over thelevel of drilling activity in the areas of operations, the amount of reservesunderlying the wells and the rate at which production from a well will decline,sometimes referred to as the “decline rate.” In addition, we have no control over producers or their productiondecisions, which are affected by, among other things, prevailing and projectedenergy prices, demand for hydrocarbons, the level of reserves, geologicalconsiderations, governmental regulation and the availability and cost of capital.  Failure to connect new wells to thePartnership’s gathering systems would, therefore, result in the amount ofnatural gas it gathers, transmits and processes and the amount of NGLs thePartnership transports and fractionates being reduced substantially over timeand could, upon exhaustion of the current wells, cause the Partnership toabandon its gathering systems and, possibly, cease gathering operations.  The Partnership’s ability to connect to newwells will be dependent on the level of drilling activity in its areas ofoperations and competitive market factors. As a consequence of such declines, our revenues would be materiallyadversely affected.

 

***The Partnership’s substantial debt andother financial obligations could impair the Company’s financial condition,results of operations and cash flows and the ability to fulfill the Partnership’sdebt obligations.***

 

ThePartnership has substantial indebtedness and other financial obligations.

 

Subjectto the restrictions governing the Partnership’s indebtedness and otherfinancial obligations and the indenture governing the notes, the Partnershipmay incur significant additional indebtedness and other financial obligations,which may be secured and/or structurally senior to the notes.

 

ThePartnership’s substantial indebtedness and other financial obligations couldhave important consequences to you.  Forexample, it could:

 

•      make it more difficult for thePartnership to satisfy its obligations with respect to the notes;

 

•      impair the Partnership’s ability toobtain additional financings in the future for working capital, capitalexpenditures, acquisitions, general corporate purposes or other purposes;

 

•      have a material adverse effect on thePartnership if it fails to comply with financial and restrictive covenants inthe Partnership’s debt agreements and an event of default occurs as a result ofthat failure that is not cured or waived;

 

•      require the Partnership to dedicate asubstantial portion of its cash flow to payments on its indebtedness and otherfinancial obligations, thereby reducing the availability of the Partnership’scash flow to fund working capital, capital expenditures, distributions andother general partnership requirements;

 

•      limit the Partnership’s flexibility inplanning for, or reacting to, changes in its business and the industry in whichit operates; and

 

•      place the Partnership at a competitivedisadvantage compared to its competitors that have proportionately less debt.

 

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Theserestrictions could limit the Partnership’s ability and the ability of itssubsidiaries to obtain future financings, make needed capital expenditures,withstand a future downturn in its business or the economy in general, conductoperations or otherwise take advantage of business opportunities that mayarise.  The Partnership’s existing creditfacility contains covenants requiring the Partnership to maintain specifiedfinancial ratios and satisfy other financial conditions.  The Partnership may be unable to meet thoseratios and conditions.  Any future breachof any of these covenants or the Partnership’s failure to meet any of theseratios or conditions could result in a default under the terms of thePartnership’s credit facility, which could result in acceleration of its debtand other financial obligations.  If thePartnership were unable to repay those amounts, the lenders could initiate abankruptcy proceeding or liquidation proceeding or proceed against the collateral.

 

***A material decrease in the supply of crudeoil available for transport through the Partnership’s Michigan Crude Pipeline,or a significant decrease in demand for refined products in the markets servedby this pipeline, could adversely affect our revenues and cash flow.***

 

Thevolume of crude oil the Partnership transports through its Michigan CrudePipeline depends on the availability of crude oil produced in the areasaccessible to the Partnership’s crude oil pipeline.  If there were a material decrease in thevolume of crude oil shipped on the pipeline due to reduced production from itsshippers, less expensive supplies of crude oil available to the markets servedby the Partnership’s pipeline, competition from trucks or reduced demand forrefined product, such events may adversely affect the Company’s revenues andcash flow from the pipeline operations.

 

***We depend on third parties for the naturalgas the Partnership processes and the NGLs it fractionates at its facilities,and any reduction in these quantities could reduce our revenues and cash flow.***

 

Althoughthe Partnership obtains the supply of natural gas and NGLs from numerous thirdparty producers, a significant portion is supplied by a limited number of keyproducers/suppliers who are committed to us under processing contracts.  However, pursuant to many of these contractsor other supply arrangements, the producers are under no obligation to delivera specific quantity of natural gas or NGLs to the Partnership’sfacilities.  If these key suppliers or asignificant number of other producers were to decrease materially the supply ofnatural gas or NGLs to the Partnership’s systems and facilities for any reason,the Partnership could experience difficulty in replacing those lostvolumes.  Because our operating costs areprimarily fixed, a reduction in the volumes of natural gas or NGLs delivered tothe Partnership would result not only in a reduction of revenues but also adecline in net income and cash flow of similar or greater magnitude.

 

***The fees charged to third parties under thePartnership’s gathering, processing, transmission, transportation,fractionation and storage agreements may not escalate sufficiently to coverincreases in costs and the agreements may not be renewed or may be suspended insome circumstances.***

 

ThePartnership’s costs may increase at a rate greater than the rate that the feesit charges to third parties increase pursuant to our contracts with them.  Furthermore, third parties may not renewtheir contracts with the Partnership. Additionally, some third parties’ obligations under their agreementswith the Partnership may be permanently or temporarily reduced upon theoccurrence of certain events, some of which are beyond our control, includingforce majeure events wherein the supply of either natural gas, NGLs or crudeoil are curtailed or cut off.  Forcemajeure events include (but are not limited to) revolutions, wars, acts ofenemies, embargoes, import or export restrictions, strikes, lockouts, fires,storms, floods, acts of God, explosions, mechanical or physical failures ofequipment or facilities of the Partnership or third parties.  If the escalation of fees is insufficient tocover increased costs, if third parties do not renew or extend their contractswith the Partnership or if any third party suspends or terminates its contractswith the Partnership, our financial results would be negatively impacted.

 

***We are exposed to the credit risk of ourcustomers and counterparties, and a general increase in the nonpayment andnonperformance by our customers could reduce our revenues and cash flow.***

 

We aresubject to risks of loss resulting from nonpayment or nonperformance by ourcustomers.  Any increase in thenonpayment and nonperformance by our customers could reduce our revenues andcash flow.

 

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***We may not be able to retain existingcustomers or acquire new customers, which would reduce our revenues and limitour future profitability.***

 

Therenewal or replacement of existing contracts with our customers at ratessufficient to maintain current revenues and cash flows depends on a number offactors beyond our control, including competition from other pipelines, and theprice of, and demand for, natural gas, NGLs and crude oil in the markets weserve.  Our competitors include largeoil, natural gas, refining and petrochemical companies, some of whom havegreater financial resources and access to natural gas and NGL supplies than wedo.  Additionally, our customers whogather gas through facilities that are not otherwise dedicated to us maydevelop their own processing and fractionation facilities in lieu of using ourservices.  Certain of our competitors mayalso have advantages in competing for acquisitions or other new businessopportunities because of their financial resources and access to natural gasand NGL supplies.

 

As aconsequence of the increase in competition in the industry and volatility ofnatural gas prices, end-users and utilities are reluctant to enter intolong-term purchase contracts.  Manyend-users purchase natural gas from more than one natural gas company and havethe ability to change providers at any time. Some of these end-users also have the ability to switch between gas andalternative fuels in response to relative price fluctuations in themarket.  Because there are numerouscompanies of greatly varying size and financial capacity that compete with usin the marketing of natural gas, we often compete in the end-user and utilitiesmarkets primarily on the basis of price. The inability of our management to renew or replace our currentcontracts as they expire and to respond appropriately to changing marketconditions could have a negative effect on our profitability.  For more information regarding the competitionthat we have, please see Item 1 *Competition*.

 

***Our profitability is affected by thevolatility of NGL product and natural gas prices.***

 

Theprofitability of our operations is affected by volatility in prevailing NGLproduct and natural gas prices.  Changesin the prices of NGL products have historically correlated closely with changesin the price of crude oil.  Crude oil,NGL product and natural gas prices have been subject to significant volatilityin recent years in response to relatively minor changes in the supply anddemand for NGL products and natural gas, market uncertainty and a variety ofadditional factors that are beyond our control, including:

 

•              the level of domestic oil, natural gasand NGL production;

 

•              imports of crude oil, natural gas andNGLs;

 

•              seasonality;

 

•              the condition of the U.S. economy;

 

•              political conditions in otheroil-producing and natural gas-producing countries; and

 

•              domestic government regulation,legislation and policies.

 

Thegross margins we realize under percent-of-proceeds and percent-of-index contracts,as well as our keep-whole contracts, are directly affected by changes in NGLproduct prices and natural gas prices, and are therefore more sensitive tovolatility in commodity prices than the fee-based contracts.  Additionally, changes in natural gas pricesmay indirectly impact our profitability since prices can influence drillingactivity and well operations and thus the volume of gas we gather and processand sell.  In the past, the prices ofnatural gas and NGLs have been extremely volatile, and we expect thisvolatility to continue.

 

***We are subject to operating and litigationrisks that may not be covered by insurance.***

 

Ouroperations are subject to numerous operating hazards and risks incidental toprocessing, transporting, fractionating and storing natural gas and NGLs and totransporting and storing crude oil. These hazards include:

 

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•              damage to pipelines, plants, relatedequipment and surrounding properties caused by floods and other naturaldisasters;

 

•              inadvertent damage from construction andfarm equipment;

 

•              leakage of crude oil, natural gas, NGLsand other hydrocarbons;

 

•              fires and explosions; and

 

•              other hazards, including those associatedwith high-sulfur content, or sour gas that could also result in personal injuryand loss of life, pollution and suspension of operations.

 

As aresult, we may be a defendant in various legal proceedings and litigationarising from our operations.  We may notbe able to maintain or obtain insurance of the type and amount we desire atreasonable rates.  As a result of marketconditions, certain insurance premiums and deductibles could become unavailableor available only for reduced amounts of coverage.  For example, insurance carriers are now requiringbroad exclusions for losses due to war risk and terrorist acts.  If we were to incur a significant liabilityfor which we were not fully insured, it could have a material adverse effect onour financial position.

 

***Transportation on certain of the Partnership’spipelines may be subject to federal or state rate and service regulation, andthe imposition and/or cost of compliance with such regulation could adverselyaffect our profitability.***

 

Someof the Partnership’s gas, liquids and crude oil transmission operations may besubject to jurisdiction and rate and service regulations of the FERC or ofvarious state regulatory bodies, depending upon the factual circumstances uponwhich each pipeline’s jurisdictional status is based.  FERC generally regulates the transportationof natural gas and oil in interstate commerce, and FERC’s regulatory authorityalso extends to: facilities construction; acquisition, extension or abandonmentof services or facilities; accounts and records; and depreciation and amortizationpolicies.  Intrastate natural gaspipeline operations are generally not subject to regulation by FERC, and somegathering systems are specifically exempted from FERC regulation by the NaturalGas Act (“NGA”), but such operations are often subject to regulation by variousagencies of the states in which they are located.  The applicable statutes and regulationsgenerally require that the our rate and term and condition of service provideno more than a fair return on the aggregate value of the facilities used torender services, and FERC rate cases can involve complex and expensiveproceedings.

 

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ThePartnership’s Appalachian pipeline carries NGLs across state lines.  The primary shipper on the pipeline isMarkWest Hydrocarbon, who has entered into agreements with the Partnershipproviding 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 itsAppalachian pipeline as a common carrier and does not hold the pipeline out forservice to the public generally, there are currently no third-party shippers onthis pipeline and the pipeline is and will continue to be operated as aproprietary facility and consequently should not be subject to regulation bythe FERC.  However, we cannot provideassurance that FERC would not determine that such transportation is within itsjurisdiction.  In such a case, thePartnership would be required to file a tariff for such transportation withFERC and provide a cost justification for the transportation charge.  MarkWest Hydrocarbon has agreed to notchallenge the status of the Partnership’s Appalachian pipeline or thetransportation charge during the term of the agreements with MarkWestHydrocarbon and, moreover, the likelihood of other entities seeking to utilizethe Partnership’s Appalachian pipeline is remote.  However, the Partnership cannot predictwhether an assertion of FERC jurisdiction might be made with respect to thispipeline, nor provide assurance that such an assertion would not adverselyaffect its results of operations.  Withrespect to the Michigan Crude Pipeline, one shipper recently contacted FERC toinquire about a transportation rate increase and the pipeline’s regulatory ratestructure.  In response, FERC requestedthat the Partnership contact the shipper to initiate a discussion with theshipper regarding its questions.  ThePartnership is presently in discussions with all shippers regarding ratestructures and is attempting to resolve any issues they may have.  FERC also requested that the Partnership filea tariff.  While the Michigan CrudePipeline operations are entirely within the state of Michigan and have beenregulated by the State of Michigan, the Partnership has calculated anddetermined that its current and proposed rate structures are well below rateswhich would be allowed under FERC’s cost of service rate making structure.  However, we cannot predict whether a FERCjurisdictional challenge might be made with respect to the Michigan CrudePipeline, nor provide assurance that such a development would not adverselyaffect our results of operations or cash flow.

 

***Our business is subject to federal, stateand local laws and regulations with respect to environmental, safety and otherregulatory matters, and the violation of or the cost of compliance with suchlaws and regulations could adversely affect our profitability.***

 

Ourbusiness is subject to the jurisdiction of numerous governmental agencies thatenforce complex and stringent laws and regulations with respect to a wide rangeof environmental, safety and other regulatory matters.  We could be adversely affected by increasedcosts due to more strict pollution control requirements or liabilitiesresulting from non-compliance with required operating or other regulatorypermits.  New environmental laws andregulations might adversely impact our products and activities, including thegathering, processing, transportation, fractionation, and storage of naturalgas and NGLs and the transportation and storage of crude oil.  Federal, state and local agencies also couldimpose additional safety requirements, any of which could affect ourprofitability.  In addition, we face therisk of accidental releases or spills associated with our operations, whichcould result in material costs and liabilities, including those relating toclaims for damages to property and persons. Failure by us to comply with environmental or safety related laws andregulations could result in the assessment of administrative, civil andcriminal penalties, the imposition of investigatory and remedial obligationsand even the issuance of injunctions that restrict or prohibit the performanceof our operations.  For more informationregarding the environmental, safety and other regulatory matters that couldaffect our business, please see Item 1 *RegulatoryMatters*and *Environmental Matters*.

 

***We are indemnified for liabilities arisingfrom an ongoing remediation of property on which the Partnership’s facilitiesare located and our results of operation and the Partnership’s ability to makepayments of principal and interest on the notes could be adversely affected ifthe indemnifying party fails to perform its indemnification obligation.***

 

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The previous owner/operator of the Partnership’sBoldman and Cobb facilities has been or is currently involved in investigatoryor remedial activities with respect to the real property underlying thesefacilities pursuant to an “Administrative Order by Consent for Removal Actions”with EPA Regions II, III, IV, and V in September 1994 and an “Agreed Order”entered into with the Kentucky Natural Resources and Environmental ProtectionCabinet in October 1994.  The previousowner/operator has agreed to retain sole liability and responsibility for, andindemnify MarkWest Hydrocarbon against, any environmental liabilitiesassociated with the EPA Administrative Order, the Kentucky Agreed Order or anyother environmental condition related to the real property prior to theeffective dates of MarkWest Hydrocarbon’s agreements pursuant to which MarkWestHydrocarbon leased or purchased the real property.  In addition, the previous owner/operator hasagreed to perform all the required response actions at its cost and expense ina manner that minimizes interference with MarkWest Hydrocarbon’s use of theproperties.  On May 24, 2002, MarkWestHydrocarbon assigned to the Partnership the benefit of this indemnity from theprevious owner/operator.  Our results ofoperation and the Partnership’s ability to make cash distributions to itsunitholders could be adversely affected if in the future the previousowner/operator fails to perform under the indemnification provisions of whichwe are the beneficiary.

 

***The amount of gas the Partnership processes, gathers andtransmits or the crude oil it gathers and transports may be reduced if thepipelines to which the Partnership delivers the natural gas or crude oil cannotor will not accept the gas or crude oil.***

 

All of the natural gas the Partnership processes,gathers and transmits is delivered into pipelines for further delivery toend-users.  If these pipelines cannot orwill not accept delivery of the gas due to downstream constraints on the pipeline,the Partnership will be forced to limit or stop the throughput of gas throughits pipelines and processing systems.  Inaddition, interruption of pipeline service upstream of the Partnership’sprocessing facilities would likewise limit or stop throughput through itsprocessing facilities.  Likewise, if thepipelines into which the Partnership delivers crude oil is interrupted, thePartnership will be limited in, or prevented from, conducting crude oiltransportation operations.  Suchinterruptions or constraints on pipeline service may be caused by any number offactors beyond the Partnership’s control, including necessary and scheduledmaintenance as well as unexpected damage to the pipeline.  Since our revenues and gross margin dependupon the volumes of natural gas the Partnership processes, gathers andtransmits, the throughput of NGLs through the Partnership’s transportation,fractionation and storage facilities and the volume of crude oil it gathers andtransports, any such limitation or reduction of volumes could result in amaterial reduction in our gross margin.

 

***Our business would be adversely affected ifoperations at any of the Partnership’s facilities were interrupted.***

 

The Partnership’s operations are dependent upon theinfrastructure that it has developed, including processing and fractionationplants, storage facilities and various means of transportation. Any significantinterruption at these facilities or pipelines or the Partnership’s inability totransmit natural gas or NGLs, or transport crude oil to or from these facilitiesor pipelines for any reason would adversely affect our results of operations.Operations at the Partnership’s facilities could be partially or completelyshut down, temporarily or permanently, as the result of any number ofcircumstances that are not within the Partnership’s control, such as:

 

•                                          unscheduled turnarounds orcatastrophic events at the physical plants;

 

•                                          labor difficulties that resultin a work stoppage or slowdown; and

 

•                                          a disruption in the supply ofcrude oil to the Partnership’s crude oil pipeline, natural gas to itsprocessing plants or gathering pipelines, or a disruption in the supply of NGLsto the Partnership’s transportation pipeline and fractionation facility.

 

***Due to the Partnership’s lack of assetdiversification, adverse developments in the Partnership’s gathering,processing, transportation, transmission, fractionation and storage businesswould reduce the Partnership’s ability to make distributions to itsunitholders.***

 

We rely on the revenues generated from the Partnership’s gathering,processing, transportation, transmission, fractionation and storage businesses.Due to the Partnership’s lack of asset diversification, an adverse

 

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development in one of thesebusinesses would have a significantly greater impact on our financial conditionand results of operations than if we maintained more diverse assets.

 

***We have found materialweaknesses in our internal controls that require remediation and concluded,pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, that our internalcontrols over financial reporting at December 31, 2004 were not effective.***

 

As we disclose in our Management’s Report on InternalControl over Financial Reporting in Part II, *Controlsand Procedures,*of this Form 10-K, we have discovered deficiencies,including material weaknesses, in our internal control over financialreporting.  While we are taking immediatesteps to correct our internal control weaknesses, the material weaknesses thathave been discovered will not be considered remediated until the new andimproved internal controls operate for a period of time, are tested and it isconcluded that such new and improved internal controls are operatingeffectively.  Pending the successfulcompletion of such testing and the hiring of additional personnel, we willperform mitigating procedures relating to our internal control weaknesses.  If we fail to remediate any materialweaknesses, we could be unable to provide timely and reliable financial information,which could have a material adverse effect on our business, results ofoperations or financial condition.

 

In addition, as the Company was unable to deliver itsaudited consolidated financial statements within 90 days of December 31, 2004,the Company is not in compliance with its debt covenants for the creditfacility.  The lending institutions ofour credit facility have waived the delivery requirement until November 15,2005.

 

The Partnership has agreed to file an exchange offerregistration statement, or under certain circumstances, a shelf registrationstatement, pursuant to a registration rights agreement relating to the 2004senior notes.  On February 22, 2005 thePartnership filed the exchange offer registration statement relating to the2004 senior notes.  The Partnershipfailed to complete the exchange offer in the time provided for in thesubscription agreements and as a consequence is incurring an interest ratepenalty of 0.5%, increasing 0.25% every 90 days thereafter up to 1%, until suchtime as the exchange offer is completed.

 

In addition, the inability of the Company and thePartnership to file the Annual Report on Form 10-K for the year ended December31, 2004 on time may impact the timing of the Company’s and the Partnership’sability to raise equity in the future. We will no longer have the ability to incorporate by reference into theregistration statements for one-year following the filing of the Form 10-Kshould the Company or the Partnership choose to raise capital through a publicoffering of registered debt or equity securities.  In effect, if the Company or the Partnershipraises additional capital through public debt or equity offerings, the Companyor the Partnership will be required to file a Form S-1 registration statement, whichis a long form type of registration statement. The requirement to file a Form S-1 registration statement may affect ourability or the Partnership’s ability to access the capital markets on a timelybasis and may increase the costs of doing so.

 

62

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**ITEM7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK**

 

Market risk includes therisk of loss arising from adverse changes in market rates and prices.  Weface market risk from commodity price changes and to a lesser extent interestrate changes.

 

*CommodityPrice*

 

Through our consolidatedsubsidiary, MarkWest Energy, we are engaged in the gathering, processing andtransmission of natural gas, the transportation, fractionation and storage ofNGLs and the gathering and transportation of crude oil. We also market naturalgas and NGL products. Our products are commodities that are subject to pricerisk resulting from material changes in response to fluctuations in supply anddemand, general economic conditions and other market conditions, such asweather patterns, over which we have no control.

 

Our primary riskmanagement objective is to reduce volatility in our cash flows.  Acommittee, which includes members of senior management, oversees all of ourhedging activity.

 

We may utilize acombination of fixed-price forward contracts, fixed-for-floating price swapsand options available in the over-the-counter (“OTC”) market.  We may alsoenter into futures contracts traded on the New York Mercantile Exchange(“NYMEX”).  Swaps and futures contractsallow us to protect our margins because corresponding losses or gains on thefinancial instruments are generally offset by gains or losses in the physicalmarket.

 

We enter OTC swaps withfinancial institutions and other energy company counterparties. We conduct astandard credit review on counterparties and have agreements containingcollateral requirements where deemed necessary. We use standardized swap agreements that allow for offset of positiveand negative exposures.  We are subjectto margin deposit requirements under OTC agreements (with non-bankcounterparties) and NYMEX positions.

 

The use of financialinstruments may expose us to the risk of financial loss in certaincircumstances, including instances when (i) NGLs do not trade at historicallevels relative to crude oil, (ii) sales volumes are less than expectedrequiring market purchases to meet commitments, or (iii) our OTC counterpartiesfail to purchase or deliver the contracted quantities of natural gas, NGLs orcrude oil or otherwise fail to perform.  To the extent that we engage inhedging activities, we may be prevented from realizing the benefits offavorable price changes in the physical market.  However, we are similarlyinsulated against unfavorable changes in such prices.

 

*Commodity RiskManagement Position*

 

As of December 31, 2004,we have entered into derivative instruments designed to manage the price riskof forecasted NGL and natural gas sales in 2005 as follows:

 
| **MarkWest Hydrocarbon, Inc.**      |   |       |   |
|-------------------------------------|--------|------------|--------|
| NGL Swaps:                          |   |       |   |
| NGL gallons                         |   | 11,928,000 |   |
| NGL sales price per gallon          |   | $          | 0.85   |   |
|                                |   |       |   |
| **MarkWest  Energy Partners, L.P.** |   |       |   |
| Natural Gas Swaps:                  |   |       |   |
| Natural gas MMBtu                   |   | 182,500    |   |
| Natural gas sales price per  MMBtu  |   | $          | 4.26   |   |

 

The NGL swaps are notdesigned as hedges.  As a result, changesin the fair value of the NGL swaps are reflected currently in earnings.  The natural gas swaps are designated ashedges.  As a result, changes in the fairvalue of the natural gas swaps are reflected in other comprehensive income, tothe extent the hedges are effective, or in income currently for the ineffectiveportion.

 

63

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*InterestRate Risk*

 

Although we had no debtoutstanding with a floating interest rate at December 31, 2004, we would beexposed to changes in interest rates in the future if we were to draw on ourcredit facility or the Partnership’s credit facility.  We may make use of interest rate swapagreements in the future to adjust the ratio of fixed and floating rates in ourdebt portfolio.

 

64

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## **ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA**

## ** **

# **Index to Consolidated Financial Statements**

#  

 
| Report of KPMG LLP,  Independent Registered Public Accounting Firm                                                                       |   |   |
|------------------------------------------------------------------------------------------------------------------------------------------|--------|--------|
|                                                                                                                                     |   |   |
| Report of  PricewaterhouseCoopers, LLP, Independent Registered Public Accounting Firm                                                    |   |   |
|                                                                                                                                     |   |   |
| Consolidated Balance Sheets at  December 31, 2004 and 2003                                                                          |   |   |
|                                                                                                                                     |   |   |
| Consolidated Statements of  Operations for each of the three years in the period ended December 31,  2004                           |   |   |
|                                                                                                                                     |   |   |
| Consolidated Statements of  Comprehensive Income (Loss) for each of the three years in the period ended  December 31, 2004          |   |   |
|                                                                                                                                     |   |   |
| Consolidated Statements of  Changes in Stockholders’ Equity for each of the three years in the period  ended December 31, 2004 |   |   |
|                                                                                                                                     |   |   |
| Consolidated Statements of  Cash Flows for each of the three years in the period ended December 31,  2004                           |   |   |
|                                                                                                                                     |   |   |
| Notes to Consolidated  Financial Statements                                                                                              |   |   |

 

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# **REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTINGFIRM**

#  

To theBoard of Directors MarkWest Hydrocarbon, Inc.

 

Wehave audited the accompanying consolidated balance sheet of MarkWestHydrocarbon, Inc. and its subsidiaries (the Company) as of December 31,2004, and the related consolidated statements of operations, comprehensiveincome, changes in capital, and cash flows for the year then ended.  These consolidated financial statements arethe responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidatedfinancial statements based on our audit.

 

Weconducted our audit in accordance with the standards of the Public CompanyAccounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtainreasonable assurance about whether the financial statements are free ofmaterial misstatement.  An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements.  An audit alsoincludes assessing the accounting principles used and significant estimatesmade by management, as well as evaluating the overall financial statementpresentation.  We believe that our auditprovides a reasonable basis for our opinion.

 

Inour opinion, the consolidated financial statements referred to above presentfairly, in all material respects, the financial position of MarkWestHydrocarbon, Inc. and subsidiaries as of December 31, 2004, and theresults of their operations and their cash flows for the year then ended, inconformity with U.S. generally accepted accounting principles.

 
| /s/ KPMG LLP |   |
|------------------------|--------|
|                   |
| Denver, Colorado       |
| October 14,  2005 |

 

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# **REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTINGFIRM**

#  

To the Board of Directors of MarkWestHydrocarbon, Inc.

 

In our opinion, theaccompanying consolidated balance sheet and the related consolidated statementsof operations, of comprehensive income (loss), of cash flows and of changes instockholder’s equity present fairly, in all material respects, the financialposition of MarkWest Hydrocarbon, Inc., a Delaware Company, and itssubsidiaries (the Company) at December 31, 2003, and the results of theiroperations and their cash flows for each of the two years in the period ended December 31,2003, in conformity with accounting principles generally accepted in the UnitedStates of America.  These financialstatements are the responsibility of the Company’s management; ourresponsibility is to express an opinion on these financial statements based onour audits.  We conducted our audits ofthese statements in accordance with the standards of the Public CompanyAccounting Oversight Board (United States), which require that we plan andperform the audit to obtain reasonable assurance about whether the financialstatements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting theamounts and disclosures in the financial statements, assessing the accountingprinciples used and significant estimates made by management, and evaluating theoverall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

As described in Note 23 to the consolidatedfinancial statements, the Company has restated its consolidated financialstatements as of and for each of the two years in the period ended December 31,2003.

 

As discussed in Note 10 to the consolidatedfinancial statements, the Company changed its method of accounting for assetretirement obligations in accordance with Statement of Financial AccountingStandards No. 143 on January 1, 2003.

 
| /s/ PricewaterhouseCoopers LLP                                                                                                                                                                     |   |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|
|                                                                                                                                                                                                         |   |
| Denver, Colorado                                                                                                                                                                                             |   |
| March 30, 2004, except as to the reclassifications  described in Note 2, the 2004 stock dividend described in Note 12, and the  restatements described in Note 23, as to which the date is October 17, 2005. |   |
|                                                                                                                                                                                                              |        |  |

 

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# **MARKWEST HYDROCARBON, INC.**

# **CONSOLIDATED BALANCE SHEETS**

**(in thousands, except share and pershare data)**

 
| ** **                                                                                                                                                 | ** **                                           | **December 31,** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------------------|------------------------------------------------------|-----------------------|------------|
| ** **                                                                                                                                                 | ** **                                           | **2004**              | ** ** | **2003** | ** ** |
| ** **                                                                                                                                                 | ** **                                           | ** **            | ** ** | **(as restated,  see note 23)** | ** ** |
| **ASSETS**                                                                                                                                                 | ** **                                           | ** **            | ** ** | ** ** | ** ** |
| Current assets:                                                                                                                                            |                                                 |                  |       |   |   |
| Cash and cash  equivalents                                                                                                                                 |                                                 | $                     | 12,844     |   | $ | 42,144 |   |
| Restricted cash                                                                                                                                            |                                                 | 15,000                |       | — |   |
| Marketable  securities                                                                                                                                     |                                                 | 14,815                |       | — |   |
| Restricted  marketable securities                                                                                                                          |                                                 | —                |       | 2,500 |   |
| Receivables,  including related party receivables of $44 and $40, respectively, and net of  allowance for doubtful accounts of $249 and $120, respectively |                                                 | 64,856                |       | 29,910 |   |
| Inventories                                                                                                                                                |                                                 | 11,292                |       | 5,548 |   |
| Prepaid  replacement natural gas                                                                                                                           |                                                 | 10,245                |       | 5,940 |   |
| Deferred income  taxes                                                                                                                                     |                                                 | 25                    |       | 534 |   |
| Other assets                                                                                                                                               |                                                 | 1,898                 |       | 503 |   |
| Total current  assets                                                                                                                                      |                                                 | 130,975               |       | 87,079 |   |
|                                                                                                                                                       |                                                 |                  |       |   |   |
| Property, plant and equipment                                                                                                                              |                                                 | 342,636               |       | 232,257 |   |
| Less:                                                                                                                                                      | Accumulated depreciation, depletion and amortization |                  | (59,443    | ) | (44,134 | ) |
|                                                                                                                                                       | Total property, plant and equipment, net             |                  | 283,193    |   | 188,123 |   |
|                                                                                                                                                       |                                                 |                  |       |   |   |
| Other assets:                                                                                                                                              |                                                 |                  |       |   |   |
| Intangible  assets, net of accumulated amortization of $3,640 in 2004                                                                                      |                                                 | 162,001               |       | 84 |   |
| Deferred  financing costs, net of accumulated amortization of $5,541 and $1,275,  respectively                                                             |                                                 | 13,849                |       | 3,747 |   |
| Deferred  contract costs, net of accumulated amortization of $78 in 2004                                                                                   |                                                 | 3,172                 |       | — |   |
| Deferred  offering costs                                                                                                                                   |                                                 | —                |       | 995 |   |
| Investment in  and advances to equity investee                                                                                                             |                                                 | 177                   |       | 250 |   |
| Notes  receivables from officers                                                                                                                           |                                                 | 207                   |       | 217 |   |
| Total other  assets                                                                                                                                        |                                                 | 179,406               |       | 5,293 |   |
| Total assets                                                                                                                                               |                                                 | $                     | 593,574    |   | $ | 280,495 |   |
|                                                                                                                                                       |                                                 |                  |       |   |   |
| **LIABILITIES AND STOCKHOLDERS’ EQUITY**                                                                                                              |                                                 |                  |       |   |   |
| Current liabilities:                                                                                                                                       |                                                 |                  |       |   |   |
| Accounts  payable, including related party payables of $30 and $51, respectively                                                                           |                                                 | $                     | 45,103     |   | $ | 24,052 |   |
| Accrued  liabilities                                                                                                                                       |                                                 | 30,908                |       | 16,511 |   |
| Fair value of  derivative instruments                                                                                                                      |                                                 | 1,057                 |       | 1,769 |   |
| Total current  liabilities                                                                                                                                 |                                                 | 77,068                |       | 42,332 |   |
|                                                                                                                                                       |                                                 |                  |       |   |   |
| Deferred income taxes                                                                                                                                      |                                                 | 6,258                 |       | 5,594 |   |
| Long-term debt                                                                                                                                             |                                                 | 225,000               |       | 126,200 |   |
| Fair value of derivative instruments                                                                                                                       |                                                 | —                |       | 125 |   |
| Other long-term liabilities                                                                                                                                |                                                 | 7,487                 |       | 2,901 |   |
| Non-controlling interest in consolidated subsidiary                                                                                                        |                                                 | 228,000               |       | 52,429 |   |
|                                                                                                                                                       |                                                 |                  |       |   |   |
| Commitments and contingencies (see Note 18)                                                                                                                |                                                 |                  |       |   |   |
|                                                                                                                                                       |                                                 |                  |       |   |   |
| Stockholders’ equity (Notes 2 and 12):                                                                                                                |                                                 |                  |       |   |   |
| 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, 10,821,760 and 10,601,775  shares issued, respectively                                       |                                                 | 108                   |       | 106 |   |
| Additional  paid-in capital                                                                                                                                |                                                 | 51,455                |       | 50,705 |   |
| Retained earnings  (accumulated deficit)                                                                                                                   |                                                 | (1,623                | )          | 2,406 |   |
| Accumulated  other comprehensive income (loss), net of tax                                                                                                 |                                                 | 246                   |       | (1,793 | ) |
| Treasury stock,  at cost; 63,586 and 75,930 shares, respectively                                                                                           |                                                 | (425                  | )          | (510 | ) |
| Total  stockholders’ equity                                                                                                                           |                                                 | 49,761                |       | 50,914 |   |
| Total liabilities  and stockholders’ equity                                                                                                           |                                                 | $                     | 593,574    |   | $ | 280,495 |   |

 

# **Theaccompanying notes are an integral part of these consolidated financialstatements.**

 

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# **MARKWEST HYDROCARBON, INC.**

**CONSOLIDATED STATEMENTS OFOPERATIONS**

**(in thousands, except per share data)**

** **
| ** **                                                                                                                           | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                                                                           | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                                                                           | ** ** | ** **                       | ** ** | **(as restated,  see note 23)** | ** ** | **(as restated, see  note 23)** | ** ** |
| Revenues                                                                                                                             |       | $                                | 460,113    |   | $ | 209,268 |   | $ | 155,787 |   |
|                                                                                                                                 |       |                             |       |   |   |   |   |
| Operating expenses:                                                                                                                  |       |                             |       |   |   |   |   |
| Purchased  product costs                                                                                                             |       | 363,261                          |       | 187,544 |   | 127,526 |   |
| Facility  expenses                                                                                                                   |       | 28,580                           |       | 20,957 |   | 17,145 |   |
| Selling, general  and administrative expenses                                                                                        |       | 28,132                           |       | 15,865 |   | 9,614 |   |
| Depreciation                                                                                                                         |       | 16,895                           |       | 8,795 |   | 6,016 |   |
| Amortization of  intangible assets                                                                                                   |       | 3,640                            |       | — |   | — |   |
| Accretion of  asset retirement obligation                                                                                            |       | 15                               |       | — |   | — |   |
| Impairments                                                                                                                          |       | 130                              |       | 2,187 |   | — |   |
| Total operating  expenses                                                                                                            |       | 440,653                          |       | 235,348 |   | 160,301 |   |
|                                                                                                                                 |       |                             |       |   |   |   |   |
| Income (loss)  from operations                                                                                                       |       | 19,460                           |       | (26,080 | ) | (4,514 | ) |
|                                                                                                                                 |       |                             |       |   |   |   |   |
| Other income and (expense):                                                                                                          |       |                             |       |   |   |   |   |
| Interest income                                                                                                                      |       | 647                              |       | 106 |   | 65 |   |
| Interest expense                                                                                                                     |       | (9,383                           | )          | (4,347 | ) | (2,474 | ) |
| Amortization of  deferred financing costs (a component of interest expense)                                                          |       | (5,281                           | )          | (2,104 | ) | (4,343 | ) |
| Gain on sale of  non-operating assets                                                                                                |       | —                           |       | — |   | 5,454 |   |
| Dividend income                                                                                                                      |       | 259                              |       | — |   | — |   |
| Miscellaneous  income (expense)                                                                                                      |       | 788                              |       | (92 | ) | (73 | ) |
| Income (loss)  from continuing operations before non-controlling interest in net income of  consolidated subsidiary and income taxes |       | 6,490                            |       | (32,517 | ) | (5,885 | ) |
|                                                                                                                                 |       |                             |       |   |   |   |   |
| Provision (benefit) for income taxes:                                                                                                |       |                             |       |   |   |   |   |
| Current                                                                                                                              |       | 20                               |       | (13,680 | ) | — |   |
| Deferred                                                                                                                             |       | 58                               |       | 595 |   | (3,057 | ) |
| Provision  (benefit) for income taxes                                                                                                |       | 78                               |       | (13,085 | ) | (3,057 | ) |
|                                                                                                                                 |       |                             |       |   |   |   |   |
| Non-controlling interest in net income of  consolidated subsidiary                                                                   |       | (7,315                           | )          | (2,988 | ) | (1,947 | ) |
|                                                                                                                                 |       |                             |       |   |   |   |   |
| Loss from  continuing operations                                                                                                     |       | (903                             | )          | (22,420 | ) | (4,775 | ) |
|                                                                                                                                 |       |                             |       |   |   |   |   |
| Discontinued operations (Note 6):                                                                                                    |       |                             |       |   |   |   |   |
| Income from  discontinued exploration and production operations (less applicable income  taxes of $962 in 2003 and $1,123 in 2002)   |       | —                           |       | 1,095 |   | 1,766 |   |
| Gain from  disposal of discontinued exploration and production operations (less  applicable income taxes of $6,322)                  |       | —                           |       | 10,348 |   | — |   |
| Income from  discontinued operations                                                                                                 |       | —                           |       | 11,443 |   | 1,766 |   |
|                                                                                                                                 |       |                             |       |   |   |   |   |
| Loss before  cumulative effect of accounting change                                                                                  |       | (903                             | )          | (10,977 | ) | (3,009 | ) |
|                                                                                                                                 |       |                             |       |   |   |   |   |
| Cumulative  effect of change in accounting for asset retirement obligations, net of  income taxes                                    |       | —                           |       | (29 | ) | — |   |
|                                                                                                                                 |       |                             |       |   |   |   |   |
| Net loss                                                                                                                             |       | $                                | (903       | ) | $ | (11,006 | ) | $ | (3,009 | ) |
|                                                                                                                                 |       |                             |       |   |   |   |   |
| Loss from continuing operations per share (Note 12):                                                                                 |       |                             |       |   |   |   |   |
| Basic                                                                                                                                |       | $                                | (0.08      | ) | $ | (2.17 | ) | $ | (0.46 | ) |
| Diluted                                                                                                                              |       | $                                | (0.08      | ) | $ | (2.17 | ) | $ | (0.46 | ) |
|                                                                                                                                 |       |                             |       |   |   |   |   |
| Net loss per share (Note 12):                                                                                                        |       |                             |       |   |   |   |   |
| Basic                                                                                                                                |       | $                                | (0.08      | ) | $ | (1.07 | ) | $ | (0.29 | ) |
| Diluted                                                                                                                              |       | $                                | (0.08      | ) | $ | (1.07 | ) | $ | (0.29 | ) |
|                                                                                                                                 |       |                             |       |   |   |   |   |
| Weighted average  number of outstanding shares of common stock (Note 12):                                                            |       |                             |       |   |   |   |   |
| Basic                                                                                                                                |       | 10,686                           |       | 10,328 |   | 10,285 |   |
| Diluted                                                                                                                              |       | 10,740                           |       | 10,347 |   | 10,301 |   |

 

Theaccompanying notes are an integral part of these consolidated financialstatements.

 

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# **MARKWEST HYDROCARBON, INC.**

**CONSOLIDATED STATEMENTS OFCOMPREHENSIVE INCOME (LOSS)**

**(in thousands)**

 
| ** **                                                                                                                                              | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                                                                                              | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                                                                                              | ** ** | ** **                       | ** ** | **(as restated,  see note 23)** | ** ** | **(as restated, see  note 23)** | ** ** |
| Net loss                                                                                                                                                |       | $                                | (903       | ) | $ | (11,006 | ) | $ | (3,009 | ) |
|                                                                                                                                                    |       |                             |       |   |   |   |   |
| Other comprehensive income (loss):                                                                                                                      |       |                             |       |   |   |   |   |
| Unrealized gains  on marketable securities, net of income taxes of $291                                                                                 |       | 526                              |       | — |   | — |   |
| Unrealized gains  (losses) on commodity derivative instruments accounted for as hedges, net of  income taxes of $825, $4,134 and $(7,991), respectively |       | 1,513                            |       | 6,390 |   | (13,606 | ) |
| Foreign currency  translation, net of income taxes                                                                                                      |       | —                           |       | 675 |   | 471 |   |
| Total other  comprehensive income (loss)                                                                                                                |       | 2,039                            |       | 7,065 |   | (13,135 | ) |
|                                                                                                                                                    |       |                             |       |   |   |   |   |
| Comprehensive  income (loss)                                                                                                                            |       | $                                | 1,136      |   | $ | (3,941 | ) | $ | (16,144 | ) |

 

The accompanying notes are an integral partof these consolidated financial statements.

 

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**MARKWEST HYDROCARBON, INC.**

**CONSOLIDATED STATEMENTS OFCHANGES IN**

**STOCKHOLDERS’ EQUITY**

**(in thousands)**

 
| ** **                                        | ** ** | **Shares of  Common  Stock (Note  12)** | ** ** | **Shares of  Treasury  Stock** | ** ** | **Common  Stock** | ** ** | **Additional  Paid-In  Capital** | ** ** | **Retained  Earnings  (Deficit)** | ** ** | **Accumulated  Other  Comprehensive  Income (Loss)** | ** ** | **Treasury  Stock** | ** ** | **Total  Stockholders’  Equity** | ** ** |
|---------------------------------------------------|------------|-----------------------------------------|------------|--------------------------------|------------|-------------------|------------|----------------------------------|------------|-----------------------------------|------------|------------------------------------------------------|------------|---------------------|------------|---------------------------------------|------------|
|                                              |       |                                    |       |                           |       |              |       |                             |       |                              |       |                                                 |       |                |       |                                  |       |
| Balance,  December 31, 2001                  |       | 10,308                                  |       | (60                            | )          | $                 | 105        |                             | $          | 48,597                            |       | $                                                    | 16,421     |                | $          | 4,277                                 |       | $ | (367 | ) | $ | 69,033 |   |
| Net loss,**as restated**                          |       | —                                  |       | —                         |       | —            |       | —                           |       | (3,009                            | )          | —                                               |       | —              |       | (3,009                                | )          |
| 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                                     |       |
| Treasury stock  reissued                          |       | —                                  |       | (10                            | )          | —            |       | 20                               |       | —                            |       | —                                               |       | 180                 |       | 200                                   |       |
| Balance,  December 31, 2002, **as restated** |       | 10,308                                  |       | (50                            | )          | 105               |       | 48,808                           |       | 13,412                            |       | (8,858                                               | )          | (328                | )          | 53,139                                |       |
| Exercise of  options                              |       | 294                                     |       | —                         |       | 1                 |       | 1,897                            |       | —                            |       | —                                               |       | —              |       | 1,898                                 |       |
| Treasury stock  acquired                          |       | —                                  |       | (58                            | )          | —            |       | —                           |       | —                            |       | —                                               |       | (390                | )          | (390                                  | )          |
| Treasury stock  reissued                          |       | —                                  |       | 32                             |       | —            |       | —                           |       | —                            |       | —                                               |       | 208                 |       | 208                                   |       |
| Net loss,**as restated**                          |       | —                                  |       | —                         |       | —            |       | —                           |       | (11,006                           | )          | —                                               |       | —              |       | (11,006                               | )          |
| Other  comprehensive income                       |       | —                                  |       | —                         |       | —            |       | —                           |       | —                            |       | 7,065                                                |       | —              |       | 7,065                                 |       |
| Balance,  December 31, 2003, **as restated** |       | 10,602                                  |       | (76                            | )          | 106               |       | 50,705                           |       | 2,406                             |       | (1,793                                               | )          | (510                | )          | 50,914                                |       |
| Exercise of  options                              |       | 175                                     |       | —                         |       | 2                 |       | 1,390                            |       | —                            |       | —                                               |       | —              |       | 1,392                                 |       |
| Modification of  stock options                    |       | 45                                      |       | —                         |       | —            |       | 1,994                            |       | —                            |       | —                                               |       | —              |       | 1,994                                 |       |
| Treasury stock  acquired                          |       | —                                  |       | (3                             | )          | —            |       | —                           |       | —                            |       | —                                               |       | (39                 | )          | (39                                   | )          |
| Treasury stock  reissued                          |       | —                                  |       | 15                             |       | —            |       | 68                               |       | —                            |       | —                                               |       | 124                 |       | 192                                   |       |
| Net loss                                          |       | —                                  |       | —                         |       | —            |       | —                           |       | (903                              | )          | —                                               |       | —              |       | (903                                  | )          |
| Other  comprehensive income                       |       | —                                  |       | —                         |       | —            |       | —                           |       | —                            |       | 2,039                                                |       | —              |       | 2,039                                 |       |
| Dividends paid                                    |       | —                                  |       | —                         |       | —            |       | (2,702                           | )          | (3,126                            | )          | —                                               |       | —              |       | (5,828                                | )          |
| Balance,  December 31, 2004                  |       | 10,822                                  |       | (64                            | )          | $                 | 108        |                             | $          | 51,455                            |       | $                                                    | (1,623     | )                   | $          | 246                                   |       | $ | (425 | ) | $ | 49,761 |   |

 

# **Theaccompanying notes are an integral part of these consolidated financialstatements.**

 

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# **MARKWEST HYDROCARBON, INC.**

**CONSOLIDATED STATEMENTS OF CASHFLOWS**

**(in thousands)**

 
| ** **                                                                                             | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                                             | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                                             | ** ** | ** **                       | ** ** | **(as restated,  see note 23)** | ** ** | **(as restated, see  note 23)** | ** ** |
| **Cash flows from operating activities:**                                                              |       |                             |       |   |   |   |   |
| Net loss                                                                                               |       | $                                | (903       | ) | $ | (11,006 | ) | $ | (3,009 | ) |
| Adjustments to  reconcile net income (loss) to net cash provided by operating activities:              |       |                             |       |   |   |   |   |
| Cumulative  effect of change in accounting principle                                                   |       | —                           |       | 29 |   | — |   |
| Depreciation and  depletion                                                                            |       | 16,895                           |       | 24,489 |   | 21,388 |   |
| Amortization of  intangible assets                                                                     |       | 3,640                            |       | — |   | — |   |
| Amortization of  deferred financing costs                                                              |       | 5,281                            |       | 1,689 |   | 1,366 |   |
| Amortization of  gas contract                                                                          |       | 78                               |       | — |   | — |   |
| Accretion of  asset retirement obligation                                                              |       | 15                               |       | — |   | — |   |
| Impairments                                                                                            |       | 130                              |       | 2,187 |   | — |   |
| Write-off of  deferred financing costs                                                                 |       | —                           |       | 415 |   | 2,977 |   |
| Non-controlling  interest in net income of consolidated subsidiary                                     |       | 7,315                            |       | 2,988 |   | 1,947 |   |
| Equity in loss  of investee                                                                            |       | 73                               |       | — |   | — |   |
| Unrealized  losses/(gains) on derivative instruments                                                   |       | 762                              |       | (2,469 | ) | 2,386 |   |
| Terminated  derivative contracts                                                                       |       | —                           |       | (719 | ) | — |   |
| Deferred income  taxes                                                                                 |       | 39                               |       | (2,139 | ) | (2,696 | ) |
| Stock option  compensation expense                                                                     |       | 1,994                            |       | — |   | — |   |
| Restricted unit  compensation expense                                                                  |       | 1,065                            |       | 1,357 |   | 73 |   |
| Participation  Plan compensation expense                                                               |       | 3,711                            |       | 1,303 |   | 176 |   |
| Contribution of  treasury shares to 401(k) benefit plan                                                |       | 192                              |       | 208 |   | 200 |   |
| 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 from sale  of property, plant and equipment                                                       |       | (63                              | )          | — |   | — |   |
| Gain from sale  of marketable securities                                                               |       | (37                              | )          | — |   | — |   |
| Reclassification  of Enron hedges to purchased product costs                                           |       | —                           |       | (153 | ) | (697 | ) |
| Other                                                                                                  |       | (1                               | )          | — |   | 114 |   |
| Changes in  operating assets and liabilities, net of working capital acquired in  acquisitions:        |       |                             |       |   |   |   |   |
| Increase in  receivables                                                                               |       | (34,946                          | )          | (390 | ) | (5,894 | ) |
| (Increase)  decrease in inventories                                                                    |       | (5,744                           | )          | (1,201 | ) | 1,997 |   |
| (Increase)  decrease in prepaid replacement natural gas and other assets                               |       | (4,305                           | )          | (7,380 | ) | 7,055 |   |
| Increase in  other current assets                                                                      |       | (1,395                           | )          | — |   | — |   |
| Decrease in  notes receivables from officers                                                           |       | 10                               |       | — |   | — |   |
| Decrease in  other assets                                                                              |       | 28                               |       | — |   | — |   |
| Increase in  accounts payable and accrued liabilities                                                  |       | 32,299                           |       | 8,210 |   | 11,282 |   |
| Increase  (decrease) in other long-term liabilities                                                    |       | 483                              |       | (7,190 | ) | 3,090 |   |
| Net cash  provided by (used in) operating activities                                                   |       | 26,616                           |       | (6,411 | ) | 36,301 |   |
|                                                                                                   |       |                             |       |   |   |   |   |
| **Cash  flows from investing activities:**                                                             |       |                             |       |   |   |   |   |
| Decrease  (increase) in restricted marketable securities                                               |       | 2,500                            |       | (2,500 | ) | — |   |
| Increase in  restricted cash                                                                           |       | (15,000                          | )          | — |   | — |   |
| Purchase of  marketable securities                                                                     |       | (15,053                          | )          | — |   | — |   |
| Proceeds from  sale of marketable securities                                                           |       | 1,092                            |       | — |   | — |   |
| East Texas  system acquisition                                                                         |       | (240,726                         | )          | — |   | — |   |
| Hobbs pipeline acquisition                                                                             |       | (2,275                           | )          | — |   | — |   |
| 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                                                                                  |       | (30,654                          | )          | (31,007 | ) | (31,683 | ) |
| 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 |   | — |   |
| Payments on  financing lease receivable                                                                |       | 133                              |       | — |   | — |   |
| Proceeds from  sale of property, plant and equipment                                                   |       | 216                              |       | 2,517 |   | 791 |   |
| Payment on  long-term gas purchase contracts                                                           |       | (3,250                           | )          | — |   | — |   |
| Proceeds from  sale of Partnership subordinated units                                                  |       | —                           |       | — |   | 8,173 |   |
| Investment in  equity affiliate                                                                        |       | —                           |       | (250 | ) | — |   |
| Net cash used in  investing activities                                                                 |       | (303,017                         | )          | (36,887 | ) | (22,719 | ) |
|                                                                                                        |            |                                  |            |  |  |  |  |  |  |  |

 

Theaccompanying notes are an integral part of these consolidated financialstatements.

 

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| ** **                                                                    | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                    | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                    | ** ** | ** **                       | ** ** | **(as restated,  see note 23)** | ** ** | **(as restated, see  note 23)** | ** ** |
| **Cash flows from financing activities:**                                     |       |                             |       |   |   |   |   |
| Payments for  deferred offering costs                                         |       | —                           |       | (389 | ) | — |   |
| Proceeds from  long-term debt                                                 |       | 220,100                          |       | 452,778 |   | 65,047 |   |
| Repayments of  long-term debt                                                 |       | (346,300                         | )          | (373,925 | ) | (113,947 | ) |
| Proceeds from  private placement of senior notes                              |       | 225,000                          |       | — |   | — |   |
| Payments for  debt issuance costs                                             |       | (15,643                          | )          | (4,070 | ) | (1,889 | ) |
| Proceeds from  MarkWest Energy’s initial public offering, net            |       | —                           |       | — |   | 42,975 |   |
| Proceeds from  secondary public offerings, net                                |       | 139,630                          |       | — |   | — |   |
| Proceeds from  MarkWest Energy’s private placement, net                  |       | 44,139                           |       | 9,774 |   | — |   |
| Distributions to  MarkWest Energy unitholders                                 |       | (15,350                          | )          | (7,214 | ) | (1,721 | ) |
| Payment of  dividends                                                         |       | (5,828                           | )          | — |   | — |   |
| Exercise of  stock options                                                    |       | 1,392                            |       | 1,899 |   | 2 |   |
| Purchase of  treasury shares                                                  |       | (39                              | )          | (390 | ) | — |   |
| Payment on share  purchase notes                                              |       | —                           |       | — |   | 13 |   |
| Proceeds from  sale of MarkWest Energy units                                  |       | —                           |       | 493 |   | — |   |
| Net cash  provided by (used in) financing activities                          |       | 247,101                          |       | 78,956 |   | (9,520 | ) |
|                                                                          |       |                             |       |   |   |   |   |
| Effect of exchange rate on changes on cash                                    |       | —                           |       | 76 |   | 8 |   |
|                                                                          |       |                             |       |   |   |   |   |
| Net increase (decrease) in cash and cash equivalents                          |       | (29,300                          | )          | 35,734 |   | 4,070 |   |
| Cash and cash equivalents at beginning of year                                |       | 42,144                           |       | 6,410 |   | 2,340 |   |
| Cash and cash equivalents at end of year                                      |       | $                                | 12,844     |   | $ | 42,144 |   | $ | 6,410 |   |
|                                                                          |       |                             |       |   |   |   |   |
| **Supplemental disclosures of cash flow  information:**                       |       |                             |       |   |   |   |   |
| Cash paid during  the year for:                                               |       |                             |       |   |   |   |   |
| Interest, net of  amounts capitalized                                         |       | $                                | 6,532      |   | $ | 3,868 |   | $ | 3,834 |   |
| Taxes                                                                         |       | $                                | —     |   | $ | (114 | ) | $ | (927 | ) |
|                                                                          |       |                             |       |   |   |   |   |
| **Supplemental disclosures of non-cash investing  and financing activities:** |       |                             |       |   |   |   |   |
| Construction  projects in process obligation                                  |       | $                                | 4,037      |   | $ | — |   | $ | — |   |
| Property, plant  and equipment asset retirement obligation                    |       | $                                | 377        |   | $ | 3,994 |   | $ | — |   |
| Deferred  offering costs                                                      |       | $                                | —     |   | $ | 606 |   | $ | — |   |

 

Theaccompanying notes are an integral part of these consolidated financialstatements.

 

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**MARKWEST HYDROCARBON, INC.**

**NOTES TO CONSOLIDATED FINANCIALSTATEMENTS**

 

**1.**                                      **Nature of Operations**

 

MarkWest Hydrocarbon, Inc. (MarkWestHydrocarbon or the Company) manages MarkWest Energy Partners, L.P. (MarkWestEnergy or the Partnership), a publicly-traded limited partnership engaged inthe gathering, processing and transmission of natural gas, the transportation,fractionation and storage of natural gas liquids and the gathering andtransportation of crude oil.  The Companyalso markets natural gas and NGLs. MarkWest Hydrocarbon and MarkWest Energyprovide services primarily in the Southwest, Appalachia and Michigan.

 

As of December 31,2004, the Company owns partnership interests in MarkWest Energy consisting ofthe following:

 

•                  2,469,496 subordinated units, representing a 23% limited partner interestin the Partnership; and a

 

•                  90% ownershipinterest in MarkWest Energy GP, L.L.C., the general partner of the Partnership,which owns a 2% general partner interest and all of the incentive distributionrights in the Partnership. Officers and directors of MarkWest Hydrocarbon, andone former director of MarkWest Hydrocarbon, own the remainder of the ownershipinterest in the general partner.

 

**2.****                                      Summaryof Significant Accounting Policies**

 

*Basis of Presentation*

 

TheCompany’s consolidated financial statements include the accounts of allmajority-owned or controlled subsidiaries, including the accounts of MarkWestEnergy, and have been prepared in accordance with accounting principlesgenerally accepted in the United States of America.  Intercompany balances and transactions havebeen eliminated.

 

*Principles of Consolidation*

 

TheCompany consolidates entities when it has the ability to control the operatingand financial decisions and policies of that entity. The determination of the Company’sability to control or exert significant influence over an entity involves theuse of judgment of the extent of its control or influence and that of the otherequity owners or participants of the entity. Equity investments in which we exercise significant influence but do notcontrol and are not the primary beneficiary are accounted for using the equitymethod.  Investments in which we are notable to exercise significant influence over the investee are accounted forunder the cost method.

 

*Non-Controlling Interest in Consolidated Subsidiary*

 

Thenon-controlling interest in consolidated subsidiary on the consolidated balancesheet represents the initial investment by the partners other than MarkWestHydrocarbon in the Partnership, plus those partners’ share of the net income ofthe Partnership since its initial public offering on May 24, 2002.Non-controlling interest in net income of consolidated subsidiary in theconsolidated statement of operations represents those partners’ share of thenet income of the Partnership.

 

***Use of Estimates***

** **

The preparation offinancial statements in conformity with U.S. generally accepted accountingprinciples requires management to make estimates and assumptions that affectthe reported amounts of assets and liabilities and disclosure of contingentassets and liabilities at the date of the financial statements and the reportedamounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.  Some of the most significant areas thatmanagement uses estimates and assumptions are in the valuation of identifiedintangible assets, in determining the fair value of derivative instruments, indetermining impairments of long lived assets, in establishing estimated usefullives for long-lived assets and in the determination of liabilities, if any,for legal contingencies.

 

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***Reclassifications***

** **

The Company hasreclassified certain 2002 and 2003 financial statement components to conform tothe 2004 presentation.  The December 31,2003 balance sheet separately reflects intangible assets, net, and deferredfinancing costs, net, that were previously aggregated.  The statements of operations for the yearsended December 31, 2003 and 2002 separately reflect interest expense andamortization of deferred financing costs that were previously aggregated. In addition, a loss of $0.5 million andincome of $0.2 million was reclassified from discontinued operations tocontinuing operations for the year ended December 31, 2003 and 2002,respectively, as a result of the Company retaining its interests in three wellsin Michigan, which it originally intended to dispose of in connection with thediscontinuance of its exploration and production business.

 

***Cash and Cash Equivalents***

** **

The Companyconsiders investments in highly liquid financial instruments purchased with anoriginal maturity of 90 days or less to be cash equivalents.

 

***Restricted Cash***

 

Underthe Company’s credit facility, it is required to keep a minimum available cashand/or marketable securities reserve of $15.0 million, which is to be reducedto zero in the event the Company restructures a keep whole contract with one ofits significant customers.

 

***RestrictedMarketable Securities***

 

Restrictedmarketable securities at December 31, 2003 was comprised of $2.5 millionresiding in an investment account as per the terms of the Security Agreementbetween MarkWest Hydrocarbon and a subsidiary of MarkWest Energy, MarkWestEnergy Operating Company L.L.C. The restricted marketable securities were heldon deposit to secure an intercompany support obligation to MarkWest Energyrequired by its credit facility.  During October 2004,MarkWest Energy Operating Company, L.L.C. amended and restated its credit facilitywith various financial institutions and eliminated the requirement for therestricted marketable securities as a part of the amendment and restatement.

 

***Inventories***

** **

Inventories consist of propane, butane,isobutane, natural gasoline and natural gas and are valued at the lower ofweighted average cost or market. Materials and supplies are valued at the lower of average cost orestimated net realizable value.

 

***Prepaid Replacement Natural Gas***

** **

Prepaidreplacement natural gas consists of natural gas purchased in advance of itsactual use in the Appalachia processing business. Replacement natural gas isvalued using the weighted average cost method.

 

***Property, Plant and Equipment***

** **

Property, plantand equipment are recorded at cost. Expenditures that extend the useful lives of assets arecapitalized.  Repairs, maintenance andrenewals that do not extend the useful lives of the assets are expensed asincurred.  Interest costs for theconstruction or development of long-term assets are capitalized and amortizedover the related asset’s estimated useful life. Depreciation is providedprincipally on the straight-line method over the following estimated usefullives: gas gathering facilities and processing plants, fractionation andstorage facilities, natural gas pipelines, crude oil pipelines and NGLtransportation facilities – 20 years, or the number of years ofcontractually dedicated reserves behind the Company’s facilities, whichever isshorter; buildings – 40 years; furniture, leasehold improvements and other – 3to 10 years.

 

75

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***Oil and GasProperties of Discontinued Operations***

 

Prior to theirdisposition in 2003, oil and gas properties and equipment consisted ofleasehold costs, producing and non-producing properties, oil and gas wells, andcapitalized interest. The Company used the full cost method of accounting foroil and gas properties.  Accordingly, allcosts associated with acquisition, exploration and development of oil and gasreserves were capitalized to the full cost pool.

 

Thesecapitalized costs, including estimated future costs to develop the reserves andestimated abandonment costs, net of salvage value, were amortized on aunits-of-production basis using estimates of proved reserves.  Investments in unproved properties and majordevelopment projects were not amortized until proved reserves associated withthe projects had been determined or until impairment occurred. If the resultsof an assessment of such properties indicate that the properties are impaired,the amount of impairment was added to the capitalized cost base to beamortized.

 

Depletionper unit of production (Mcfe) for each of the Company’s cost centers for theyears ended December 31, 2003 and 2002 was as follows:

 
| ** ** | ** ** | **United States** | ** ** | **Canada** | ** ** |
|------------|------------|-------------------|------------|------------|------------|
| 2003       |       | $                 | 0.80       |       | $          | 2.47 |   |
| 2002       |       | $                 | 0.68       |       | $          | 1.83 |   |

 

The capitalizedcosts included in the full cost pool were subject to a “ceiling test,” whichlimits such costs to the aggregate of the estimated present value, using a 10%discount rate, of the future net revenues from proved reserves, based oncurrent economics and operating conditions. The ceiling test included hedgingcontracts in place at the end of each year. The Company impaired its remaining U.S. properties by $1.0 millionduring the year ended December 31, 2003.

 

Sales of proved and unproved properties wereaccounted for as adjustments of capitalized costs with no gain or lossrecognized, unless such adjustments would have significantly altered therelationship between capitalized costs and proved reserves of oil and gas, inwhich case the gain or loss was recognized in the consolidated statement ofoperations.

 

***Capitalization of Interest***

** **

The Companycapitalizes interest on major projects during construction and on unprovedproperties under development.  For theyears ended December 31, 2004, 2003 and 2002, the Company capitalized $0.8million, $1.4 million and $1.9 million of interest, respectively.

 

***Valuation ofIntangibles***

 

Intangibleassets acquired in a business combination are recorded under the purchasemethod of accounting at their estimated fair values at the date of acquisition,in accordance with SFAS No. 141, *BusinessCombinations.*  The fair valuesof acquired identifiable intangible assets are determined by management usingrelevant information and assumptions. Fair value is generally calculated as the present value of estimatedfuture cash flows using a risk-adjusted discount rate, which requiressignificant management judgment with respect to revenue and expense growthrates, and the selection and use of an appropriate discount rate.  Amortization of intangibles with definitelives is calculated using the straight-line method over the estimated usefullife of the intangible asset in accordance with SFAS No. 142, *Goodwill and Other Intangible Assets*.

 

***Impairment of Long-Lived Assets***

 

In accordance with SFAS No. 144, *Accounting for**the Impairment or Disposal of Long-Lived Assets*, the Companyevaluates its long-lived assets (excluding the full cost pool), includingintangibles, for impairment when events or changes in circumstances indicate,in management’s judgment, that the carrying value of such assets may not berecoverable.  The determination of whether impairment has occurred isbased on management’s estimate of undiscounted future cash flows attributableto the assets as compared to the carrying value of the assets. If impairmenthas occurred, the amount of impairment recognized is determined by estimatingthe fair value of the assets and recording a provision for the amount by whichthe carrying value exceeds fair value. For assets identified

 

76

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to be disposed of in thefuture, the carrying value of these assets is compared to the estimated fairvalue, less the cost to sell, to determine if impairment is required.  Until the assets are disposed of, theestimate of the fair value is re-determined when related events orcircumstances change.

 

When determining whether impairment of one of the Company’slong-lived assets has occurred, the Company must estimate the undiscounted cashflows attributable to its assets or asset groups.  Such an estimate of cash flows is based onassumptions regarding the volume of reserves behind the asset and future NGLproduct and natural gas prices.  The amountof additional reserves developed by future drilling activity is dependent inpart on natural gas prices.  Projectionsof reserves, drilling activity and future commodity prices are inherentlysubjective and contingent upon a number of variable factors, many of which aredifficult to forecast.  Any significantvariance in any of these assumptions or factors could materially affect futurecash flows, which could result in the impairment of an asset.

 

***Deferred FinancingCosts***

 

Deferred financing costs are being amortized over the estimated lives ofthe related obligations, which approximates the effective interest method.  The amortization of deferred financing costsalso include the acceleration of amortization due to the refinancing ofdebt.  Total accelerated amortizationincluded in amortization of deferred financing costs for the year ended December 31,2004, 2003 and 2002 were $1.5 million, $0.4 million and $3.0 million,respectively.

 

***Deferred ContractCosts***

 

The Company entered into a series of agreementswith a gas producer in September 2004, under which the Company processesnatural gas under modified keep-whole arrangements.  In connection withthese agreements, the Company paid $3.3 million of consideration to theproducer in connection with these non-separable contracts, which are beingamortized as additional cost of the gas purchased over the term of thecontracts, October 1, 2004 through February 9, 2015.

 

***Accrued Liabilities***

** **

Accruedliabilities consist of the following (in thousands):

 
| ** **                                                 | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                 | ** ** | **2004**              | ** ** | **2003** | ** ** |
| ** **                                                 | ** ** | ** **            | ** ** | **(as restated, see note  23)** | ** ** |
| Product costs                                              |       | $                     | 14,408     |   | $ | 10,277 |   |
| Bonus and profit sharing, severance and vacation  accruals |       | 2,028                 |       | 535 |   |
| Interest payable                                           |       | 2,876                 |       | 396 |   |
| Deferred income                                            |       | 3,518                 |       | 601 |   |
| Construction in progress accruals                          |       | 2,602                 |       | — |   |
| Taxes payable                                              |       | 1,358                 |       | 550 |   |
| State income taxes payable                                 |       | 543                   |       | 603 |   |
| Phantom unit compensation accrual                          |       | 327                   |       | 467 |   |
| Other accruals                                             |       | 3,248                 |       | 3,082 |   |
| Total accrued  liabilities                                 |       | $                     | 30,908     |   | $ | 16,511 |   |

 

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***Deferred income***

 

Deferredincome represents prepayments received under fixed fee contracts to deliverNGLs at a future date.  Deferred incomeis recognized as revenue upon delivery of the product.

 

***Contingencies***

 

TheCompany is involved in various legal actions, the outcomes of which are notwithin the Company’s complete control and may not be known for prolongedperiods of time.  In some actions, theclaimants seek damages, as well as other relief, which, if granted, would requiresignificant expenditures.  The Companyrecords a liability in the consolidated financial statements for these actionswhen a loss is known or considered probable and the amount can be reasonablyestimated.  The Company reviews theseestimates each accounting period as additional information is known and adjuststhe loss accrual when appropriate.  Ifthe loss is not probable or cannot be reasonably estimated, a liability is notrecorded in the consolidated financial statements.

 

*Derivative Instruments*

 

SFAS No. 133, *Accounting for Derivative Instruments and Hedging Activities*establishes accounting and reporting standards requiring that derivativeinstruments (including certain derivative instruments embedded in othercontracts) be recorded at fair value in the consolidated balance sheet asassets or liabilities.  Changes in thefair value of a derivative instrument not designated in a qualifying hedgingrelationship are recognized currently in earnings.   For derivative instruments designated ascash flow hedges, changes in fair value, to the extent the hedge is effective,are recognized in other comprehensive income and reclassified into currentearnings when the hedged item is recognized in earnings.   Any ineffectiveness in the hedgingrelationship is recognized immediately in earnings.  For derivative instruments designated as fairvalue hedges, changes in fair value, as well as the offsetting changes in theestimated fair value of the hedged item attributable to the hedged risk, arerecognized currently in earnings. Differences between the changes in the fair values of the hedged itemand the hedging derivative instrument, if any, represent ineffectiveness andare reflected currently in earnings.  TheCompany formally documents, designates and assesses the effectiveness oftransactions receiving hedge accounting treatment.  Results of NGL and natural gas derivativetransactions are reflected in revenue and results of interest rate hedgingtransactions are reflected in interest expense. Hedge ineffectiveness on NGL and natural gas derivatives is reported inrevenue.

 

*Concentrationof Credit Risk*

** **

## **Financial instruments that subject the Company to concentrations ofcredit risk consist principally of trade accounts receivable. The Company’scustomers are concentrated within the Appalachian Basin, Michigan and Southwestgeographic areas and the retail propane, refining, petrochemical and otherenergy-based industries.  Consequently,changes within these regions and/or industries have the potential to negativelyimpact the Company’s exposure to credit risk. The concentration of credit riskin a single industry affects the Company’s overall exposure to credit riskbecause customers may be similarly affected by changes in economic or otherconditions. The Company has not experienced significant credit losses on itsreceivables.  For the year ended December 31,2004, one customer accounted for 13% of total revenues and one customeraccounted for 17% of the Company’s total accounts receivable at December 31,2004.  For the year ended December 31,2003 and 2002 there were no customers that accounted for more than 10% of totalrevenues and there were no customers that accounted for more than 10% ofaccounts receivable at December 31, 2003.**

## ** **

*TreasuryStock*

 

Treasury stockpurchases are accounted for under the cost method whereby the entire cost ofthe acquired stock is recorded as treasury stock. Treasury stock reissued isrelieved on a weighted average cost basis.

 

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*FairValue of Financial Instruments*

## ** **

*Cashand Cash Equivalents, Receivables, Accounts Payable and Other CurrentLiabilities. *Thecarrying amount approximates fair value because of the short-term maturity ofthese instruments.

 

*FairValue of Marketable Securities. *Marketablesecurities are recorded at market based on the closing price of the securitiesat the balance sheet date.

 

*FairValue of Derivative Instruments. * Fixed for-floating natural gas and NGL priceswaps are recorded at fair value in the consolidated balance sheet.

 

*Debt.*  The carrying value of the Partnership’scredit facility approximates fair value since the facility bears interest atcurrent market interest rates.  The fairvalue of the Partnership’s senior notes was approximately $225.0 million at December 31,2004 based on quoted market prices.

 

*Revenue Recognition*

 

MarkWest Hydrocarbon generates revenue from the marketing ofNGLs and, to a lesser extent, natural gas. Revenue for product sales are recognized at the time the product isdelivered and title is transferred.  ThePartnership generates the majority of its revenues from natural gas gatheringand processing, NGL fractionation, transportation and storage, and crude oilgathering and transportation. While all of these services constitute midstreamenergy operations, the Partnership provides its services pursuant to sixdifferent types of arrangements.  In manycases, the Partnership provides services under contracts that contain acombination of more than one of the arrangements.  The following is a description of thePartnership’s six arrangements.

 

•                  *Fee-basedarrangements -*Underfee-based arrangements, the Partnership receives a fee or fees for one or moreof the following services: gathering, processing, and transmission of naturalgas, transportation, fractionation and storage of NGLs, and gathering andtransportation of crude oil.  The revenuethe Partnership earns from these contracts is directly related to the volume ofnatural gas, NGLs or crude oil that flows through its systems and facilitiesand is not directly dependent on commodity prices.

 

•                  *Percent-of-proceedsarrangements -*Underpercent-of-proceeds arrangements, the Partnership generally gathers andprocesses natural gas on behalf of producers, sells the resulting residuenatural gas and NGLs at market prices and remits to the producers an agreedupon percentage of the proceeds based on an index price.  In other cases, instead of remitting cashpayments to the producer, MarkWest Energy delivers an agreed upon percentage ofthe residue gas and NGLs to the producer and sells the volumes it keeps tothird parties at market prices.

 

•                  *Percent-of-index**arrangements*- Under percent-of-index arrangements, thePartnership generally purchases natural gas at either a percentage discount toa specified index price, a specified index price less a fixed amount or apercentage discount to a specified index price less an additional fixed amount.MarkWest Energy then gathers and delivers the natural gas to pipelines where itresells the natural gas at the index price.

 

•                  *Keep-wholearrangements* -Under keep-whole arrangements, the Partnership gathers natural gas from theproducer, processes the natural gas and sells the resulting NGLs to thirdparties at market prices.  Because theextraction of the NGLs from the natural gas during processing reduces the Btucontent of the natural gas, the Partnership must either purchase natural gas atmarket prices for return to producers or make cash payment to the producersequal to the difference in the energy content of the natural gas stream beforeand after processing.

 

•                  *Settlementmargin -*Undersettlement margin, the Partnership is allowed to retain a fixed percentage ofthe natural gas volume gathered to cover the compression fuel charges and deemedline losses.  To the extent thePartnership’s gathering systems are operated more efficiently than specifiedper contract allowance, we are entitled to retain the difference for its ownaccount.

 

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•                  *Condensatesales -* Duringthe gathering process, thermodynamic forces contribute to changes in operatingconditions of the natural gas flowing through the pipeline infrastructure.  As a result, hydrocarbon dew points arereached, causing condensation of hydrocarbons in the high-pressurepipelines.  Under these arrangements,condensate collected in the system is retained by us and sold at market prices.

 

Underall six arrangements, revenue is recognized at the time the product isdelivered and title is transferred.  Itis upon delivery and title transfer that the Partnership meets all four revenuerecognition criteria, and it is at such time that the Partnership recognizesrevenue.

 

ThePartnership’s assessment of each of the four revenue recognition criteria asthey relate to its revenue producing activities is as follows:

 

*Persuasive evidence of an arrangement exists.*The Partnership’s customary practiceis to enter into a written contract, executed by both the customer and thePartnership.

 

*Delivery.*Delivery is deemed to haveoccurred at the time the product is delivered and title is transferred, or inthe case of fee-based arrangements, when the services are rendered.  Tothe extent we retain our equity liquids as inventory, delivery occurs when theinventory is subsequently sold and title is transferred to the third partypurchaser.

 

*The fee is fixed or determinable.* The Partnership negotiates thefee for its services at the outset of its fee-based arrangements. In thesearrangements, the fees are nonrefundable. The fees are generally due within tendays of delivery or services rendered. For other arrangements, the amount of revenue is determinable when thesale of the applicable product has been completed upon delivery and transfer oftile. Proceeds from the sale of products are generally due in ten days.

 

*Collectibility is probable.* Collectibilityis evaluated on a customer-by-customer basis. New and existing customers aresubject to a credit review process, which evaluates the customers’ financialposition (e.g. cash position and credit rating) and their ability to pay. Ifcollectibility is not considered probable at the outset of an arrangement inaccordance with the Partnership’s credit review process, revenue is recognizedwhen the fee is collected.

 

Gas volumes received may be different from gas volumesdelivered resulting in gas imbalances.  The Company records a receivableor payable for such imbalances based upon the contractual terms of the purchaseagreements.   The Company had an imbalance payable of $0.1 millionand $0.7 million and an imbalance receivable of $1.4 million and $1.9 millionat December 31, 2004 and 2003, respectively.  Revenues for the transportation of crude arebased upon regulated tariff rates and the related transportation volumes andare recognized when delivery of crude is made to the purchaser or other commoncarrier pipeline.

 

***Stock and Incentive Compensation Plans***

** **

As permitted under SFAS No. 123,*Accounting for Stock-Based Compensation,*theCompany has elected to continue to measure compensation costs for stock-basedand unit-based employee compensation plans as prescribed by APB No. 25, *Accounting for Stock Issued to Employees*, as permitted under SFAS No. 123, *Accounting for Stock Based Compensation*, and SFAS No. 148, *Accounting for Stock Based Compensation – Transition andDisclosure. *The Company hastwo fixed compensation plan and two variable plans, one of which is through theCompany’s consolidated subsidiary, MarkWest Energy.  The Company accounts for these plans using fixedand variable accounting as appropriate.

 

Stockoptions are issued under the Company’s 1996 Stock Incentive Plan and 1996Non-employee Director Stock Option Plan. The plans allow for the exercise ofstock options using the cashless method, but only at the discretion of theCompany.  Under a cashless exercise, theCompany withholds from shares that otherwise would be issued upon the exerciseof the option, the number of shares with a fair market value equal to theoption exercise price and remits the remaining shares to the employee.  Prior to April 2004, the Company did notallow participants to exercise their stock options using the cashlessmethod.  Accordingly, compensationexpense was not recognized

 

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for stock optionsgranted unless the options were granted at an exercise price less than thequoted market price of the Company’s stock on the grant date.  In April 2004, the Company changed itspolicy to allow participants to exercise their stock options using the cashlessmethod.  Under APB 25, *Accounting for Stock Issued to Employees,*afixed stock option plan that permits the use of a cashless exercise becomesvariable if a pattern of exercising the stock options using the cashless methodis demonstrated.  As a result, in April 2004,the Company was required to account for stock options issued under the plans asvariable awards.  Compensation expensefor stock options issued as variable awards is measured as the difference inthe market value of the Company’s common stock and the exercise price of thestock options.  The difference isamortized into earnings over the period of service, adjusted quarterly for thechange in the fair value of the unvested stock options awarded.  Increases or decreases in the market value ofthe Company’s common stock between April of 2004 and the end of eachreporting period result in a change in the measure of compensation for vestedawards, which is reflected currently in operations.  The Company recorded compensation expense foroptions granted under the plans accounted for as variable awards of $1.6million for the year ended December 31, 2004.  During the year ended December 31, 2004,recipients exercised their options to purchase an aggregate of 226,734 sharesof the Company’s common stock. Recipients exercised options for 125,960 shares using the cashlessmethod resulting in the net issuance of 44,816 shares of common stock.  During the three months ended March 31,2004, two officers resigned from the Company. As the former officers continued to serve on the Company’s Board ofDirectors, the Company agreed that the individual’s stock options wouldcontinue to vest and be exercisable in accordance with the original vesting andexercise provisions.  As a result of the modificationto the stock options for these officers the outstanding stock options are to beaccounted for as variable awards, and as a result, the Company recordedcompensation expense of $0.4 million for the three months ended March 31,2004, measured as the difference in the market value of the Company’s commonstock on the date the officer’s status changed and the strike price of theoutstanding stock options.  These chargesare included in selling, general and administrative expenses.

 

TheCompany has also entered into arrangements with certain directors and officersof the Company.  These arrangements arereferred to as the Participation Plan. Under the Participation Plan, the Company sells subordinated partnershipunits of the Partnership and interests in the Partnership’s general partner toemployees and directors of the Company under a purchase and saleagreement.  In accordance with theprovisions of APB No. 25, *Accountingfor Stock Issued to Employees,* and EITF No. 95-16, *Accounting for Stock Compensation Arrangements withEmployer Loan Features*,**theParticipation Plan is accounted for as a variable plan.  Since the employee and director are 100%vested on the date they purchase the subordinated units or general partnerinterests, compensation expense for the subordinated units is measured as thedifference in the market value of the subordinated Partnership units and theamount paid by those individuals. Compensation related to the general partner interest is calculated asthe difference in the formula value and the amount paid by thoseindividuals.  The formula value is theamount MarkWest Hydrocarbon would have to pay the directors and employees torepurchase the general partner interests and is based on the current marketvalue of the Partnership’s common units and the current quarterly distributionpaid by the Partnership.  Increases ordecreases in the market value of the subordinated units and the formula valueof the general partner interests between the date they are acquired and the endof each reporting period result in a change in the measure of compensation,which is reflected currently in operations. The Company recorded compensation expense under the Participation Planof $3.7 million, $1.3 million and $0.2 million for the years ended December 31,2004, 2003 and 2002, respectively. These charges are included in selling,general and administrative expenses.

 

ThePartnership issues restricted units under the MarkWest Energy Partners, L.P.Long-Term Incentive Plan.  A restrictedunit is a “phantom” unit that entitles the grantee to receive a common unitupon the vesting of the phantom unit, or at the discretion of the CompensationCommittee, cash equivalent to the value of a common unit.  In accordance with APB No. 25, thePartnership applies variable accounting for the plan because a phantom unit isan award to an employee entitling them to increases in the market value of thePartnership’s units subsequent to the date of grant without issuing units tothe employees, similar to a stock appreciation right.  As a result, the Partnership is required tomark to market the awards at the end of each reporting period.  Compensation expense is measured for thephantom unit grants using the market price of MarkWest Energy’s common units onthe date the units are granted.  The fairvalue of the units awarded is amortized into earnings over the period ofservice, adjusted quarterly for the change in the fair value of the unvestedunits granted.  The phantom units vestover a stated period.  For certain employeesvesting is accelerated if certain performance measures are met.  The accelerated vesting criteria provisionsare based on annualized distribution goals. If the Partnership’s distributions are at or above the goal for acertain number of consecutive quarters, vesting of the employee’s phantom unitsis accelerated.  However,

 

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the vesting of anyphantom units may not occur until at least one year following the date ofgrant.  The general partner of thePartnership may also elect to accelerate the vesting of outstanding awards,which results in an immediate charge to operations for the unamortized portionof the award.  The Partnership recordedcompensation expense under the Long-Term Incentive Plan of $1.1 million, $1.4million and $0.1 million for the years ended December 31, 2004, 2003 and2002, respectively.  These charges areincluded in selling, general and administrative expenses.

 

Hadcompensation cost for the Company’s stock-based and unit-based compensationplans been determined based on the fair value at the grant dates under thoseplans consistent with the method prescribed by SFAS No. 123, *Accounting for Stock-Based Compensation,*the Company’s netincome and earnings per share would have been reduced to the pro forma amountslisted below (in thousands, except per share data):

 
| ** **                                                                                                                                   | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                                                                                   | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                                                                                   | ** ** | ** **                       | ** ** | **(as restated, see  note 23)** | ** ** | **(as restated, see  note 23)** | ** ** |
|                                                                                                                                         |       |                             |       |   |   |   |   |
| Net loss, as  reported                                                                                                                       |       | $                                | (903       | ) | $ | (11,006 | ) | $ | (3,009 | ) |
| Add:  compensation expense included in reported net loss                                                                                     |       | 6,770                            |       | 2,701 |   | 249 |   |
| Deduct: total  stock-based employee compensation expense determined under fair value based  method for all awards, net of related tax effect |       | (4,681                           | )          | (2,927 | ) | (618 | ) |
| Pro forma net income  (loss)                                                                                                                 |       | $                                | 1,186      |   | $ | (11,232 | ) | $ | (3,378 | ) |
|                                                                                                                                         |       |                             |       |   |   |   |   |
| Net loss per  share:                                                                                                                         |       |                             |       |   |   |   |   |
| Basic, as  reported                                                                                                                          |       | $                                | (0.08      | ) | $ | (1.07 | ) | $ | (0.29 | ) |
| Basic, pro forma                                                                                                                             |       | $                                | 0.11       |   | $ | (1.09 | ) | $ | (0.33 | ) |
| Diluted, as  reported                                                                                                                        |       | $                                | (0.08      | ) | $ | (1.07 | ) | $ | (0.29 | ) |
| Diluted, pro  forma                                                                                                                          |       | $                                | 0.11       |   | $ | (1.09 | ) | $ | (0.33 | ) |

 

***Income Taxes***

 

TheCompany accounts for income taxes under the asset and liability method pursuantto SFAS No. 109, *Accounting for IncomeTaxes*. Under SFAS No. 109, deferred income taxes are recognizedfor the future tax consequences attributable to differences between thefinancial statement carrying amounts of existing assets and liabilities andtheir respective tax basis and net operation loss and credit carryforwards.Deferred tax assets and liabilities are measured using enacted tax ratesexpected to apply to taxable income in the years in which those temporarydifferences are expected to be recovered or settled. The effect of any tax ratechange on deferred taxes is recognized in income in the period that includesthe enactment date of the tax rate change. Realizability of deferred tax assetsis assessed and if not more likely than not, a valuation allowance is recordedto write down the deferred tax assets to their net realizable value.

 

*ComprehensiveIncome (Loss)*

 

Comprehensive income includes net income (loss) andother comprehensive income (loss), which includes, unrealized gains and losseson commodity or interest rate derivative financial instruments accounted for ashedges and unrealized gains or losses on marketable securities accounted for asavailable for sale.

 

*Earnings(Loss) Per Share*

 

Basic earnings (loss)per share is computed on the basis of the weighted average number of shares ofcommon stock outstanding during the period. Diluted earnings per share iscomputed on the basis of the weighted average number of shares of common stockplus the effect of dilutive potential common shares outstanding during theperiod using the treasury stock method. Dilutive potential common sharesinclude outstanding stock options and stock awards.  All share information has been adjusted togive retroactive effect to stock dividends paid, see note 12.

 

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Thefollowing are the number of shares used to compute the basic and dilutedearnings per share (in thousands):

 
| ** **                                          | ** ** | **Year ended December 31,** | ** ** |
|-----------------------------------------------------|------------|----------------------------------|------------|
| ** **                                          | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
|                                                |       |                             |       |   |   |   |   |
| Basic earnings per share:                           |       |                             |       |   |   |   |   |
| Weighted average  shares outstanding                |       | 10,686                           |       | 10,328 |   | 10,285 |   |
| Dilutive earnings per share:                        |       |                             |       |   |   |   |   |
| Weighed average  limited shares outstanding         |       | 10,686                           |       | 10,328 |   | 10,285 |   |
| Dilutive effect  of exercise of options outstanding |       | 54                               |       | 19 |   | 16 |   |
| Dilutive shares                                     |       | 10,740                           |       | 10,347 |   | 10,301 |   |

 

## ***Foreign Currency Translation***

## ** **

On December 2, 2003, the Company soldall of its Canadian subsidiaries and, consequently, no longer have assets,liabilities or operations that require foreign currency translation.  Prior thereto, assets and liabilities of theCompany’s Canadian subsidiary, which used the Canadian dollar as its functionalcurrency, were translated into United States dollars at the foreign currencyexchange rate in effect at the applicable reporting date, and the statements ofoperations data were translated at the average rates in effect during the applicableperiod.  The resulting cumulativetranslation adjustment was recorded as a separate component of othercomprehensive income.

 

## ***Recent Accounting Pronouncements***

## ** **

In December 2004,the FASB issued SFAS No. 123 (revised 2004), *Shared-Based Payment*. This statement addresses the accounting for share-based paymenttransactions in which an enterprise receives employee services in exchange for (a) equityinstruments of the enterprise, or (b) liabilities that are based on thefair value of the enterprise’s equity instruments or that may be settled by theissuance of such equity instruments. SFAS No. 123(R) requires an entity to recognize the grant-datefair-value of stock options and other equity-based compensation issued toemployees in the income statement.  Therevised Statement requires that an entity account for those transactions usingthe fair-value-based method, and eliminates the intrinsic value method ofaccounting in APB No. 25, *Accountingfor Stock Issued to Employees,*which was permitted under SFAS No. 123,as originally issued.  The revisedStatement requires entities to disclose information about the nature of theshare-based payment transactions and the effects of those transactions on thefinancial statements.  SFAS 123(R) iseffective for public companies for the first fiscal year beginning after June 15,2005.  All public companies must useeither the modified prospective or the modified retrospective transitionmethod.  The Company has not yetevaluated the impact of the adoption of this pronouncement, which must beadopted in the first quarter of calendar year 2006.  On March 29, 2005, the SEC staff issuedSAB No. 107, *Share-Based Payment*,to express the views of the staff regarding the interaction between SFAS No. 123(R)and certain SEC rules and regulations and to provide the staff’s viewsregarding the valuation of share-based payment arrangements for publiccompanies.  The Company will take intoconsideration the additional guidance provided by SAB No. 107 inconnection with the implementation of SFAS No. 123(R).

 

In March 2005,the FASB issued FIN No. 47, *Accountingfor Conditional Asset Retirement Obligations,* which clarifies theaccounting for conditional asset retirement obligations as used in SFAS No. 143,*Accounting for Asset Retirement Obligations. *A conditional asset retirementobligation is an unconditional legal obligation to perform an asset retirementactivity in which the timing and (or) method of settlement are conditional on afuture event that may or may not be within the control of the entity.  An entity is required to recognize aliability for the fair value of a conditional asset retirement obligation underSFAS No. 143 if the fair value of the liability can be reasonablyestimated.  FIN 47 permits, but does notrequire, restatement of interim financial information.  The provisions of FIN 47 are effective forreporting periods ending after December 15, 2005.  The Company is currently evaluating theimpact of adopting FIN 47 on its consolidated financial statements.

 

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In May 2005, the FASB issued SFAS No. 154, *Accounting Changes and Error Corrections—areplacement of APB Opinion No. 20 and FASB Statement No. 3*.SFAS No. 154 replaces Accounting**PrinciplesBoard Opinion No. 20, *AccountingChanges*, and SFAS No. 3, *ReportingAccounting Changes in Interim Financial Statements*, and changes therequirements for the accounting for and reporting of a**change in accounting principle. Thisstatement applies to all voluntary changes in accounting principle**and also applies to changes required byan accounting pronouncement in the unusual instance that the**pronouncement does not include specifictransition provisions. The statement is effective for accounting**changes and corrections of errors made infiscal years beginning after December 15, 2005. The**Company will adopt the provisions of SFASNo. 154 beginning in calendar year 2006. Management**believes that the adoption of theprovisions of SFAS No. 154 will not have a material impact on the**Company’s consolidated financialstatements.

 

**3.****                                     InitialPublic Offering and Private Placement of MarkWest Energy Partners**

 

*Initial PublicOffering*

 

On May 24, 2002, MarkWest Hydrocarbonconveyed most of the assets, liabilities and operations of its midstreambusiness to MarkWest Energy in exchange for:

 

•                    3,000,000 subordinated limitedpartnership units, representing a 54.3% interest in the Partnership after theissuance of the common limited partnership units.

•                    A general partner interest,representing a 2.0% interest in the Partnership after issuance of the commonlimited partnership units.

•                    Incentive distribution rights (asdefined in the Partnership Agreement).

•                    The direct and indirect assumptionof certain liabilities by the Partnership, including $1.8 million in workingcapital liabilities and $19.4 million of indebtedness.

•                    The right to be reimbursed by thePartnership for $15.6 million of capital expenditures.

•                    The right to receive $26.7 millionin cash upon the closing of the initial public offering (IPO) and MarkWestEnergy Operating Company, L.L.C.’s (the Operating Company) $60.0 million creditfacility.  The Operating Company is awholly owned subsidiary of the Partnership.

 

ThePartnership issued 2,415,000 common units (including 315,000 units issuedpursuant to the underwriters’ over-allotment option), representing a 43.7%limited partnership interest in the Partnership, in an IPO at a price of $20.50per unit. The Operating Company concurrently entered into a $60.0 millionterm loan credit facility with its lenders and borrowed $21.4 million upon theclosing of the IPO.

 

Uponthe closing of the IPO, MarkWestHydrocarbon received cash totaling $63.5 million, which was funded by proceedsfrom the IPO and by Partnership borrowings under its credit facility.  The Company used the cash to repay bankindebtedness.

 

Thecommon units have preference over the subordinated units with respect to cashdistributions and, accordingly, the Company accounted for the sale of thecommon units as a sale of a non-controlling interest. The subordinated unitsautomatically convert to common units on June 30, 2009, but a portion ofthe subordinated units may convert on or after June 30, 2005 if thePartnership meets certain financial tests,, as defined in the PartnershipAgreement.

 

*Private Placement*

 

DuringNovember 2002, MarkWest Hydrocarbon sold 500,000 of its Partnershipsubordinated units to a private venture fund for $8.6 million. The saleprice was $17.146 per subordinated unit, and represented a 22% discount off thecommon unit price of MarkWest Energy over the twenty trading days prior toclosing. The discounted subordinated unit sales price relative to the marketvalue of the common units was attributable to the preference of the commonunits with respect to distributions as well as the lack of a public tradingmarket for the subordinated units. Net proceeds after transaction costs were$8.1 million. MarkWest Hydrocarbon recognized a gain on the sale of $5.5million. MarkWest Hydrocarbon granted preferential rights of conversion to thebuyer, i.e. that one-third of the 500,000 subordinated units sold will beconverted into common units at each of the first three

 

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possible conversion dates provided for in MarkWest Energy’s PartnershipAgreement.  MarkWest Hydrocarbon’s formerPresident and Chief Executive Officer and current Chairman of the Board ofDirectors indirectly acquired 13,997 of the subordinated units as a limitedpartner of the private venture fund.

 

## **4.            Marketable Securities**

## ** **

Marketablesecurities are classified as available-for-sale and stated at market based onthe closing price of the securities at the consolidated balance sheetdate.  Accordingly, unrealized gains orlosses are reflected in other comprehensive income (loss), net of applicableincome taxes.  For losses that are otherthan temporary, the cost basis of the securities is written down to fair valueand the amount of the write-down is reflected in the statement ofoperations.  The Company utilizes aweighted-average cost basis to compute realized gains and losses.  Realized gains and losses, and dividend andinterest income, are reflected in earnings.

 

Debt and equitysecurities are classified as available-for-sale.  The following are the components ofmarketable securities (in thousands):

 
| **December 31, 2004**                                          | ** ** | **Cost Basis** | ** ** | **Unrealized  gains** | ** ** | **Unrealized  losses** | ** ** | **Recorded  Basis** | ** ** |
|---------------------------------------------------------------------|------------|----------------|------------|-----------------------|------------|------------------------|------------|---------------------|------------|
| **Equity securities:**                                              |       |           |       |                  |       |                   |       |                |       |
| Master limited  partnership units                                   |       | $              | 5,248      |                  | $          | 872                    |       | $                   | (19        | ) | $ | 6,101 |   |
| Equity  securities, classified as current                           |       | 5,248          |       | 872                   |       | (19                    | )          | 6,101               |       |
| **Fixed maturities:**                                               |       |           |       |                  |       |                   |       |                |       |
| Mortgage backed  securities (due after one year through five years) |       | 8,750          |       | 10                    |       | (46                    | )          | 8,714               |       |
| Mortgage back  securities, classified as non-current                |       | 8,750          |       | 10                    |       | (46                    | )          | 8,714               |       |
| Total marketable  securities                                        |       | $              | 13,998     |                  | $          | 882                    |       | $                   | (65        | ) | $ | 14,815 |   |

 
| **December 31, 2003**                                         | ** ** | **Cost Basis** | ** ** | **Unrealized  gains** | ** ** | **Unrealized  losses** | ** ** | **Recorded  Basis** |   |
|--------------------------------------------------------------------|------------|----------------|------------|-----------------------|------------|------------------------|------------|---------------------|--------|
| **Fixed maturities:**                                              |       |           |       |                  |       |                   |       |                |   |
| Mortgage backed  securities (due December 2007)               |       | $              | 2,500      |                  | $          | —                 |       | $                   | — |   | $ | 2,500 |   |
| Total restricted  marketable securities (as restated, see note 23) |       | $              | 2,500      |                  | $          | —                 |       | $                   | — |   | $ | 2,500 |   |

 

At December 31,2004, unrealized gains of $0.9 million relate primarily to investments inequity securities of domestic energy partnerships.  Unrealized losses of $0.1 million relateprimarily to mortgage backed securities and are primarily attributable tochanges in interest rates.  Netunrealized gains on marketable securities of $0.8 million, net of the relatedtax effect of $0.3 million, are reflected as a component of other comprehensiveincome at December 31, 2004.

 

## **5.             Acquisitionsby MarkWest Energy**

## ** **

*East Texas System Acquisition*

 

On July 30,2004, the Partnership completed the East Texas System acquisition consisting ofAmerican Central Eastern Texas’ Carthage gathering system and gas processingassets located in east Texas for approximately $240.7 million.  The Company’s consolidated financialstatements include American Central Eastern Texas’ results of operations from July 30,2004.  The assets acquired consist ofprocessing plants, gathering systems, a processing facility currently underconstruction and a NGL pipeline to be constructed in 2005.

 

Inconjunction with the closing of the acquisition, the Partnership completed aprivate offering of 1,304,438 common units, at $34.50 per unit, representingapproximately $45.0 million in proceeds after transaction costs ofapproximately $0.9 million and including a contribution from the generalpartner of $0.9 million to maintain its

 

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ownership interest.  In addition,the Partnership amended and restated its credit facility, increasing itsmaximum lending limit from $140.0 million to $315.0 million.  The credit facility included a $265.0 millionrevolving facility and a $50.0 million term loan facility.  The Partnership used the proceeds from theprivate offering and borrowings of $195.7 million under the credit facility tofinance the East Texas System acquisition.

 

The total adjusted purchase price wascomprised of $240.7 million, and was allocated as follows (in thousands):

 
| Acquisition  costs:              |   |   |    |
|----------------------------------|--------|--------|---------|
| Cash  consideration              |   | $      | 240,269 |   |
| Direct  acquisition costs        |   | 457    |    |
| Total                            |   | $      | 240,726 |   |
|                             |   |   |    |
| Allocation of acquisition costs: |   |   |    |
| Customer contracts               |   | $      | 165,379 |   |
| Property, plant  and equipment   |   | 76,012 |    |
| Inventory                        |   | 65     |    |
| Imbalance  payable               |   | (337   | )       |
| Property taxes  payable          |   | (393   | )       |
| Total                            |   | $      | 240,726 |   |
|                                  |        |        |         |  |  |  |  |

 

*Hobbs Lateral Acquisition*

 

On April 1, 2004, the Partnershipacquired the Hobbs Lateral pipeline for approximately $2.3 million.  The Hobbs Lateral consisted of a four-milepipeline, with a capacity of 160 million cubic feet of natural gas per day,connecting the Northern Natural Gas interstate pipeline to Southwestern PublicService’s Cunningham and Maddox power generating stations in Hobbs, NewMexico.  The Hobbs Lateral is a NewMexico intrastate pipeline regulated by the Federal Energy RegulatoryCommission.

 

*Michigan Crude Pipeline*

 

On December 18,2003, the Partnership completed the acquisition (the “Michigan Crude Pipelineacquisition”) of Shell Pipeline Company, LP’s and Equilon Enterprises, LLC’s,Michigan Crude Gathering Pipeline, for approximately $21.3 million. The resultsof operations of the system have been included in the Partnership’s consolidatedfinancial statements since December 18, 2003. The $21.3 million purchaseprice was financed through borrowings under the Partnership’s line of credit.

 

Thesystem is a common carrier Michigan intrastate pipeline and gathers light crudeoil from wells. The system extends from production facilities near Manistee,Michigan to a storage facility near Lewiston, Michigan.  The trunk line consisted of approximately 150miles of pipe.  Crude oil is gatheredinto the System from 57 injection points, including 52 central productionfacilities and five truck unloading facilities. The oil is transported for a fee to the Lewiston station where it isbatch injected into the Enbridge Lakehead Pipeline, which then transports thecrude oil to refineries in Sarnia, Ontario, Canada.

 

Thepurchase price was comprised of $21.3 million paid in cash plus directacquisition costs 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 |   |

 

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*Western Oklahoma Acquisition*

 

On December 1, 2003, the Partnership completed theacquisition of American Central Western Oklahoma Gas Company, L.L.C. forapproximately $38.0 million.  Results ofoperations for the acquired assets have been included in the Company’sconsolidated financial statements since that date.

 

The assets acquired include the Foss Lake gatheringsystem located in the western Oklahoma counties of Roger Mills and Custer.  The acquired gathering system was comprisedof approximately 167 miles of pipeline, connected to approximately 270 wellsand 11,000 horsepower of compression facilities.   The assets also included the Arapaho gasprocessing plant.

 

The purchase price of approximately $38.0 million was financed throughborrowings under the Partnership’s credit facility.

 

The purchase price was comprised of$38.0 million paid in cash, 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 |   |

 

*Lubbock Pipeline Acquisition*

 

EffectiveSeptember 2, 2003, the Partnership, through its wholly owned subsidiary,MarkWest Pinnacle L.P., completed the acquisition (the “Lubbock PipelineAcquisition”) 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 creditfacility. The results of operations of the Lubbock Pipeline have been includedin the Company’s consolidated financial statements since that date.

 

*Pinnacle Acquisition*

 

On March 28, 2003, the Partnershipcompleted the acquisition (the “Pinnacle acquisition”) of Pinnacle Natural GasCompany, Pinnacle Pipeline Company, PNG Transmission Company, Inc., PNGUtility Company and Bright Star Gathering, Inc. (collectively, “Pinnacle”).  The assets acquired were comprised of threelateral natural gas pipelines and twenty gathering systems.  Pinnacle’s results of operations have beenincluded in the Company’s consolidated financial statements since thatdate.  The purchase price was financedthrough borrowing under the Partnership’s line of credit.

 

Thepurchase price was allocated as follows (in thousands):

 
| Acquisition  costs:                          |   |   |   |
|----------------------------------------------|--------|--------|--------|
| Long-term debt  incurred                     |   | $      | 39,471 |   |
| Direct  acquisition costs                    |   | 450    |   |
| Current  liabilities assumed                 |   | 8,945  |   |
|                                         |   | $      | 48,866 |   |
|                                         |   |   |   |
| Allocation of acquisition costs:             |   |   |   |
| Current assets                               |   | $      | 10,643 |   |
| Fixed assets (including long-term contracts) |   | 38,223 |   |
| Total                                        |   | $      | 48,866 |   |

 

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*Pro Forma Results of Operations (unaudited)*

 

Thefollowing table reflects the pro forma consolidated results of operations forthe periods presented, as though the Pinnacle acquisition, the Western Oklahomaacquisition, the Michigan Crude Pipeline acquisition and the East Texas Systemacquisition each had occurred as of the beginning of the periodspresented.  The unaudited pro formaresults have been prepared for comparative purposes only and may not be indicativeof future results.   The unaudited pro forma results of operationsfor the Hobbs Lateral acquisition and the Lubbock Pipeline acquisition have notbeen presented, as these acquisitions were not significant.  The following table is in thousands, exceptper share amounts.

 
| ** **                                                      | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                      | ** ** | **2004**                         | ** ** | **2003** | ** ** |
| ** **                                                      | ** ** | ** **                       | ** ** | **(as restated, see note 23)** | ** ** |
| Revenue                                                         |       | $                                | 480,791    |   | $ | 301,537 |   |
| Net income (loss) from continuing operations                    |       | $                                | 220        |   | $ | (28,085 | ) |
| Net income (loss) from continuing operations per  share:        |       |                             |       |   |   |
| Basic                                                           |       | $                                | 0.02       |   | $ | (2.72 | ) |
| Diluted                                                         |       | $                                | 0.02       |   | $ | (2.72 | ) |
| Weighted average number of outstanding shares of  common stock: |       |                             |       |   |   |
| Basic                                                           |       | 10,686                           |       | 10,328 |   |
| Diluted                                                         |       | 10,740                           |       | 10,347 |   |

 

**6.****             ****        DiscontinuedOperations**

 

During 2003, theCompany discontinued its exploration and production business.  Through a series of dispositions noted below,the Company sold off substantially all of its U.S. and Canadian oil and gasproperties. The dispositions were as follows:

 

*Salesof San Juan Basin Properties*

 

During the second andthird quarters of 2003, the Company completed the sales of its San Juan Basin(U.S.) oil and gas properties to certain third parties for net proceedsaggregating approximately $55.3 million. The Company recognized an aggregatenet pretax gain of $23.3 million on these sales for the year ended December 31,2003.  The proceeds from the sales wereused for working capital and general corporate purposes.

 

*Salesof Canadian Properties*

 

During December 2003,the Company completed the sales of all of its Canadian oil and gas propertiesto certain third parties for net proceeds aggregating approximately $49.1million. The Company recognized an aggregate pretax loss of $4.8 million onthese sales for the year ended December 31, 2003. The proceeds from thesales were primarily used to pay off the Company’s remaining outstanding debt,exclusive of MarkWest Energy’s debt.

 

*Saleof Eastern Michigan Properties*

 

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

 

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*FinancialStatement Impact of Discontinued Operations*

 

Forthe years ended December 31, 2003 and 2002, revenues from the Company’sdiscontinued operations were $30.1 and $31.5 million, respectively, and income(loss) from discontinued operations before income taxes was $2.1 and $2.9million, respectively.

 

Forthe years ended December 31, 2003 and 2002, the impact on both basic anddiluted net income (loss) per share from discontinued operations was $1.11 and$0.17, respectively.

 

**7.             Property, Plant and Equipment**

 

Property,plant and equipment consists of (in thousands):

 
| ** **                             | ** **                                                        | **December 31,** | ** ** |
|----------------------------------------|-------------------------------------------------------------------|-----------------------|------------|
| ** **                             | ** **                                                        | **2004**              | ** ** | **2003** | ** ** |
| Property, plant and equipment:         |                                                              |                  |       |   |   |
| Gas gathering  facilities              |                                                              | $                     | 160,763    |   | $ | 73,424 |   |
| Gas processing  plants                 |                                                              | 56,239                |       | 55,888 |   |
| Fractionation  and storage facilities  |                                                              | 22,112                |       | 22,160 |   |
| Natural gas  pipelines                 |                                                              | 38,167                |       | 38,790 |   |
| Crude oil  pipelines                   |                                                              | 18,499                |       | 18,352 |   |
| NGL  transportation facilities         |                                                              | 4,381                 |       | 4,415 |   |
| Land, buildings  and other equipment   |                                                              | 9,418                 |       | 12,499 |   |
| Furniture,  office equipment and other |                                                              | 4,113                 |       | 4,367 |   |
| Construction  in-progress              |                                                              | 28,944                |       | 2,362 |   |
|                                   |                                                              | 342,636               |       | 232,257 |   |
| Less:                                  | Accumulated depreciation, depletion, amortization  and impairment |                  | (59,443    | ) | (44,134 | ) |
|                                   | Total property, plant and equipment, net                          |                  | $          | 283,193 |   | $ | 188,123 |   |

 

During 2004,the Company recorded an impairment charge of approximately $0.1 million.  The charge related to plant processingequipment taken out of service.

 

###### *CobbProcessing Plant*

###### * *

During2003, MarkWest Hydrocarbon entered into an agreement with the Partnership forthe construction of a new Cobb processing plant.  Initially, the Partnership estimated theconstruction costs of the new plant and the costs to decommission and dismantlethe old plant to be approximately $2.1 million. In the third quarter of 2004, this estimate was revised to $3.6 millionto construct the new plant and $0.5 million to decommission and dismantle theold plant. Construction was completed in the second quarter of 2005 at a costof $3.6 million.  Upon the completion ofthe new plant, the Partnership ceased operating the existing Cobb processingplant.

 

As of December 31,2003, and in accordance with SFAS No. 144, the Partnership determined thatthe carrying value of the old processing plant of $1.4 million exceeded itsestimated fair value of $0.3 million. Consequently, the Company reflected an impairment of $1.1 million in thestatement of operations for the year ended December 31, 2003.

 

On December 31,2004, the general partner and the Partnership amended the Partnership Agreementto provide for the contribution of $1.7 million by the general partner.  In exchange for the contribution, theamendment specifies that the first $1.7 million of depreciation deductionattributable to the new plant will be allocated to the general partner.  The amendment had no impact on the MarkWestHydrocarbon’s consolidated balance sheet, results of operations and cash flows.

 

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*Dispositions*

 

Inaddition to the dispositions of substantially all of the Company’s oil and gasproperties, the Company also sold its Lordstown, Ohio terminal on July 15,2003 to a third party for approximately $0.7 million, including $0.2 millionfor on-hand inventory. On September 2, 2003, the Company sold itsLynchburg, Virginia terminal to a third party for approximately $1.2 millionplus on-hand inventory. As a result of the two sales, the Company incurred aloss in 2003 of less than $0.1 million.

 

**8.             IntangibleAssets Subject to Amortization**

 

On July 30, 2004, the Partnership completed theacquisition of American Central Eastern Texas’ Carthage gathering system andgas processing assets located in East Texas for approximately $240.7million.  Of the total purchase price,$165.4 million was allocated to amortizable identifiable intangible assets(i.e., customer contracts) based on the net present value of the projected cashflows from these contracts.  The keyvariables in determining the valuation of the customer contracts were theassumption of renewals, economic incentives to retain customers, historicalvolumes, current and future capacity of the gathering system and pricingvolatility.  The Partnership isamortizing the carrying value of these customer contracts on a straight-linebasis over their average estimated economic life of 20 years.  The estimated economic life was determined byassessing the life of the assets to which the contracts relate, likelihood ofrenewals, competitive factors, regulatory or legal provisions and maintenanceand renewal costs.

 

Other intangible assets include customer contractsacquired in 2003 for $274,000, which are being amortized through June of2005.

 

The Company’sintangible assets at December 31, 2004, are composed of customer contractswhich are being amortized over the following estimated useful lives (inthousands):

 

| ** ** | ** ** | **Gross** | ** ** | **Accumulated  Amortization** | ** ** | **Net** | ** ** |
|------------|------------|-----------|------------|-------------------------------|------------|---------|------------|
| 20 years   |       | $         | 165,379    |                          | $          | 3,446   |       | $ | 161,933 |   |
| 1 year     |       | 288       |       | 220                           |       | 68      |       |
| Total      |       | $         | 165,667    |                          | $          | 3,666   |       | $ | 162,001 |   |

 

Amortizationexpense related to the Company’s intangible assets was $3.6 million for theyear ended December 31, 2004.

 

Estimatedfuture amortization expense related to the Company’s intangible assets at December 31,2004 is as follows (in thousands):

 

| Year ending  December 31: |   |    |    |
|--------------------------------|--------|---------|---------|
| 2005                           |   | $       | 8,337   |   |
| 2006                           |   | 8,269   |    |
| 2007                           |   | 8,269   |    |
| 2008                           |   | 8,269   |    |
| 2009                           |   | 8,269   |    |
| Thereafter                     |   | 120,588 |    |
| Total                          |   | $       | 162,001 |   |

 

## **9.             Long-TermDebt**

## ** **

***MarkWestHydrocarbon***

 

*Credit Facility*

 

On October 25, 2004, the Company entered into a$25.0 million senior credit facility with a term of one year.  The $25.0 million revolving facility has avariable interest rate based on the base rate, which is equal to the

 

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higher of a) the Federal Funds Rate plus 1/2of 1%, and b) the rate of interest in effect for such day as publicly announcedfrom time to time by the Administrative Agent as its prime rate, plus theapplicable rate, which is based on a utilization percentage.  The amount available to be drawn under thecredit facility is based upon the amount of the Company’s eligible accountsreceivable and inventory.  The Company isrequired to pay a commitment fee equal to the applicable rate (as defined inthe agreement and determined by a utilization percentage) times the actualdaily amount by which the aggregate commitment exceeds the sum of (i) theoutstanding amount of loans plus (ii) the outstanding amount of theCompany’s letter of credit obligations. Substantially all of the Company’s assets and its subsidiaries (otherthan excluded MarkWest Energy entities) are pledged to the lender to secure therepayment of the outstanding borrowings under the credit facility.  The proceeds from this facility are expectedto be used to finance inventory and accounts receivable and to support lettersof credit.

 

In connection with the credit facility, the Company issubject to a number of restrictions on its business, including restrictions onits ability to grant liens on assets; merge, consolidate or sell assets; incurindebtedness; make acquisitions; engage in other businesses; enter intooperating leases; enter into certain swap contracts; engage in transactionswith affiliates; make dispositions; make restricted payments, distributions andredemptions and other usual and customary covenants.  As of December 31, 2004, the Company hadno outstanding borrowings and it had a borrowing capacity of $19.0million.  At December 31, 2004, $6.0million of this facility was used for a letter of credit issued in support ofone of the Company’s producer agreements.

 

The credit facility also contains covenants requiringthe Company to maintain:

 

•      apositive consolidated EBITDA (including cash distributions from thePartnership) for the four consecutive fiscal quarters most recently completed;

•      aminimum net worth of $40.0 million plus 50% of proceeds of equity issuedsubsequent to October 25, 2004; and

•      aminimum available cash and marketable securities reserve of $15.0 million,which is to be reduced to zero in the event the Company restructures akeep-whole contract with one of its significant customers.

 

As the Company was unable to deliver its 2004 audited consolidatedfinancial statements within 90 days of December 31, 2004, the Company wasnot in compliance with its debt covenants. The lending institutions of the Company’s credit facility have waivedthe 90 days delivery requirement until November 15, 2005.

 

***MarkWest EnergyPartners***

 

*Credit Facility*

 

InOctober 2004, the Partnership entered into the third amended and restatedcredit agreement (“Partnership Credit Facility”), which provides for a maximumlending limit of $200.0 million for a term of five years.  The credit facility includes a revolvingfacility up to $200.0 million with the potential to increase the maximumlending limit to $300.0 million.  Thecredit facility is guaranteed by the Partnership and all of its subsidiariesand is collateralized by substantially all of the Partnership’s assets andthose of its subsidiaries.  Theborrowings under the credit facility bear interest at a variable interest ratebased on one of two indices that include either (i) LIBOR plus anapplicable margin, which was fixed at a rate of 2.75% for the first twoquarters following the closing of the credit facility or (ii) Base Rate(as defined for any day, a fluctuating rate per annum equal to the higher of (a) theFederal Funds Rate plus 1⁄2 of 1% or (b) the rate of interest in effect forsuch day as publicly announced from time to time by the administrative agent ofthe debt as its “prime rate”) plus an applicable margin, which margin is fixedat a rate of 2.00% for the first two quarters following the closing of thecredit facility.  After that period, theapplicable margin adjusts quarterly based on the Partnership’s ratio of fundeddebt to EBITDA (as defined in the credit agreement).  The Partnership incurs a commitment fee on the unusedportion of the credit facility at a rate ranging from 37.5 to 50.0 basis pointsbased upon the ratio of the Partnership’s consolidated funded debt (as definedin the Partnership Credit Facility) to consolidated EBITDA (as defined in thePartnership Credit Facility) for the four most recently completed fiscalquarters.  For the years ended December 31,2004 and 2003, the weighted average interest rate on the Partnership’s creditfacility was 4.48% and 4.69%, respectively.

 

Underthe provisions of the Partnership Credit Facility, the Partnership is subjectto a number of restrictions on its business, including restrictions on itsability to grant liens on assets; make or own certain investments; enter

 

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into any swap contractsother than in the ordinary course of business; merge, consolidate or sellassets; incur indebtedness (other than subordinated indebtedness); makeacquisitions; engage in other businesses; enter into capital or operatingleases; engage in transactions with affiliates; make distributions on equityinterests; declare or make, directly or indirectly any restricted payments.

 

The PartnershipCredit Facility also contains covenants requiring the Partnership to maintain:

 

•      a ratio ofnot less than 3.00 to 1.00 of consolidated EBITDA to consolidated interestexpense for the prior four fiscal quarters;

•      a ratio of not more than 5.00 to 1.00of total consolidated debt to consolidated EBITDA for the prior four fiscalquarters;

•      a ratio of not more than 3.50 to1.00 of consolidated senior debt to consolidated EBITDA for the prior fiscalquarters; and

•      a minimum net worth of $200.0 millionplus 50% of proceeds from Partnership interests issued subsequent to October 25,2004.

 

Thesecovenants are used to calculate the available borrowing capacity on a quarterlybasis.  The calculation takes into considerationthe cash flow contribution of any future acquisitions at the time ofclosing.  The Partnership Credit Facilitymatures on October 23, 2009.  Atthat time, the Partnership Credit Facility terminates and all outstandingamounts thereunder are due and payable.

 

Thereis no debt outstanding under the Partnership Credit Facility at December 31,2004 and, based on the covenants above, the Partnership had available borrowingcapacity of approximately $63.3 million. The available borrowing capacityat December 31, 2004 was calculated, using the most restrictive debtcovenant, as the amount that, when added to existing debt, would provide amaximum leverage ratio of 5.0 to 1.0.

 

As thePartnership was unable to deliver its 2004 audited consolidated financial statementswithin 90 days of December 31, 2004, the Partnership was not in compliancewith its debt covenants.  The lendinginstitutions of the credit facility waived the 90 day delivery requirementuntil June 30, 2005.  The Partnership’s Form 10-K for the yearended December 31, 2004 and its Quarterly Report on Form 10-Q for thefirst quarter of 2005 were filed on June 24, 2005.

 

*Senior Notes*

 

In October 2004,the Partnership and its subsidiary,MarkWest Energy Finance Corporation, issued $225.0 million of seniornotes due November 1, 2014 pursuant to Rule 144A and Regulation Sunder the Securities Act of 1933. Subject to compliance with certain covenants, the Partnership may issueadditional notes from time to time under the indenture.  Interest on the notes accrues at the rate of6.875% per year and is payable semi-annually in arrears on May 1 and November 1,commencing on May 1, 2005.  ThePartnership may redeem some or all of the notes at any time on or after November 1,2009 at certain redemption prices together with accrued and unpaid interest to the date of redemption, and thePartnership may redeem all of the notes at any time prior to November 1,2009 at a make-whole redemption price. In addition, prior to November 1, 2007, the Partnership may redeemup to 35% of the aggregate principal amount of the notes with the proceeds ofcertain equity offerings at a certain redemption price.  If the Partnership sells certain assets anddoes not reinvest the proceeds or repay senior indebtedness, or if the Partnershipexperiences specific kinds of changes in control, it must offer to repurchasenotes at a specified price.  MarkWestEnergy Partners, L.P. is a holding entity and owns no operating assets and hasno significant operations independent of its subsidiaries.  Each of the Partnership’s existingsubsidiaries, other than MarkWest Energy Finance Corporation, has guaranteedthe notes jointly and severally and fully and unconditionally.  The notes are senior unsecured obligationsequal in right of payment with all of the Partnership’s existing and futuresenior debt.  These notes are senior inright of payment to all of the Partnership’s future subordinated debt buteffectively junior in right of payment to its secured debt to the extent of theassets securing the debt, including the Partnership’s obligations in respect ofthe Partnership Credit Facility.  Theproceeds from these notes were used to pay down the Partnership’s outstandingdebt under its credit facility.

 

Theindenture governing the senior notes limits the activity of the Partnership andits restricted subsidiaries.  Theprovisions of such indenture places limits, on the ability of the Partnershipand its restricted subsidiaries to incur

 

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additional indebtedness; declareor pay dividends or distributions or redeem, repurchase or retire equityinterests or subordinated indebtedness; make investments; incur liens; createany consensual limitation on the ability of the Partnership’s restrictedsubsidiaries to pay dividends, make loans or transfer property to thePartnership; engage in transactions with the Partnership’s affiliates; sellassets, including equity interest of the Partnership’s subsidiaries; make anypayment on or with respect to, or purchase, redeem, defease or otherwiseacquire or retire for value any subordinated obligation or guarantorsubordination obligation (except principal and interest at maturity); andconsolidate, merge or transfer assets.

 

ThePartnership agreed to file an exchange offer registration statement, or undercertain circumstances, a shelf registration statement, pursuant to aregistration rights agreement relating to the 2004 senior notes.  On February 22, 2005, the Partnershipfiled the exchange offer registration statement relating to the 2004 seniornotes.  The Partnership is offering toexchange up to $225.0 million aggregate principal amount of new 6.875% seniornotes due 2014 that have been registered under the Securities Act for an equalprincipal amount of the 2004 senior notes. The Partnership failed to complete the exchange offer in the timeprovided for in the subscription agreements (April 19, 2005) and as aconsequence is incurring an interest rate penalty of 0.5%, increasing 0.25% every 90 days thereafter up to 1%,until such time as the exchange offer is completed.

 

The indenture governing the outstanding senior notes containsrestrictions on the Partnership’s ability to make cash distributions.  Under the indenture, the Partnership isrestricted from making Restricted Payments if at the time of making theRestricted Payment, a default or an event of default has occurred and iscontinuing.  The Partnership’s failure tofile its Annual Report on Form 10-K for the year ended December 31,2004 and its Quarterly Report on Form 10-Q for the first quarter of 2005within the time periods specified in the Securities and Exchange Commission’s rules andregulations constituted a default under the indenture, and the failure to filethe Form 10-K within thirty days after the April 8, 2005 notice fromthe indenture trustee constituted an event of default under the indenture.  On May 16, 2005, the Partnership paid acash distribution to unitholders for the first quarter of 2005.  This cash distribution, made while the eventof default for failure to file its Form 10-K had occurred and wascontinuing, constituted a default under the indenture, and this default maturedinto an event of default thirty days after such Restricted Payment was made, orJune 15, 2005.  Both of these eventsof default were cured upon the filing of the Partnership’s Form 10-K andthe Quarterly Report on Form 10-Q for the first quarter of 2005 on June 24,2005 prior to any declaration of acceleration of the senior notes by thetrustee as a result of such events of default.

 

Long-termdebt consists of (in thousands):

 
| ** **                                        | ** ** | **December 31,** | ** ** |
|---------------------------------------------------|------------|-----------------------|------------|
| ** **                                        | ** ** | **2004**              | ** ** | **2003** | ** ** |
|                                              |       |                  |       |   |   |
| 6.875% Senior Notes due  November 1, 2014    |       | $                     | 225,000    |   | $ | — |   |
| Revolving credit  facility due November 2006 |       | —                |       | 126,200 |   |
|                                              |       |                  |       |   |   |
|                                              |       | $                     | 225,000    |   | $ | 126,200 |   |

 

**10.****  AssetRetirement Obligations**

 

In June 2001, the FASB issued Statement No. 143, *Accounting for Asset Retirement Obligations. *The Company adopted SFAS No. 143beginning January 1, 2003. The most significant impact of this standard onthe Company was a change in the method of accruing for site restorationcosts.  Under SFAS No. 143, the fairvalue 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 areincreased by the amount of these obligations. Over time, the liabilities are accreted for the change in their presentvalue and the initial capitalized costs are depreciated over the useful livesof the related assets.

 

Thecumulative effect of this accounting change for years prior to 2003 was lessthan $0.1 million and is reflected in the Company’s statement of operations. Atthe time of adoption, the Company recorded an asset

 

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retirementobligation of $3.4 million, decreased a site restoration liability of $0.9million that was recorded prior to the implementation of SFAS No. 143 andincreased net property, plant and equipment of $2.4 million in accordance withthe provisions of SFAS No. 143. There was no impact on our cash flows as aresult of adopting SFAS No. 143. For the year ended December 31, 2003, the impact on earnings pershare from the cumulative effect of the change in accounting for assetretirement obligations was not significant.

 

Thepro forma asset retirement obligation would have been $2.5 million at January 1,2002 had the Company adopted SFAS No. 143 on January 1, 2002. For theyear ended December 31, 2002, the pro forma effect on net income andearnings per share, had the Company adopted SFAS No. 143 on January 1,2002, would have been as follows (in thousands, except per share data):

 
| ** **      | ** ** | **As  Reported**                | ** ** | **Pro  Forma**                  | ** ** |
|-----------------|------------|---------------------------------|------------|---------------------------------|------------|
| ** **      | ** ** | **(as restated, see  note 23)** | ** ** | **(as restated, see  note 23)** | ** ** |
| Net loss        |       | $                               | (3,009     | )                               | $          | (4,454 | ) |
| Loss per share: |       |                            |       |                            |       |
| Basic           |       | $                               | (0.29      | )                               | $          | (0.43 | ) |
| Diluted         |       | $                               | (0.29      | )                               | $          | (0.43 | ) |

 

The following is a reconciliation of the Company’s assetretirement obligation for the years ended December 31, 2004 and 2003 (inthousands):

 
| Asset  retirement obligation as of January 1, 2003   |   | $      | 3,367  |   |
|-----------------------------------------------------------|--------|--------|--------|--------|
| Liabilities accrued  during the period                    |   | 1,197  |   |
| Liabilities settled                                       |   | (4,188 | )      |
| Accretion                                                 |   | 128    |   |
| Asset retirement  obligation as of December 31, 2003 |   | 504    |   |
| Liabilities accrued  during the period                    |   | 377    |   |
| Liabilities settled                                       |   | (4     | )      |
| Accretion                                                 |   | 15     |   |
| Asset retirement  obligation as of December 31, 2004 |   | $      | 892    |   |

 

The Company’s assets subject to asset retirement obligations,exclusive of assets owned by MarkWest Energy, were primarily oil and gas wells.The Company discontinued its exploration and production business and sold offsubstantially all of its assets as of December 31, 2003.

 

The Partnership reviewed current laws and regulationsgoverning obligations for asset retirements as well as leases.  Based on that review, the Partnershipidentified certain land leases in East Texas that contain provisions requiringthe Partnership to return the land to its original condition upon thetermination of the lease.  Based on thereview of the leases, the Partnership recorded an asset retirement obligationof $0.4 million during the year ended December 31, 2004, using anestimated average term of the leases of 25 years.  Accretion expense for the year ended December 31,2004 was less than $0.1 million.

 

In accordance with SFAS No. 143, the Partnership hasidentified certain assets that have an indeterminate life, and thus a futureretirement obligation is not determinable. These assets include certain pipelines and processing plants.  A liability for these asset retirementobligations will be recorded when a fair value is determinable.

 

The asset retirement obligation associated with thePartnership’s remaining facilities was insignificant and not recognized in thefinancial statements.

 

In October 2003, the board of directors of the Company’sgeneral partner approved a plan to shut down the Partnership’s existing Cobbprocessing facility, and construct a replacement facility. Construction ofthe new facility

 

94

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was completed in thefirst quarter of 2005.  During the fourth quarter of 2003, the Partnershipestimated the amount of the asset retirement obligation associated with thedecommissioning and dismantlement of the old Cobb facility to be $0.5 millionand, accordingly, the Partnership recorded a related accrued liability.  At December 31, 2004, the assetretirement obligation was $0.5 million.

 

At January 1 and December 31, 2004 and 2003, therewere no assets legally restricted for purposes of settling asset retirementobligations.

 

**11.****          Secondary Public Offerings and PrivatePlacements by MarkWest Energy Partners**

 

*Private Placement – June 27 and July 10, 2003*

 

Througha private placement transaction to certain accredited investors, MarkWestEnergy sold 375,000 common units in two installments at a price of $26.23 perunit that yielded gross proceeds of approximately $9.8 million.  The first installment of 300,031 units wascompleted on June 27, 2003, for proceeds of approximately $7.9million.  The second installment of74,969 units was completed on July 10, 2003, for proceeds of approximately$1.9 million.  Transaction costs for bothinstallments were less than $0.1 million. The Partnership’s general partner made its contribution to maintain its2% interest in July 2003 after the second installment was completed.

 

###### * Secondary Public Offering – January 12,2004*

###### * *

On January 12, 2004, the Partnershippriced its offering of 1,148,000 common units at $39.90 per unit.  Of the 1,148,000 common units, 1,100,444 weresold by the Partnership for gross proceeds of $43.9 million. The remaining47,556 were sold by certain selling unitholders, proceeds of which wereretained by them.  Inconnection with the over-allotment provisions of the underwriting agreement,the Partnership issued an additional 72,500 common units for gross proceeds of$2.9 million.  Aggregate gross proceeds of$46.8 million were reduced by underwriters’ fees of $2.5 million andprofessional fees and other offering costs of $1.3 million, resulting in netproceeds of $43.0 million.  The netproceeds of $43.0 million and the $0.9 million contributed by the generalpartner to maintain its 2% interest resulted in total net proceeds to thePartnership associated with the offering of $43.9 million, which were used topay down the Partnership’s credit facility.

 

*Private Placement – July 30,2004*

 

The Partnership sold 1,304,438 common unitsin a private placement to certain accredited investors for $34.50 per commonunit that resulted in gross proceeds of $45.0 million.  The aggregate gross proceeds of $45.0 millionwere reduced by offering costs of $0.9 million resulting in net proceeds of$44.1 million.

 

###### *SecondaryOffering – September 21, 2004*

###### * *

On September 21, 2004, the Partnershippriced its offering of 2,157,395 common units at $43.41 per unit.  Of the 2,157,395 common units, 2,000,000 weresold by the Partnership for gross proceeds of $86.8 million. The remaining157,395 were sold by certain selling unitholders, proceeds of which have beenretained by them.  Inconnection with the over-allotment provisions of the underwriting agreement,the Partnership issued an additional 323,609 common units for gross proceeds of$14.1 million.  Aggregate gross proceeds of$100.9 million were reduced by underwriters’ fees of $4.8 million andprofessional fees and other offering costs of $0.4 million, resulting in netproceeds of $95.7 million.

 

**12.****          Stockholders’ Equity**

 

*Cash Dividends - Quarterly*

 

TheCompany paid quarterly cash dividends for the year ended December 31, 2004as follows:

 

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| **Quarter  Ended:**     | ** ** | **Dividend** | ** ** | **Record Date** | ** **             | **Payment Date** | ** **             |
|-------------------------|------------|--------------|------------|-----------------|------------------------|------------------|------------------------|
|                    |       |         |       |            |                   |             |                   |
| December 31, 2004  |       | $            | 0.068      |            | February 9, 2005  |             | February 21, 2005 |   |
| September 30, 2004 |       | $            | 0.045      |            | November 24, 2004 |             | December 6, 2004  |   |
| June 30, 2004      |       | $            | 0.023      |            | August 5, 2004    |             | August 19, 2004   |   |
| March 31, 2004     |       | $            | 0.023      |            | May 5, 2004       |             | May 19, 2004      |   |

 

TheCompany did not pay cash dividends during the years ended December 31,2003 and 2002.

 

*Cash Dividends – Special*

 

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

 

*Stock Dividends*

 

On October 28,2004, the Company’s Board of Directors declared a stock dividend of one shareof MarkWest Hydrocarbon’s common stock for each ten shares owned bystockholders.  The stock dividend of976,974 shares was paid on November 19, 2004 to the stockholders of recordas of the close of business on November 9, 2004.

 

On July 10,2003, the Company’s Board of Directors declared a stock dividend of one shareof MarkWest Hydrocarbon’s common stock for each ten shares held by itsstockholders.  The stock dividend of852,248 shares was paid on August 11, 2003 to the stockholders of recordas of the close of business on July 31, 2003.

 

Allshare and per share information has been adjusted to give retroactive effect tostock dividends paid.

 

## **13.**          IncomeTaxes

 

The provision for incometaxes from continuing operations is comprised of (in thousands):

 
| ** **                              | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------|------------|----------------------------------|------------|
| ** **                              | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                              | ** ** | ** **                       | ** ** | **(as restated, see  note 23)** | ** ** | **(as restated, see  note 23)** | ** ** |
| Current income tax  expense (benefit):  |       |                             |       |   |   |   |   |
| Federal                                 |       | $                                | 20         |   | $ | (12,258 | ) | $ | — |   |
| State                                   |       | —                           |       | (1,422 | ) | — |   |
| Total  current                          |       | 20                               |       | (13,680 | ) | — |   |
|                                    |       |                             |       |   |   |   |   |
| Deferred income tax  expense (benefit): |       |                             |       |   |   |   |   |
| Federal                                 |       | (286                             | )          | 554 |   | (2,726 | ) |
| State                                   |       | 344                              |       | 41 |   | (331 | ) |
| Total  deferred                         |       | 58                               |       | 595 |   | (3,057 | ) |
|                                    |       |                             |       |   |   |   |   |
| Total  income tax expense (benefit)     |       | $                                | 78         |   | $ | (13,085 | ) | $ | (3,057 | ) |

 

96

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

 
| ** **                                          | ** ** | **December 31,**           | ** ** |
|-----------------------------------------------------|------------|---------------------------------|------------|
| ** **                                          | ** ** | **2004**                        | ** ** | **2003** | ** ** |
| ** **                                          | ** ** | **(as restated, see  note 23)** | ** ** | **(as restated, see  note 23)** | ** ** |
| Deferred tax  liabilities:                          | ** ** | ** **                      | ** ** | ** ** | ** ** |
| Investment  in consolidated subsidiary              |       | $                               | 12,315     |   | $ | 11,251 |   |
| Marketable  securities                              |       | 449                             |       | — |   |
| Total  gross deferred tax liabilities               |       | 12,764                          |       | 11,251 |   |
|                                                |       |                            |       |   |   |
| Deferred tax assets:                                |       |                            |       |   |   |
| Property,  plant and equipment                      |       | (1,630                          | )          | (1,924 | ) |
| Alternative  minimum tax (AMT) credit carryforwards |       | (2,995                          | )          | (2,773 | ) |
| Participation plan compensation                     |       | (1,418                          | )          | (887 | ) |
| Derivative  instruments                             |       | (202                            | )          | (509 | ) |
| Accrued  severance benefits                         |       | (189                            | )          | — |   |
| Allowance  for doubtful accounts                    |       | (21                             | )          | — |   |
| State  net operating loss (NOL) carryforwards       |       | (1,121                          | )          | (59 | ) |
| Other,  net                                         |       | (76                             | )          | (39 | ) |
| Total  gross deferred tax assets                    |       | (7,652                          | )          | (6,191 | ) |
| Less  valuation allowance                           |       | 1,121                           |       | — |   |
| Net  deferred tax assets                            |       | (6,531                          | )          | (6,191 | ) |
|                                                |       |                            |       |   |   |
| Net deferred tax  liabilities                       |       | $                               | 6,233      |   | $ | 5,060 |   |
|                                                |       |                            |       |   |   |
| Net current deferred  tax assets                    |       | $                               | (25        | ) | $ | (534 | ) |
| Net long-term deferred  tax liabilities             |       | 6,258                           |       | 5,594 |   |
| Net  deferred tax liabilities                       |       | $                               | 6,233      |   | $ | 5,060 |   |

 

The differences between the provision for income taxesat the federal statutory income tax rate of 34% and the actual provision forincome taxes from continuing operations are summarized as follows (inthousands):

 
| ** **                                        | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------|------------|----------------------------------|------------|
| ** **                                        | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                        | ** ** | ** **                       | ** ** | **(as restated, see  note 23)** | ** ** | **(as restated, see  note 23)** | ** ** |
| ** **                                        | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Income tax at statutory  rate(1)                  |       | $                                | (280       | ) | $ | (12,072 | ) | $ | (2,663 | ) |
| State income taxes, net  of federal benefit       |       | 7                                |       | (834 | ) | (337 | ) |
| Stock  options subject to variable accounting     |       | 369                              |       |   |   |   |   |
| Percentage  depletion in excess of cost basis     |       | (37                              | )          | — |   | — |   |
| Nondeductible  expenses                           |       | 21                               |       | — |   | — |   |
| Prior year adjustment  for state NOL carryforward |       | (1,085                           | )          | — |   | — |   |
| Change in valuation  allowance                    |       | 1,121                            |       | — |   | — |   |
| Change in estimate of blended  state rate         |       | 117                              |       | — |   | — |   |
| Impact of state amended  tax returns              |       | 177                              |       | — |   | — |   |
| Alternative minimum tax credit                    |       | (373                             | )          | — |   | — |   |
| Other                                             |       | 41                               |       | (179 | ) | (57 | ) |
|                                              |       |                             |       |   |   |   |   |
| Total                                             |       | $                                | 78         |   | $ | (13,085 | ) | $ | (3,057 | ) |

 

----

(1)          Thecalculation of income tax at statutory rate has been adjusted for thenon-controlling interest in net income of consolidated subsidiary.

 

97

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In assessing the reliability of deferred tax assets,management considers whether it is more likely than not that some portion orall of the deferred tax assets will not be realized.  The ultimate realization of deferred taxassets is dependent upon the generation of future taxable income during theperiods in which those temporary differences become deductible.  Management considers the scheduled reversalof deferred tax liabilities, projected future taxable income, and tax planningstrategies in making this assessment. Based upon the level of historical taxable income and projections forfuture taxable income of the periods in which the deferred tax assets aredeductible, management believes it is more likely than not that the Companywill realize the benefits of these deductible differences, net of the existingvaluation allowances at December 31, 2004.  The amount of the deferred tax assetsconsidered realizable, however, could be reduced in the near term if estimatesof future taxable income during the carryforward period are reduced.

 

At December 31, 2004, the Company had no federalNOL carryforwards. State NOL carryforwards were approximately $21.7 million andexpire in 2018 through 2023.  The Companyexpects that future taxable income, if any, will likely be apportioned to statesother than those which generated the state net operating losses.  Consequently, the Company believes it is morelikely than not that the state net operating loss will not be realized and hasprovided a 100% valuation allowance against the state net operatinglosses.  The Company had federal AMTcredit carryforwards of $3.0 million. AMT credit carry forwards have noexpiration date and can be applied as a credit to reduce regular income taxes.

 

**14.**          **Derivative Financial Instruments**

 

*Commodity Price Risk*

 

Through the Company’s consolidated subsidiary, MarkWestEnergy Partners, the Company is engaged in the gathering, processing andtransmission of natural gas, the transportation, fractionation and storage ofNGLs and the gathering and transportation of crude oil. The Company alsomarkets natural gas and NGL products. The Company’s products are commoditiesthat are subject to price risk resulting from changes in response tofluctuations in supply and demand, general economic conditions and other marketconditions, such as weather patterns, over which the Company has no control.

 

The Company’s primary risk management objective is to reducevolatility in its cash flows as a result of changes in commodity prices. A committee, which includes members of senior management, oversees all of theCompany’s hedging activity.

 

The Company may utilize a combination of fixed-price forwardcontracts, fixed-for-floating price swaps and options available in theover-the-counter (“OTC”) market.  The Company may also enter into futurescontracts traded on the New York Mercantile Exchange (“NYMEX”). Swaps andfutures contracts allow the Company to protect its margins becausecorresponding losses or gains on the financial instruments are generally offsetby gains or losses in the physical market.

 

The Company enters into OTC swaps with financial institutionsand other energy company counterparties. The Company conducts a standard creditreview on counterparties and has agreements containing collateral requirementswhere deemed necessary.  The Company usesstandardized swap agreements that allow for offset of positive and negativeexposures. The Company is subject to margin deposit requirements under OTCagreements (with non-bank counterparties) and for NYMEX positions.

 

The use of financial instruments may expose the Company tothe risk of financial loss in certain circumstances, including instances when (i) NGLsdo not trade at historical levels relative to crude oil, (ii) salesvolumes are less than expected requiring market purchases to meet commitments,or (iii) the Company’s OTC counterparties fail to purchase or deliver thecontracted quantities of natural gas, NGLs or crude oil or otherwise fail toperform.  To the extent that the Company engages in hedging activities, itmay be prevented from realizing the benefits of favorable price changes in thephysical market.  However, the Company is similarly protected againstunfavorable changes in such prices.

 

98

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*CommodityRisk Management Position*

 

As of December 31, 2004, the Partnership has natural gasswap agreements relating to 182,500 MMBtu, of forecasted natural gas sales witha fixed price of $4.26 per MMBtu.  Theseswaps settled in the first quarter of 2005. The swaps are accounted for as hedges. As of December 31, 2004, the Company has NGL swap agreementsrelating to 11,928,000 NGL gallons with a weighted average fixed price of $0.85per gallon.  These swaps settled in thefirst quarter of 2005.  The NGL swaps arenot designed as hedges.  As a result,changes in the fair value of the NGL swaps are reflected currently in earnings.

 

At December 31, 2004 and 2003, the Company recorded aliability of $1.1 million and $1.9 million, respectively, for the fair value ofthese swaps.  The gains and losses on thenatural gas swaps are included in accumulated other comprehensive loss in theaccompanying consolidated balance sheet and are reclassified into earnings asthe hedged transactions take place.  Theaccumulated other comprehensive loss balance of $0.3 million, before incometaxes of less than $0.1 million, represents unrecognized net losses onderivative instruments accounted for as hedges as of December 31, 2004 andis expected to be reclassified into earnings during the next twelvemonths.  During the year ended December 31,2004 and 2003, the Company reclassified $3.7 million and $19.5 million,respectively, of accumulated other comprehensive loss into earnings as a resultof hedging transactions that settled during the period.  This amount includes the accumulated othercomprehensive loss balance of $1.5 million and $13.4 million representingunrecognized net losses on derivative instruments as of December 31, 2003and December 31, 2002, respectively.

 

In the event a derivative no longer qualifies for as a cashflow hedge, SFAS No. 133 provides the amount in other comprehensive incomeis to be reclassified to earnings in the periods of the originally forecastedtransactions.  The Company reclassified$0.3 million, $0.2 million and $0.8 million from other comprehensive income torevenue, net of $0.1 million, $0.1 million and $0.3 million of deferred taxesfor 2004, 2003 and 2002, respectively, relating to a discontinued interest ratehedge.

 

For each of the years ended December 31,2004, 2003 and 2002, no gains or losses included in accumulated other comprehensiveloss were reclassified into earnings as a result of the discontinuance of cashflow hedges due to a determination that the forecasted transactions would nolonger occur by the end of the originally specified time period.

 

The Company recognized a loss of less than$0.1 million and $2.4 million during 2004 and 2002, respectively, and a gain of$2.4 million during 2003, relating to the ineffective portion of derivativesaccounted for as hedges and to derivative instruments that were not designatedor did not qualify for hedge accounting. All of these amounts are reflected in revenue in the Company’saccompanying consolidated statements of operations.

 

*Interest Rate Risk*

 

Although the Company had no debt outstanding with afloating interest rate at December 31, 2004, the Company would be exposedto changes in interest rates in the future if it drew on its creditfacilities.  The Company may make use ofinterest rate swap agreements in the future should it borrow from its creditfacilities to adjust the ratio of fixed and floating rates in the debtportfolio.

 

## **15.**          EmployeeBenefit Plan

## ** **

The Company made contributions of $0.5million, $0.4 million and $0.3 million to a 401(k) savings and profit-sharingplan for the years ended December 31, 2004, 2003 and 2002, respectively.The Company contributed approximately 15,000, 32,000 and 39,000 common sharesto a 401(K) savings and profit-sharing plan for the years ended December 31,2004, 2003 and 2002, respectively, with an aggregate fair value of $0.2million, $0.2 million and $0.3 million, respectively.  The plan is discretionary, with annualcontributions determined by the Company’s Board of Directors.

 

99

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## **16.**          Stockand Incentive Compensation Plans

 

At December 31,2004, the Company has four stock-based compensation plans, one of which isthrough its consolidated subsidiary, MarkWest Energy. These plans are describedbelow. The Company applies APB Opinion No. 25, *Accountingfor Stock Issued to Employees,* and related Interpretations inaccounting for its plans.  The Companyrecognized $6.8 million, $2.7 million and $0.3 million in compensationexpense for the variable plans for the years ended December 31, 2004, 2003and 2002, respectively.

 

Under the 1996 Stock Incentive Plan, theCompany may grant options to its employees for up to 925,000 shares of commonstock. Under this plan, the exercise price of each option equals the marketprice of the Company’s stock on the date of the grant, and the maximum term ofthe option is ten years. Options are granted periodically throughout the yearand vest at the rate of 25% per year for options granted in 1999 andthereafter, and 20% per year for options granted prior to 1999.  At December 31, 2004, there were 409,935options available for grant under this plan.

 

Under the 1996Non-employee Director Stock Option Plan, the Company may grant options to itsnon-employee directors for up to 30,000 shares of common stock. There are nooptions available for grant at December 31, 2004.  Under this plan, the exercise price of eachoption equals the market price of the Company’s stock on the date of the grant,and the maximum term of an option is three years. Options are granted upon thedate the director first becomes a director and biannually thereafter. Optionsgranted upon the date the director first becomes a director vest at the rate of33% per year.  Subsequent, biannualoptions vest 100% on the first anniversary of the option grant date.

 

The1996 Stock Incentive Plan and the 1996 Non-employee Director Stock Option Planallow for the exercise of stock options using the cashless method, but only atthe discretion of the Company.  Under acashless exercise, the Company withholds from shares that otherwise would beissued upon the exercise of the option, the number of shares with a fair marketvalue equal to the option exercise price and remits the remaining shares to theemployee.  Prior to April 2004, theCompany did not allow participants to exercise their stock options using thecashless method.  Accordingly,compensation expense was not recognized for stock options granted unless theoptions were granted at an exercise price less than the quoted market price ofthe Company’s stock on the grant date. In April 2004, the Company changed its policy to allow participantsto exercise their stock options using the cashless method.  Under APB 25, *Accounting for Stock Issued to Employees,*a fixed stockoption plan that permits the use of a cashless exercise becomes variable if apattern of exercising the stock options using the cashless method isdemonstrated.  As a result, in April 2004,the Company was required to account for stock options issued under the plans asvariable awards. Compensation expense for stock options issued as variable awardsis measured as the difference in the market value of the Company’s common stockand the exercise price of the stock options. The difference is amortized into earnings over the period of service,adjusted quarterly for the change in the fair value of the unvested stockoptions awarded.  Increases or decreasesin the market value of the Company’s common stock between April of 2004and the end of each reporting period result in a change in the measure ofcompensation for vested awards, which is reflected currently inoperations.  The Company recordedcompensation expense for options granted under the plans accounted for asvariable awards of $1.6 million for the year ended December 31, 2004.  During the year ended December 31, 2004,recipients exercised their options to purchase an aggregate of 226,734 sharesof the Company’s common stock. Recipients exercised options for 125,960 shares using the cashlessmethod resulting in the net issuance of 44,816 shares of common stock.  During the three months ended March 31,2004, two officers resigned from the Company. As the former officers continued to serve on the Company’s Board ofDirectors, the Company agreed that the individual’s stock options wouldcontinue to vest and be exercisable in accordance with the original vesting andexercise provisions.  As a result of themodification to the stock options for these officers the outstanding stockoptions are to be accounted for as variable awards, and as a result, theCompany recorded compensation expense of $0.4 million for the three monthsended March 31, 2004, measured as the difference in the market value ofthe Company’s common stock on the date the officer’s status changed and thestrike price of the outstanding stock options. These charges are included in selling, general and administrativeexpenses.

 

100

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The fair value of eachoption granted in 2004, 2003 and 2002 was estimated using the Black-Scholesoption-pricing model.  The followingassumptions were used to compute the weighted average fair market value ofoptions granted:

 

| ** **                | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|---------------------------|------------|----------|------------|----------|------------|----------|------------|
| Expected life of  options |       | 6 years  |       | 6 years  |       | 6 years  |       |
| Risk free interest  rates |       | 3.62     | %          | 3.48     | %          | 3.54     | %          |
| Estimated volatility      |       | 32       | %          | 51       | %          | 52       | %          |
| Dividend yield            |       | 4.7      | %          | 0.0      | %          | 0.0      | %          |

 

A summary of the status of the Company’sstock option plans as of December 31, 2004, 2003 and 2002, and changesduring the years then ended are presented below.  Stock option information in the followingtable has not been adjusted to give retroactive effect to stock dividendspaid.  See note 12.

 

| ** **                                                      | ** ** | **2004**   | ** ** | **2003**                      | ** ** | **2002**   | ** ** |
|-----------------------------------------------------------------|------------|------------|------------|-------------------------------|------------|------------|------------|
| ** **                                                      | ** ** | **Shares** | ** ** | **Weighted-  Average  Price** | ** ** | **Shares** | ** ** | **Weighted-  Average  Price** | ** ** | **Shares** | ** ** | **Weighted-  Average  Price** | ** ** |
| **Fixed Options**                                               |       |       |       |                          |       |       |       |   |   |   |   |   |   |
| Outstanding at  beginning of year                               |       | 440,080    |       | $                             | 8.35       |       | 728,315    |   | $ | 9.06 |   | 792,948 |   | $ | 9.18 |   |
| Granted                                                         |       | 33,500     |       | 12.62                         |       | 45,750     |       | 8.44 |   | 20,000 |   | 6.09 |   |
| Effect of stock  dividends                                      |       | 15,072     |       |                          |       | 83,042     |       |   |   | — |   |   |   |
| Exercised                                                       |       | (280,776   | )          | 8.37                          |       | (261,141   | )          | 8.11 |   | (386 | ) | 5.38 |   |
| Cancelled                                                       |       | (36,188    | )          | 11.67                         |       | (155,886   | )          | 8.78 |   | (84,247 | ) | 9.51 |   |
| Outstanding at end of  year                                     |       | 171,688    |       | $                             | 8.43       |       | 440,080    |   | $ | 8.35 |   | 728,315 |   | $ | 9.06 |   |
|                                                            |       |       |       |                          |       |       |       |   |   |   |   |   |   |
| Options exercisable                                             |       | 92,362     |       |                          |       | 342,043    |       |   |   | 559,382 |   |   |   |
| Weighted-average  fair value of options granted during the year |       |       |       | $                             | 2.46       |       |       |   | $ | 2.41 |   |   |   | $ | 2.54 |   |

 

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The following table summarizes information about fixed stock optionsoutstanding at December 31, 2004:

 
| ** **                    | ** ** | **Options Outstanding** | ** ** | **Options Exercisable**                              | ** ** |
|-------------------------------|------------|-------------------------|------------|------------------------------------------------------|------------|
| **Range  of Exercise Prices** | ** ** | **Number  Outstanding** | ** ** | **Weighted-  Average  Remaining  Contractual  Life** | ** ** | **Weighted-  Average  Exercise  Price** | ** ** | **Number  Exercisable** | ** ** | **Weighted-  Average  Exercise  Price** | ** ** |
| $4.00 to $6.00                |       | 30,413                  |       | 6                                                    |       | $ | 4.71 |   | 13,019 |   | $ | 4.67 |   |
| $6.00 to $8.00                |       | 34,943                  |       | 5                                                    |       | 6.74 |   | 27,411 |   | 6.83 |   |
| $8.00 to $10.00               |       | 83,832                  |       | 7                                                    |       | 9.24 |   | 48,632 |   | 9.05 |   |
| $10.00 to $12.00              |       | 13,200                  |       | 5                                                    |       | 11.02 |   | 3,300 |   | 10.25 |   |
| $12.00 to $14.00              |       | 2,200                   |       | 10                                                   |       | 13.25 |   | — |   | — |   |
| $14.00 to $16.00              |       | 1,100                   |       | 10                                                   |       | 14.27 |   | — |   | — |   |
| $16.00 to $18.00              |       | 6,000                   |       | 3                                                    |       | 17.25 |   | — |   | — |   |
| $4.41 to $17.25               |       | 171,688                 |       | 6                                                    |       | $ | 8.43 |   | 92,362 |   | $ | 7.82 |   |

 

*MarkWest Hydrocarbon Participation Plan*

 

MarkWestHydrocarbon also has a Participation Plan for certain employees and directorsof MarkWest Hydrocarbon.  Under theParticipation Plan, MarkWest Hydrocarbon sells subordinated partnership unitsof the Partnership and interest in the Partnership’s general partner to certainemployees and directors of MarkWest Hydrocarbon under a purchase and saleagreement.  The interests in the generalpartner are sold with certain put and call provisions that allow the individualto require MarkWest Hydrocarbon to buy back or requires the individual to sellback their interest in the general partner to MarkWest Hydrocarbon.  Specifically, the employees and directors canexercise their put if (1) MarkWest Hydrocarbon or the Partnership’sgeneral partner undergoes a change of control; (2) additional membershipinterests are issued and if the issuance of additional membership interests, ona pro forma basis, decreases the distributions to all then existing members; (3) anyamendment, alteration or repeal of the provisions of the general partneragreement is undertaken which materially and adversely affects the thenexisting rights, duties, obligations or restrictions of the employees anddirectors; or (4) the employee or director (i) becomes totallydisabled while a director, officer or employee of the general partner, ofMarkWest Hydrocarbon or of any of their affiliates after reaching the age of 60years.  The employee or his estate has120 days after the put event to exercise the put under (4) and 30 daysafter notice to exercise under (1) through (3).  MarkWest Hydrocarbon can exercise its calloption if the employee or director ceases to be a director or employee ofMarkWest Hydrocarbon or any of its affiliates or if there is a change ofcontrol.  The Company has 12 monthsfollowing the termination date to exercise its call option.  As the formula used to determine the sale andbuy-back price is not based on fair value, coupled with the attributes of theput and call provisions, these transactions are considered compensatoryarrangements, similar to a stock appreciation right.  The subordinated partnership units of thePartnership are also sold to the employees and directors at a formula that isnot based on fair value.  Thesubordinated units are sold without any restrictions on transfer.  However, the Company has established animplied repurchase obligation through its pattern of buying back the subordinatedunits each time an employee or director has left MarkWest Hydrocarbon.  The employees’ and directors’ subordinatedunits convert into common units on June 30, 2005.  Since the employees and directors are 100%vested on the date they purchase the subordinated units or general partnerinterests, compensation expense for the subordinated units is measured as thedifference in the market value of the subordinated partnership units and theamount paid by those individuals. Compensation expense related to the general partner interest iscalculated as the difference in the formula value and the amount paid by thoseindividuals.  The formula value is theamount MarkWest Hydrocarbon would have to pay the employees and directors torepurchase the general partner interests and is based on the current marketvalue of the Partnership’s common units and the previous quarterly distributionpaid.  The increases or decreases in themarket value of the subordinated units and the formula value of the generalpartner interest between the date they are acquired and the end of eachreporting period result in a change in the measure of compensation, which isreflected currently in operations.  Totalsubordinated units sold to the employees and directors in 2004, 2003 and 2002were 1,500, 12,500 and 24,864, respectively, for approximately less than $0.1million, $0.3 million and $0.4 million, respectively.  MarkWest Hydrocarbon reacquired 2,867, 867and 4,626 subordinated units in 2004, 2003 and 2002, respectively.  Total interests in the Partnership’s generalpartner sold to the directors and employees in 2004, 2003 and 2002, were 0.7%,3.6% and 8.6%, respectively, for approximately $0.2 million in each year,respectively.  MarkWest Hydrocarbonreacquired 0.7%, 0.3% and 1.6% of the general partner interest in 2004, 2003and 2002, respectively.

 

102

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The Company recordedcompensation expense under the Participation Plan of $3.7 million, $1.3 millionand $0.2 million for the years ended December 31, 2004, 2003 and 2002,respectively.

 

Immediately after MarkWest Energy’s initial public offeringon May 24, 2002, MarkWest Hydrocarbon sold an 8.6% interest in the generalpartner of the Partnership and 24,864 of its Partnership subordinated units, tocertain officers of MarkWest Hydrocarbon for a total purchase price of $0.6million.  The officers and employees paidapproximately 30% of the purchase price in cash, or $0.2 million, and financed theremainder, approximately $0.4 million, with notes payable to MarkWestHydrocarbon.  The non-recourse promissorynotes requires that the principal balance is to be repaid no later than June 30,2009 and the notes bear interest at the rate of 7% per annum on the unpaidbalance.  Outstanding notes receivablefrom officers pertaining to the loans made in May 2002 were approximately$0.2 million as of both December 31, 2004 and 2003.

 

 ***MarkWest Energy Partners Long-Term Incentive Plan***

 

ThePartnership’s general partner has adopted the MarkWest Energy Partners, L.P.Long-Term Incentive Plan for employees and directors of the general partner andemployees of its affiliates who perform services for the Partnership. Thelong-term incentive plan consists of two components, restricted units and unitoptions. The long-term incentive plan currently permits the grant of awardscovering an aggregate of 500,000 common units, 200,000 of which may be awardedin the form of restricted units and 300,000 of which may be awarded in the formof unit options.  The CompensationCommittee of the general partner’s board of directors administers the plan.

 

Thegeneral partner’s board of directors in its discretion may terminate or amendthe long-term incentive plan at any time with respect to any units for which agrant has not yet been made. The general partner’s board of directors also hasthe right to alter or amend the long-term incentive plan or any part of theplan from time to time, including increasing the number of units that may begranted subject to unitholder approval as required by the exchange upon whichthe common units are listed at that time. However, no change in any outstandinggrant may be made that would materially impair the rights of the participantwithout the consent of the participant.

 

*Restricted Units.*  A restricted unit is a “phantom” unit thatentitles the grantee to receive a common unit upon the vesting of the phantomunit, or at the discretion of the Compensation Committee, cash equivalent tothe value of a common unit. These restricted units are entitled to receivedistribution equivalents, which represent cash equal to the amount of cashdistributions made on common units during the vesting period, from the date ofgrant and vest over a stated period.  Priorto September 2004, the vesting period was four years, with 25% of thegrant vesting at the end of each of the second and third years and 50% vestingat the end of the fourth year. As of September 1, 2004, the vesting periodfor subsequent grants was changed to three years, with 33% of the grant vestingat the end of each of the first, second and third years.  In the future, the Compensation Committee maymake additional grants under the plan to employees and directors containingsuch terms as the Compensation Committee shall determine under the plan. TheCompensation Committee also determines the period over which restricted unitsgranted to employees and directors will vest. The restricted units will vest upon a change of control of thePartnership, the general partner of the Partnership or MarkWest Hydrocarbon.

 

If agrantee’s employment or membership on the board of directors terminates for anyreason, the grantee’s unvested restricted units are automatically forfeitedunless, and to the extent, the Compensation Committee provides otherwise.  Common units to be delivered upon the vestingof restricted units may be common units acquired by the general partner in theopen market, common units already owned by the general partner, common unitsacquired by the general partner directly from the Partnership or any otherperson or any combination of the foregoing. The general partner will beentitled to reimbursement from the Partnership for the cost incurred inacquiring common units.  If thePartnership issues new common units upon vesting of the restricted units, thetotal number of common units outstanding will increase.

 

The following is a summary of the Long-TermIncentive Plan restricted units issued under the Partnership’s Long-TermIncentive Plan (in thousands, except unit data):

 

103

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| ** **                    | ** ** | **2004**   | ** ** | **2003**   | ** ** |
|-------------------------------|------------|------------|------------|------------|------------|
| ** **                    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Balance, beginning of  period |       | 34,496     |       | 50,230     |       |
| Granted                       |       | 27,900     |       | 11,756     |       |
| Vested                        |       | (27,453    | )          | (23,758    | )          |
| Forfeited                     |       | (5,443     | )          | (3,732     | )          |
| Balance, end of period        |       | 29,500     |       | 34,496     |       |
|                          |       |       |       |       |       |
| Fair value, end of year       |       | $          | 1,434      |       | $          | 1,383 |   |
|                               |            |            |            |            |            |  |  |

 

Duringthe year ended December 31, 2004, 27,453 restricted unit grantsvested.  Of the total number ofrestricted units vested, 155 restricted units, at the Partnership’s option,were redeemed for cash of less than $0.1 million and 27,298 common units wereissued.

 

In October 2003,the board of directors of the general partner approved the accelerated vestingof restricted unit grants based upon the achievement of cash distributiongoals. As a result of achieving those distribution goals, 23,758 restrictedunits vested effective December 1, 2003. Accordingly, the Partnership recorded a charge in the amount of $1.0million, equal to the fair market value of the common units issued for thevested restricted units at the date of the accelerated vesting less the amountof compensation cost previously recognized.

 

ThePartnership recorded compensation expense under the Long-Term Incentive Plan of$1.1 million, $1.4 million and $0.1 million for the years ended December 31,2004, 2003 and 2002, respectively.  Thesecharges are included in selling, general and administrative expenses.

 

*Unit Options**.** *The Long-Term IncentivePlan currently permits the granting of options covering common units. TheCompensation Committee may make grants under the plan to employees anddirectors containing such terms as the committee shall determine. Unit optionswill have an exercise price that, in the discretion of the committee, may beless than, equal to or more than the fair market value of the units on the dateof grant. Unit options granted are exercisable over a period determined by theCompensation Committee. In addition, the unit options are exercisable upon achange in control of MarkWest Energy, the general partner of MarkWest Energy,or the Company or upon the achievement of specified financial objectives.

 

Uponexercise of a unit option, the general partner will acquire common units in theopen market or directly from the Company or any other person or use commonunits already owned by the general partner, or any combination of theforegoing. The general partner will be entitled to reimbursement by thePartnership for the difference between the cost incurred by the general partnerin acquiring these common units and the proceeds received by the generalpartner from an optionee at the time of exercise.  Thus, the cost of the unit options will beborne by the Partnership. If the Partnership issues new common units uponexercise of the unit options, the general partner will pay the Partnership theproceeds it received from the optionee upon exercise of the unit option.

 

As of December 31,2004, the Partnership had not granted common unit options to employees ordirectors of the general partner, or employees of its affiliates or members ofsenior management.

 

**17.****         ****Related PartyTransactions**

 

Through theCompany’s wholly owned subsidiary, MarkWest Resources, Inc. (“Resources”),the Company held varied undivided interests in several exploration andproduction assets in which MAK-J Energy Partners Ltd. (“MAK-J”) also owns orowned an undivided interest, varying from 25% to 51%. The general partner ofMAK-J is a corporation owned and controlled by the Company’s former Presidentand Chief Executive Officer and current Chairman of the Board of Directors. Twoformer officers, both of who left the Company during 2003, were limitedpartners in MAK-J. The properties were operated pursuant to joint operatingagreements entered into between Resources and MAK-J. Resources was the operatorunder such agreements. The joint operating agreements were governed by aParticipation and Operations Agreement, most recently amended June 2,2003. The joint property acquisitions and joint operating agreements weresubject to the approval of the independent members of the

 

104

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Company’s Boardof Directors. As the operator, Resources was obligated to provide certainaccounting and well operations services to the parties. The Participation andOperations Agreement provided for a monthly fee ($2,000 per month) payable toResources to offset the costs of accounting and well operations on a monthlybasis. As a part of the sale of the Company’s San Juan Basin oil and gasproperties to a third party on June 30, 2003, the Participation andOperations Agreement was assigned to the purchasing third party.

 

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

 

Through theCompany’s wholly owned subsidiary, Matrex, LLC, the Company holds interests incertain exploration and production assets in which MAK-J also ownsinterests.  Both parties are participantsto joint operating agreements involving other third parties.

 

The Company hasreceivables due from MAK-J, representing its share of operating and capitalcosts generated in the normal course of business, of less than $0.1 million asof December 31, 2004 and 2003. The Company also has payables to MAK-J,representing its share of revenues generated in the normal course of business,of less than $0.1 million as of December 31, 2004 and 2003.

 

## **18.**          Commitmentsand Contingencies

 

*Legal*

 

The Company andseveral of its subsidiaries were recently served with several complaints forrecovery of property and personal injury damages sustained as a result of aleak occurring November 8, 2004 in a NGL pipeline owned by a third party,and leased and operated by the Partnership’s subsidiary, MarkWest EnergyAppalachia, LLC.  The 4-inch pipelinetransported NGLs from the Maytown gas processing plant to the Partnership’sSiloam fractionator.  A subsequentignition and fire from the leaked vapors resulted in property damage to fivehomes and injuries to some of the residents. The exact cause of the leak and resulting fire is unknown and is beinginvestigated by the pipeline owner, the Partnership and the Office of PipelineSafety.  The Partnership has submittedclaims for and is pursuing Business Interruption Insurance to cover theincreased transportation costs incurred and the lost income.

 

While investigationinto the incident continues, at this time the Company believes that it hasadequate insurance coverage for property damage and personal injury liabilityresulting from the incident.  Therefore,the Company believes that the possibility of incurring a loss is remote.  The deductible for the insurance is $0.3 million,which the Company recorded during the year ended December 31, 2004 as acharge to income.

 

TheCompany, in the ordinary course of business, is a party to various other legalactions. In the opinion of management, none of these actions, either individuallyor in the aggregate, will have a material adverse effect on the Partnership’sfinancial condition, liquidity or results of operations.

 

*LeaseObligations*

 

The Company has variousnon-cancelable operating lease agreements for equipment and office spaceexpiring at various times through fiscal 2015. Annual rent expense under theseoperating leases was $5.2 million, $2.2 million and $2.3 million for the threeyears ended December 31, 2004, 2003 and 2002, respectively. The Company’sminimum future lease payments under these operating leases as of December 31,2004 are as follows (in thousands):

 
| 2005                |   | $     | 4,212  |   |
|---------------------|--------|-------|--------|--------|
| 2006                |   | 3,345 |   |
| 2007                |   | 2,043 |   |
| 2008                |   | 1,459 |   |
| 2009                |   | 1,377 |   |
| 2010 and thereafter |   | 826   |   |
| Total               |   | $     | 13,262 |   |

 

105

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TheCompany also has a commitment to purchase equipment of $6.1 million at December 31,2004.

 

## **19.**          SegmentReporting

 

The Company’s operations are classified into tworeportable segments:

 

(1)    Managing MarkWest Energy — The Company operates MarkWest Energy, apublicly traded limited partnership engaged in the gathering, processing andtransmission of natural gas, the transportation, fractionation and storage ofnatural gas liquids, and the gathering and transportation of crude oil.

 

(2)    Marketing — The Company sells its equity and third party NGLs, purchasesthird party natural gas and sells its equity and third-party natural gas.  Since February 2004, the Company is alsoengaged in the wholesale marketing of propane.

 

During 2003, theCompany discontinued its exploration and production business segment.

 

On May 24, 2002,the Company spun off its gathering and processing assets into MarkWest Energy,its consolidated subsidiary. The formation and initial public offering ofMarkWest Energy (the initial public offering closed on May 24, 2002) andthe subsequent change to the structure of the Company’s internal organizationcaused the composition of its reportable segments to change in the fourthquarter of 2002.  Prior to the fourthquarter of 2002, the company classified its operations into two reportablesegments:

 

(1)   Exploration and Production—explore for and produce natural gas.

 

(2)   Gathering, Processing and Marketing—gathering and processing of naturalgas and the transportation, fractionation and storage of natural gas liquids;also purchase and market third-party natural gas and NGLs.

 

The Company evaluates the performance of its segmentsand allocates resources to them based on operating income.  There were no intersegment revenues prior to May 24,2002.  The Company conducts itscontinuing operations in the United States.

 

The table belowpresents information about operating income for the reported segments for thethree years ended December 31, 2004, 2003 and 2002. Operating income foreach segment includes total revenues minus purchased product costs, facilityexpenses, selling, general and administrative expenses, depreciation,amortization of intangible assets, accretion of asset retirement obligationsand impairments and excludes interest income, interest expense, amortization ofdeferred financing costs, gain on sale of non-operating assets, non-controllinginterest in net income of consolidated subsidiary, miscellaneous income(expense) and income taxes.

 

Selling, general and administrative expenses are allocated to thesegments based on direct expenses incurred by the segments or allocated basedon****thepercent of time that employees devote to the segment in accordance with thePartnership’s services agreement with the Company.****

 

106

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| ** **                                                         | ** ** | **Marketing**      | ** ** | **MarkWest  Energy** | ** ** | **Eliminating  Entries** | ** ** | **Total** | ** ** |
|--------------------------------------------------------------------|------------|--------------------|------------|----------------------|------------|--------------------------|------------|-----------|------------|
| ** **                                                         | ** ** | **(in thousands)** | ** ** |
| **Year Ended December 31,  2004**                             |       |               |       |                 |       |                     |       |      |       |
| Revenues                                                           |       | $                  | 218,337    |                 | $          | 301,314                  |       | $         | (59,538    | ) | $ | 460,113 |   |
| Purchased product costs                                            |       | 185,951            |       | 211,534              |       | (34,224                  | )          | 363,261   |       |
| Facility expenses                                                  |       | 23,983             |       | 29,911               |       | (25,314                  | )          | 28,580    |       |
| Selling, general and  administrative expenses                      |       | 11,999             |       | 16,133               |       | —                   |       | 28,132    |       |
| Depreciation                                                       |       | 1,339              |       | 15,556               |       | —                   |       | 16,895    |       |
| Amortization of  intangible assets                                 |       | —             |       | 3,640                |       | —                   |       | 3,640     |       |
| Accretion of asset  retirement obligation                          |       | 2                  |       | 13                   |       | —                   |       | 15        |       |
| Impairments                                                        |       | —             |       | 130                  |       | —                   |       | 130       |       |
| Operating income (loss)                                            |       | $                  | (4,937     | )                    | $          | 24,397                   |       | $         | —     |   | $ | 19,460 |   |
| Cash, cash equivalents  and restricted cash                        |       | $                  | 3,581      |                 | $          | 24,263                   |       | $         | —     |   | $ | 27,844 |   |
| Current assets                                                     |       | 58,016             |       | 72,959               |       | —                   |       | 130,975   |       |
| Current liabilities                                                |       | 14,656             |       | 62,412               |       | —                   |       | 77,068    |       |
| Total assets                                                       |       | 64,152             |       | 529,422              |       | —                   |       | 593,574   |       |
| Total debt                                                         |       | —             |       | 225,000              |       | —                   |       | 225,000   |       |
|                                                               |       |               |       |                 |       |                     |       |      |       |
| **Year Ended December 31,  2003, (as restated, see note 23)** |       |               |       |                 |       |                     |       |      |       |
| Revenues                                                           |       | $                  | 142,569    |                 | $          | 117,430                  |       | $         | (50,731    | ) | $ | 209,268 |   |
| Purchased product costs                                            |       | 142,633            |       | 70,832               |       | (25,921                  | )          | 187,544   |       |
| Facility expenses                                                  |       | 25,304             |       | 20,463               |       | (24,810                  | )          | 20,957    |       |
| Selling, general and  administrative expenses                      |       | 7,267              |       | 8,598                |       | —                   |       | 15,865    |       |
| Depreciation                                                       |       | 1,247              |       | 7,548                |       | —                   |       | 8,795     |       |
| Impairments                                                        |       | 1,039              |       | 1,148                |       | —                   |       | 2,187     |       |
| Operating income (loss)                                            |       | $                  | (34,921    | )                    | $          | 8,841                    |       | $         | —     |   | $ | (26,080 | ) |
| Cash, cash equivalents  and restricted cash                        |       | $                  | 33,391     |                 | $          | 8,753                    |       | $         | —     |   | $ | 42,144 |   |
| Current assets                                                     |       | 63,498             |       | 23,581               |       | —                   |       | 87,079    |       |
| Current liabilities                                                |       | 21,208             |       | 21,124               |       | —                   |       | 42,332    |       |
| Total assets                                                       |       | 67,624             |       | 212,871              |       | —                   |       | 280,495   |       |
| Total debt                                                         |       | —             |       | 126,200              |       | —                   |       | 126,200   |       |
|                                                               |       |               |       |                 |       |                     |       |      |       |
| **Year Ended December 31,  2002, (as restated, see note 23)** |       |               |       |                 |       |                     |       |      |       |
| Revenues                                                           |       | $                  | 112,049    |                 | $          | 70,246                   |       | $         | (26,508    | ) | $ | 155,787 |   |
| Purchased product costs                                            |       | 100,334            |       | 38,906               |       | (11,714                  | )          | 127,526   |       |
| Facility expenses                                                  |       | 16,838             |       | 15,101               |       | (14,794                  | )          | 17,145    |       |
| Selling, general and  administrative expenses                      |       | 4,203              |       | 5,411                |       | —                   |       | 9,614     |       |
| Depreciation                                                       |       | 1,036              |       | 4,980                |       | —                   |       | 6,016     |       |
| Operating income (loss)                                            |       | $                  | (10,362    | )                    | $          | 5,848                    |       | $         | —     |   | $ | (4,514 | ) |
| Cash and cash  equivalents                                         |       | $                  | 3,634      |                 | $          | 2,776                    |       | $         | —     |   | $ | 6,410 |   |
| Current assets                                                     |       | 36,531             |       | 7,065                |       | —                   |       | 43,596    |       |
| Current liabilities                                                |       | 43,021             |       | 5,303                |       | —                   |       | 48,324    |       |
| Total assets                                                       |       | 169,794            |       | 87,709               |       | —                   |       | 257,503   |       |
| Total debt                                                         |       | 42,823             |       | 21,400               |       | —                   |       | 64,223    |       |

 

107

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Areconciliation of operating income (loss) to total consolidated income (loss)from continuing operations before taxes is as follows (in thousands):

 
| ** **                                                                                                                           | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                                                                           | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                                                                           | ** ** | ** **                       | ** ** | **(as restated,  see note 23)** | ** ** | **(as restated,  see note 23)** | ** ** |
| Operating  income (loss)                                                                                                             |       | $                                | 19,460     |   | $ | (26,080 | ) | $ | (4,514 | ) |
| Interest income                                                                                                                      |       | 647                              |       | 106 |   | 65 |   |
| Interest expense                                                                                                                     |       | (9,383                           | )          | (4,347 | ) | (2,474 | ) |
| Amortization of  deferred financing costs                                                                                            |       | (5,281                           | )          | (2,104 | ) | (4,343 | ) |
| Gain on sale of  non-operating assets                                                                                                |       | —                           |       | — |   | 5,454 |   |
| Dividend income                                                                                                                      |       | 259                              |       | — |   | — |   |
| Miscellaneous income (expense)                                                                                                       |       | 788                              |       | (92 | ) | (73 | ) |
| Income  (loss) from continuing operations before non-controlling interest in net  income of consolidated subsidiary and income taxes |       | $                                | 6,490      |   | $ | (32,517 | ) | $ | (5,885 | ) |

 

## **20.**          QuarterlyResults of Operations (Unaudited)

 

The following summarizes certain quarterlyresults of operations (in thousands and as restated, see note 23):

 
| ** **                                    | ** ** | **Three Months Ended** | ** ** |
|-----------------------------------------------|------------|------------------------|------------|
| ** **                                    | ** ** | **March 31**      | ** ** | **June 30** | ** ** | **September 30** | ** ** | **December 31** | ** ** |
| **2004**                                      |       |                   |       |   |   |   |   |   |   |
| Revenues                                      |       | $                      | 93,700     |   | $ | 89,024 |   | $ | 121,511 |   | $ | 155,878 |   |
| Income (loss) from  continuing operations (1) |       | $                      | 720        |   | $ | (6,368 | ) | $ | (1,966 | ) | $ | 6,711 |   |
| Net income (loss) (1)                         |       | $                      | 720        |   | $ | (6,368 | ) | $ | (1,966 | ) | $ | 6,711 |   |
| Earnings (loss) per  share:                   |       |                   |       |   |   |   |   |   |   |
| Basic                                         |       | $                      | 0.07       |   | $ | (0.60 | ) | $ | (0.18 | ) | $ | 0.63 |   |
| Diluted                                       |       | $                      | 0.07       |   | $ | (0.60 | ) | $ | (0.18 | ) | $ | 0.63 |   |
|                                          |       |                   |       |   |   |   |   |   |   |
| **2003**                                      |       |                   |       |   |   |   |   |   |   |
| Revenues                                      |       | $                      | 51,231     |   | $ | 48,241 |   | $ | 48,719 |   | $ | 61,077 |   |
| Income (loss) from  continuing operations (1) |       | $                      | (3,514     | ) | $ | (5,977 | ) | $ | (6,367 | ) | $ | (6,562 | ) |
| Net income (loss) (1)                         |       | $                      | (1,413     | ) | $ | 10,031 |   | $ | (7,036 | ) | $ | (12,588 | ) |
| Earnings (loss) per  share:                   |       |                   |       |   |   |   |   |   |   |
| Basic                                         |       | $                      | (0.14      | ) | $ | 0.98 |   | $ | (0.68 | ) | $ | (1.23 | ) |
| Diluted                                       |       | $                      | (0.14      | ) | $ | 0.97 |   | $ | (0.68 | ) | $ | (1.22 | ) |

 

----

(1)    The results ofoperations for the three months ended December 31, 2004 and 2003, includesimpairments of $0.1 million and $1.1 million, respectively (see Note 7).

 

108

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## **21.**          SupplementalInformation on Oil and Gas Producing Activities (Unaudited)

 

The following information is presented in accordance with SFASNo. 69, *Disclosure about Oil and Gas ProducingActivities.*  During 2003, the Company discontinuedits exploration and production business.

 

**(A)****          CostsIncurred in Oil and Gas Exploration and Development Activities**—Thefollowing costs were incurred in oil and gas exploration and developmentactivities during the years ended December 31, 2003 and 2002 (inthousands):

 
| ** **                                                             | ** ** | **United States** | ** ** | **Canada** | ** ** | **Total** | ** ** |
|------------------------------------------------------------------------|------------|-------------------|------------|------------|------------|-----------|------------|
| **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 |   |

 

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

 
| ** **                                                              | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Proved properties                                                       |       | $        | 741        |     | $          | 99,360 |   |
| Unproved properties                                                     |       | —   |       | 32,934   |       |
| Equipment and  facilities                                               |       | 1,639    |       | 6,940    |       |
|                                                                    |       | 2,380    |       | 139,234  |       |
| Less: accumulated  depreciation, depletion, amortization and impairment |       | (1,624   | )          | (21,876  | )          |
| Net  capitalized costs                                                  |       | $        | 756        |     | $          | 117,358 |   |

 

**(C) Resultsof Operations from Producing Activities**—Results of operationsfrom producing activities for the years ended December 31, 2003 and 2002,are presented below (in thousands). Income taxes are different from incometaxes shown in the Consolidated Statements of Operations because this tableexcludes general and administrative and interest expense.

 

109

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| ** **                                | ** ** | **United States** | ** ** | **Canada** | ** ** | **Total**  | ** ** |
|-------------------------------------------|------------|-------------------|------------|------------|------------|------------|------------|
| **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 and 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 |   |

 

**(D) Estimated Proved Oil and GasReserves**—Estimates of the Company’s proved and proveddeveloped future net recoverable oil and gas reserves and changes for 2003 and2002 follow. Proved oil and gas reserves are the estimated quantities of crudeoil, natural gas and natural gas liquids which geological and engineering datademonstrate with reasonable certainty to be recoverable in future years fromknown reservoirs under existing economic and operating conditions based onprices and costs as of the date of the estimate. Proved quantities of crude oiland natural gas liquids were not significant in any of the years presented.

 

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

 

Reserve estimates are subject to numerousuncertainties inherent in the estimation of quantities of proved reserves andin the projection of future rates of production and the timing of developmentexpenditures. The accuracy of such estimates is a function of the quality ofavailable data and of engineering and geological interpretation and judgment.Estimates of economically recoverable reserves and of future net cash flowsexpected there from prepared by different engineers or by the same engineers atdifferent times may vary substantially. Results of subsequent drilling, testing and production may cause eitherupward or downward revisions of previous estimates. Further, the volumesconsidered to be commercially recoverable fluctuate with changes in commodityprices and operating costs.

 

110

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| ** **                         | ** ** | **Gas**           | ** ** |
|------------------------------------|------------|-------------------|------------|
| ** **                         | ** ** | ** **        | ** ** | **(MMcfe)** | ** ** | ** ** | ** ** |
| ** **                         | ** ** | **United States** | ** ** | **Canada** | ** ** | **Total** | ** ** |
| Total proved reserves:             | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** |
| 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,  2002            |       | 37,327            |       | 28,752 |   | 66,079 |   |
| December 31,  2003            |       | 242               |       | — |   | 242 |   |

 

**(E) Standardized Measure of Discounted Future Net Cash Flows—**Estimateddiscounted future net cash flows and changes therein were determined inaccordance with SFAS No. 69, *Disclosures about Oil andGas Producing Activities.*Certain information concerning theassumptions used in computing the valuation of proved reserves and theirinherent limitations are discussed below. The Company believes such informationis essential for a proper understanding and assessment of the data presented.

 

Futurecash inflows are computed by applying year-end prices of oil and gas relatingto the Company’s proved reserves to the year-end quantities of those reserves.Future price changes are considered only to the extent provided by contractualarrangements, including hedging contracts in existence at year-end.

 

Theassumptions used to compute estimated future net revenues do not necessarilyreflect the Company’s expectations of actual revenues or costs, or theirpresent worth. In addition, variations from the expected production rate alsocould result directly or indirectly from factors outside of the Company’scontrol, such as unintentional delays in development, changes in prices orregulatory controls. The reserve valuation further assumes that all reserveswill be disposed of by production. However, if reserves are sold in place,additional economic considerations could also affect the amount of casheventually realized.

 

111

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Futuredevelopment and production costs are computed by estimating the expenditures tobe incurred in developing and producing the proved reserves at the end of theyear, based on year-end costs and assuming continuation of existing economicconditions.

 

As of December 31,2002, future income tax expenses were estimated using a combined federal andstate income tax rate of 38.8% in the United States and a combined federal andprovincial rate of 43.25% in Canada. As of December 31, 2003, remainingtax attributes are expected to eliminate future income taxes. Permanentdifferences in Canadian resource allowances and natural gas-related tax creditswere recognized. Estimates for future general and administrative and interest expensehave not been considered.

 

Anannual discount rate of 10% was used to reflect the timing of the future netcash 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 |   |

 
| ** **                                                | ** ** | **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 valueof future net cash flows before income taxes was $67,524 in the United Statesand $63,751 in Canada at December 31, 2002.

 

**Changesin the Standardized Measure of Discounted Future Net Cash Flows Relating toProved Gas Reserves**—An analysis of the changes in thestandardized measure of discounted future net cash flows during each of theyears ended December 31, 2003 and 2002 is as follows (in thousands).

 
| ** **                                                                                                       | ** ** | **December 31, 2003** | ** ** |
|------------------------------------------------------------------------------------------------------------------|------------|----------------------------|------------|
| ** **                                                                                                       | ** ** | **United States**          | ** ** | **Canada** | ** ** | **Total** | ** ** |
| ** **                                                                                                       | ** ** | ** **                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| 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 |   |

 

112

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The computationof the standardized measure of discounted future net cash flows relating toproved oil and gas reserves at December 31, 2003, was based on year-endnatural 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 computationof the standardized measure of discounted future net cash flows relating toproved oil and gas reserves at December 31, 2002, was based on year-endnatural gas prices of approximately $4.27 per Mcfe in the United States andapproximately $3.87 per Mcfe in Canada, equivalent to $4.74 per MMBtu at theHenry Hub.

 

**22.****         ****Valuation and Qualifying Accounts**

 
| ** **                            | ** ** | **Balance at  beginning of  period** | ** ** | **Charged to  costs and  expenses** | ** ** | **Deductions** | ** ** | **Balance at end  of period** | ** ** |
|---------------------------------------|------------|--------------------------------------|------------|-------------------------------------|------------|----------------|------------|-------------------------------|------------|
| ** **                            | ** ** | **(in thousands)**                   | ** ** |
| Allowance for doubtful  accounts:     |       |                                 |       |                                |       |           |       |                          |       |
| For  the year ended December 31: |       |                                 |       |                                |       |           |       |                          |       |
| 2004                                  |       | $                                    | 120        |                                | $          | 277            |       | $                             | (148       | ) | $ | 249 |   |
| 2003                                  |       | $                                    | 87         |                                | $          | 177            |       | $                             | (144       | ) | $ | 120 |   |
| 2002                                  |       | $                                    | —     |                                | $          | 128            |       | $                             | (41        | ) | $ | 87 |   |

 

113

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During the fourth quarter of 2001, Enron Corporationand its subsidiaries (“Enron”) filed for bankruptcy protection.  In response to this filing, the Companyterminated all derivative contracts where Enron was the counterparty.  As a result, in 2001 the Company wrote off$1.1 million of derivative instruments related to its cash flow hedges offsetby $0.1 million of derivative instruments related to its fair valuehedges.  In the third quarter of 2004,the Company sold its claim to these assets for $0.8 million and recorded theproceeds to miscellaneous income.

 

**23.  Restatement of Consolidated FinancialStatements**

 

TheCompany has determined that, in certain cases, it did not comply with generallyaccepted accounting principles in the Company’s 2002 and 2003 consolidatedfinancial statements and, accordingly, it has restated its 2002 and 2003 annualfinancial statements.  The Company hasalso filed Form 10-Q/As for the first three quarters of 2004 to restateits quarterly financial information for 2003 and 2004.

 

TheCompany has determined that earlier issued financial statements for the years2002 and 2003 and the first three quarters of 2003 and 2004 should be restatedto reflect compensation expense in the Company’s financial statements for thesale of subordinated units of MarkWest Energy and interests in the Partnership’sgeneral partner to certain of its employees and directors from 2002 through2004 and for an error in accounting for natural gas inventory in the fourthquarter of 2003.

 

Therestatements primarily result from compensation expense attributed to the saleof a portion of MarkWest Hydrocarbon’s subordinated Partnership units andinterests in the Partnership’s general partner to certain employees anddirectors from 2002 through 2004. MarkWest Hydrocarbon had historically recorded the sale of thesubordinated Partnership units and interests in the Partnership’s generalpartner to certain of MarkWest Hydrocarbon’s employees and directors as a saleof an asset.  These arrangements arereferred to as the Participation Plan. However, MarkWest Hydrocarbon determined that these transactions shouldbe accounted for as compensatory arrangements, pursuant to the guidance in APB No. 25,*Accounting for Stock Issued to Employees*andEITF No. 95-16, *Accounting for StockCompensation Arrangements with Employer Loan Features under APB Opinion No. 25*.  This guidance requires MarkWest Hydrocarbonto record compensation expense for the difference between the market value ofthe subordinated Partnership units and the formula value of the general partnerinterests held by the employees and directors at the end of each reportingperiod*. *****Therestatement increased selling, general and administrative expenses by $1.4million and $0.2 million and eliminated the gain on sale of non-operatingassets to related party previously reported of $0.4 million and $0.1 millionfor the years ended December 31, 2003 and 2002, respectively.  In addition, the restatement decreased thenon-controlling interest in net income of consolidated subsidiary by $0.2million for the year ended December 31, 2003.  The impact of this restatement adjustment wasto reduce net income per basic and diluted share by $0.10 and $0.02 for theyear ended December 31, 2003 and 2002, respectively.****

 

The Company hasalso restated revenue for 2003 by $0.1 million to record natural gas inventoryin pipelines at cost.  Previously, theinventory was incorrectly identified as a pipeline imbalance and was recordedas a receivable at fair value.  Theimpact of this restatement adjustment was to reduce net income per basic anddiluted share by $0.01 for the year ended December 31, 2003.  An adjustment was also made to restate $2.5million in restricted marketable securities from restricted cash.  Finally, the Company adjusted the income taxprovision (benefit) for the restatement adjustments.  All amounts in the accompanying financialstatements have been adjusted for these restatements.

 

 For the year ended December 31, 2003, netcash provided by operating activities increased by $0.1 million and net cashprovided by financing activities decreased by a corresponding amount toreclassify the contribution of treasury shares to the 401(k) benefit plan fromfinancing activities to operating activities and to reflect distributions paidunder the Participation Plan as an operating activity.  For the year ended December 31, 2002,net cash provided by operating activities increased by $0.2 million and netcash used in financing activities increased by a corresponding amount toreclassify the contribution of treasury shares to 401(k) benefit plan fromfinancing activities to operating activities and to reflect distribution paidunder the Participation Plan as an operating activity.  In addition, for the year ended December 31,2002, net cash provided by operating activities also increased by $0.2 millionand net cash used in financing activities increased by a corresponding amountto reflect the proceeds from the sale of membership interests

 

114

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in the Partnership froma related party as an operating activity.

 

On October 28,2004, the Company’s Board of Directors declared a stock dividend of one shareof MarkWest Hydrocarbon’s common stock for each ten shares owned bystockholders.  The stock dividend waspaid on November 19, 2004 to the stockholders of record as of the close ofbusiness on November 9, 2004. Common stock information has been restated to give retroactive effect tothe stock dividend paid. The Company has reclassified certain 2002 and 2003financial statement components to conform to the 2004 presentation, see Note2.  Information under the headings “aspreviously reported” have been adjusted for the reclassifications ofdiscontinued operations.

 

115

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**Balance Sheet Amounts (in thousands):**

 
| ** **                                           | ** ** | **December 31, 2003** | ** ** |
|------------------------------------------------------|------------|----------------------------|------------|
| ** **                                           | ** ** | **As Previously Reported** | ** ** | **Restatement Adjustments** | ** ** | **As Restated** | ** ** |
| Assets:                                              |       |                       |       |   |   |   |   |
| Current assets:                                      |       |                       |       |   |   |   |   |
| Restricted  cash                                     |       | $                          | 2,500      |   | (2,500 | ) | $ | — |   |
| Restricted  marketable securities                    |       | —                     |       | 2,500 |   | 2,500 |   |
| Receivables,  net                                    |       | 30,750                     |       | (840 | ) | 29,910 |   |
| Inventories                                          |       | 4,815                      |       | 733 |   | 5,548 |   |
| Deferred  income taxes                               |       | 603                        |       | (69 | ) | 534 |   |
| Total current assets                                 |       | 87,255                     |       | (176 | ) | 87,079 |   |
|                                                 |       |                       |       |   |   |   |   |
| Deferred  offering costs and other, net              |       | 1,037                      |       | (42 | ) | 995 |   |
| Total  other assets                                  |       | 5,335                      |       | (42 | ) | 5,293 |   |
| Total assets                                         |       | $                          | 280,713    |   | $ | (218 | ) | $ | 280,495 |   |
|                                                 |       |                       |       |   |   |   |   |
| Liabilities:                                         |       |                       |       |   |   |   |   |
| Current liabilities:                                 |       |                       |       |   |   |   |   |
| Accrued  liabilities                                 |       | $                          | 16,751     |   | $ | (240 | ) | $ | 16,511 |   |
| Total  current liabilities                           |       | 42,572                     |       | (240 | ) | 42,332 |   |
|                                                 |       |                       |       |   |   |   |   |
| Deferred income taxes                                |       | 6,346                      |       | (752 | ) | 5,594 |   |
| Other long-term  liabilities                         |       | 504                        |       | 2,397 |   | 2,901 |   |
| Non-controlling  interest in consolidated subsidiary |       | 52,782                     |       | (353 | ) | 52,429 |   |
|                                                 |       |                       |       |   |   |   |   |
| Stockholders’ equity:                           |       |                       |       |   |   |   |   |
| Retained  earnings (deficit)                         |       | 3,676                      |       | (1,270 | ) | 2,406 |   |
| Total  stockholders’ equity                     |       | 52,184                     |       | (1,270 | ) | 50,914 |   |
| Total  liabilities and stockholders’ equity     |       | $                          | 280,713    |   | $ | (218 | ) | $ | 280,495 |   |

 

116

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**IncomeStatement Amounts (in thousands):**

 
| ** **                                                                                                                  | ** ** | **Year Ended December 31, 2003** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                                                                  | ** ** | **As Previously Reported**            | ** ** | **Restatement Adjustments** | ** ** | **As Restated** | ** ** |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Revenues                                                                                                                    |       | $                                     | 209,375    |   | $ | (107 | ) | $ | 209,268 |   |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Operating expenses:                                                                                                         |       |                                  |       |   |   |   |   |
| Selling,  general and administrative expenses                                                                               |       | 14,465                                |       | 1,400 |   | 15,865 |   |
| Total  operating expenses                                                                                                   |       | 233,948                               |       | 1,400 |   | 235,348 |   |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Loss  from operations                                                                                                       |       | (24,573                               | )          | (1,507 | ) | (26,080 | ) |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Other income and  (expense):                                                                                                |       |                                  |       |   |   |   |   |
| Gain  on sale of non-operating assets to related parties                                                                    |       | 382                                   |       | (382 | ) | — |   |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Loss  from continuing operations before non-controlling interest in net income of  consolidated subsidiary and income taxes |       | (30,628                               | )          | (1,889 | ) | (32,517 | ) |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Provision (benefit) for  income taxes:                                                                                      |       |                                  |       |   |   |   |   |
| Current                                                                                                                     |       | (13,656                               | )          | (24 | ) | (13,680 | ) |
| Deferred                                                                                                                    |       | 1,156                                 |       | (561 | ) | 595 |   |
| Benefit  for income taxes                                                                                                   |       | (12,500                               | )          | (585 | ) | (13,085 | ) |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Non-controlling  interest in net income of consolidated subsidiary                                                          |       | (3,236                                | )          | 248 |   | (2,988 | ) |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Loss  from continuing operations                                                                                            |       | (21,364                               | )          | (1,056 | ) | (22,420 | ) |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Loss before cumulative  effect of accounting change                                                                         |       | (9,921                                | )          | (1,056 | ) | (10,977 | ) |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Net  loss                                                                                                                   |       | $                                     | (9,950     | ) | $ | (1,056 | ) | $ | (11,006 | ) |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Loss from continuing  operations per share:                                                                                 |       |                                  |       |   |   |   |   |
| Basic                                                                                                                       |       | $                                     | (2.07      | ) | $ | (0.10 | ) | $ | (2.17 | ) |
| Diluted                                                                                                                     |       | $                                     | (2.07      | ) | $ | (0.10 | ) | $ | (2.17 | ) |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Net loss per share:                                                                                                         |       |                                  |       |   |   |   |   |
| Basic                                                                                                                       |       | $                                     | (0.96      | ) | $ | (0.11 | ) | $ | (1.07 | ) |
| Diluted                                                                                                                     |       | $                                     | (0.96      | ) | $ | (0.11 | ) | $ | (1.07 | ) |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Weighted average number  of outstanding shares of common stock:                                                             |       |                                  |       |   |   |   |   |
| Basic                                                                                                                       |       | 10,328                                |       |   |   | 10,328 |   |
| Diluted                                                                                                                     |       | 10,347                                |       |   |   | 10,347 |   |

 

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| ** **                                                                                                                  | ** ** | **Year Ended December 31, 2002** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                                                                  | ** ** | **As Previously  Reported**           | ** ** | **Restatement  Adjustments** | ** ** | **As Restated** | ** ** |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Operating expenses:                                                                                                         |       |                                  |       |   |   |   |   |
| Selling,  general and administrative expenses                                                                               |       | $                                     | 9,420      |   | $ | 194 |   | $ | 9,614 |   |
| Total  operating expenses                                                                                                   |       | 160,107                               |       | 194 |   | 160,301 |   |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Loss  from operations                                                                                                       |       | (4,320                                | )          | (194 | ) | (4,514 | ) |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Other income and  (expense):                                                                                                |       |                                  |       |   |   |   |   |
| Gain  on sale of non-operating assets to related parties                                                                    |       | 141                                   |       | (141 | ) | — |   |
| Loss  from continuing operations before non-controlling interest in net income of  consolidated subsidiary and income taxes |       | (5,550                                | )          | (335 | ) | (5,885 | ) |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Provision (benefit) for  income taxes:                                                                                      |       |                                  |       |   |   |   |   |
| Deferred                                                                                                                    |       | (2,935                                | )          | (122 | ) | (3,057 | ) |
| Benefit  for income taxes                                                                                                   |       | (2,935                                | )          | (122 | ) | (3,057 | ) |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Loss  from continuing operations                                                                                            |       | (4,562                                | )          | (213 | ) | (4,775 | ) |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Loss  before cumulative effect of accounting change                                                                         |       | (2,796                                | )          | (213 | ) | (3,009 | ) |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Net  loss                                                                                                                   |       | $                                     | (2,796     | ) | $ | (213 | ) | $ | (3,009 | ) |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Loss from continuing  operations per share:                                                                                 |       |                                  |       |   |   |   |   |
| Basic                                                                                                                       |       | $                                     | (0.44      | ) | $ | (0.02 | ) | $ | (0.46 | ) |
| Diluted                                                                                                                     |       | $                                     | (0.44      | ) | $ | (0.02 | ) | $ | (0.46 | ) |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Net loss per share:                                                                                                         |       |                                  |       |   |   |   |   |
| Basic                                                                                                                       |       | $                                     | (0.27      | ) | $ | (0.02 | ) | $ | (0.29 | ) |
| Diluted                                                                                                                     |       | $                                     | (0.27      | ) | $ | (0.02 | ) | $ | (0.29 | ) |
|                                                                                                                        |       |                                  |       |   |   |   |   |
| Weighted average number  of outstanding shares of common stock:                                                             |       |                                  |       |   |   |   |   |
| Basic                                                                                                                       |       | 10,285                                |       |   |   | 10,285 |   |
| Diluted                                                                                                                     |       | 10,301                                |       |   |   | 10,301 |   |

 

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**CashFlow Amounts (in thousands):**

 
| ** **                                 | ** ** | **Year Ended December 31, 2003** | ** ** |
|--------------------------------------------|------------|---------------------------------------|------------|
| ** **                                 | ** ** | **As Previously Reported**            | ** ** | **Restatement Adjustment** | ** ** | **As Restated** | ** ** |
| **Cash flows from operating  activities:** |       |                                  |       |   |   |   |   |
| Net  cash used in operating activities     |       | $                                     | (6,522     | ) | $ | 111 |   | $ | (6,411 | ) |
|                                       |       |                                  |       |   |   |   |   |
| **Cash flows from operating  activities:** |       |                                  |       |   |   |   |   |
| Net  cash provided by financing activities |       | $                                     | 79,067     |   | $ | (111 | ) | $ | 78,956 |   |

** **
| ** **                                 | ** ** | **Year Ended December 31, 2002** | ** ** |
|--------------------------------------------|------------|---------------------------------------|------------|
| ** **                                 | ** ** | **As Previously Reported**            | ** ** | **Restatement Adjustment** | ** ** | **As Restated** | ** ** |
| **Cash flows from operating  activities:** |       |                                  |       |   |   |   |   |
| Net  cash provided by operating activities |       | $                                     | 35,879     |   | $ | 422 |   | $ | 36,301 |   |
|                                       |       |                                  |       |   |   |   |   |
| **Cash flows from investing  activities:** |       |                                  |       |   |   |   |   |
| Net  cash provided by operating activities |       | $                                     | (22,479    | ) | $ | (240 | ) | $ | (22,719 | ) |
|                                       |       |                                  |       |   |   |   |   |
| **Cash flows from operating  activities:** |       |                                  |       |   |   |   |   |
| Net  cash used in financing activities     |       | $                                     | (9,338     | ) | $ | (182 | ) | $ | (9,520 | ) |

 

 

**Statement of Stockholders’ Equity (in thousands):**

 
| ** **                                               | ** ** | **Retained  Earnings  (Deficit)** | ** ** |
|----------------------------------------------------------|------------|-----------------------------------|------------|
|                                                     |       |                              |       |
| Balance,  December 31, 2002, as previously reported |       | $                                 | 13,625     |   |
| Restatement adjustments                                  |       | (213                              | )          |
| Balance,  December 31, 2002, as restated            |       | $                                 | 13,412     |   |
|                                                     |       |                              |       |
| Balance,  December 31, 2003, as previously reported |       | $                                 | 3,676      |   |
| Restatement adjustments                                  |       | (1,270                            | )          |
| Balance,  December 31, 2003, as restated            |       | $                                 | 2,406      |   |

 

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

 

On February 23, 2004, MarkWestHydrocarbon, Inc. dismissed PricewaterhouseCoopers LLP as its independentaccountants effective upon the filing of the Company’s Form 10-K forfiscal year ended December 31, 2003. Our Form 10-K was filed on March 30,2004. The Audit Committee of the Board of Directors participated in,recommended and approved the decision to change independent accountants.

 

The report of PricewaterhouseCoopers LLP onthe consolidated financial statements for the years ended December 31,2003 and 2002 contains no adverse opinion or disclaimer of opinion and was notqualified or modified as to uncertainty, audit scope or accounting principle.

 

In connection with its audits for the yearsended December 31, 2003 and 2002 and through March 30, 2004, therehave been no disagreements with PricewaterhouseCoopers LLP on any matter ofaccounting principles or practices, financial statement disclosure or auditingscope or procedure, which disagreements, if not resolved to the satisfaction ofPricewaterhouseCoopers LLP would have caused them to make reference thereto intheir report on financial statements for such years.

 

During the two years ended December 31,2003 and through March 30, 2004, there have been no “Reportable Events”(as defined in Regulation S-K, Item 304(a)(1)(v)), other than as disclosedin our Quarterly Report on Form 10-Q for the three months ended June 30,2003, in respect of internal controls and procedures related to the reportingof certain hedge transactions entered into with a related party.  As previously disclosed, once the reportingdeficiency was discovered, our Audit Committee retained PricewaterhouseCoopersto assist it in assessing if there were any material deficiencies in ourdisclosure controls and procedures. Following the performance of its review, PricewaterhouseCoopers provideda report to the Audit Committee that the deficiency constituted a materialweakness under Statement on Auditing Standards No. 60.  The Audit Committee addressed the hedgingdisclosure omission by directing the Company not to enter into any futurerelated party hedging transactions and by implementing enhanced proceduresdesigned to identify any related party transaction that might requiredisclosure.  In addition, as disclosed inour Annual Report on Form 10-K for the year ended December 31, 2003,PricewaterhouseCoopers LLC identified to the Company’s management and AuditCommittee in connection with the audit for fiscal 2003 certain deficiencies inthe Company’s internal controls that, when considered collectively, may beconsidered a material weakness.  TheCompany has authorized PricewaterhouseCoopers LLP to respond fully to theinquiries of KPMG LLP regarding the foregoing.

 

On April 12, 2004, the Audit Committee of the Board ofDirectors, engaged KPMG LLP as our independent accountants for the yearending December 31, 2004.  The Company has not consulted withKPMG LLP during the years ended December 31, 2003 and 2002 or duringany subsequent interim period prior to its appointment as auditor regarding theapplication of accounting principles to a specified transaction, eithercompleted or proposed, or the type of audit opinion that might be rendered onthe Company’s consolidated financial statements, or any matter that was eitherthe subject of a disagreement (as defined in Item 304(a)(1)(iv) ofRegulation S-K and the related instructions) or reportable event (withinthe meaning of Item 304(a)(1)(v) of Regulation S-K).

 

**ITEM 9A.  CONTROLS AND PROCEDURES**

 

***Evaluation of Disclosure Controls and Procedures***

 

As ofthe end of the period covered by this report, an evaluation was carried outunder the supervision and with the participation of our management, includingour Chief Executive Officer (“CEO”), our Chief Financial Officer (“CFO”), andour Chief Accounting Officer (“CAO”), of the effectiveness of the design andoperation of our disclosure controls and procedures (as defined in Rule 13a-15eof the Securities Exchange Act of 1934 (as amended, or the “Exchange Act”).  Disclosure controls and procedures arecontrols and procedures that are designed to ensure that information requiredto be disclosed in the Company’s reports filed or submitted under the ExchangeAct is recorded, processed, summarized and reported within the time periodsspecified in The Securities and Exchange Commission’s rules and forms.

 

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Based on this evaluation,our Chief Executive Officer, Chief Financial Officer and Chief AccountingOfficer concluded that as of December 31, 2004, as a result of thematerial weaknesses in our internal control over financial reporting discussedbelow, our disclosure controls and procedures were not effective.  Due to material weaknesses discussed below, inpreparing the Company’s financial statements as of and for the year ended December 31,2004, we performed additional analysis and other procedures to ensure that suchfinancial statements fairly present in all material respects our financialcondition, results of operations and cash flows in accordance with generallyaccepted accounting principles.

 

Through the date of thefiling of this Form 10-K, we have adopted remedial measures to address thedeficiencies in our internal controls that existed on December 31,2004.  In addition, we have appliedcompensating procedures and processes as necessary to ensure the reliability ofour financial reporting.  Such additionalprocedures included detailed management review of account reconciliations forall accounts in all business units, multiple level management review ofaccounting treatment for significant non-routine transactions and additionalreviews at the Southwest Business Unit by Corporate personnel.  Accordingly, management believes, based onits knowledge, that (i) this report does not contain any untrue statementof a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstance under which they were made, notmisleading with respect to the period covered by this report and (ii) thefinancial statements, and other financial information included in this report,fairly present in all material respects our financial condition, results ofoperations and cash flows as of, and for, the periods presented in this report.

 

***Material Weakness in Disclosure Controls and Procedures***

 

Based on our assessment,management has concluded that, as of December 31, 2004, we did notmaintain effective internal control over financial reporting due to thefollowing material weaknesses:

 

*IneffectiveControl Environment -*Our control environment did notsufficiently promote effective internal control over financial reporting throughoutour management structure, and this material weakness was a contributing factorin the development of other material weaknesses described below. Principalcontributing factors included the lack of adequate personnel with sufficientexpertise to perform accounting functions necessary to ensure preparation offinancial statements in accordance with generally accepted accountingprinciples, and a lack of adequate policies and procedures to enable the timelypreparation of reliable financial statements, as described more fully below.

 

To date, we have takenthe following step to remediate this material weakness:

 

•                  Wehave hired a Vice President of Compliance to coordinate our internal audit andinternal control compliance efforts.

 

*Insufficient technical accountingexpertise, inadequate policies and procedures related to accounting matters,and inadequate management review in the financial reporting process* – We did not have sufficienttechnical accounting expertise to address, or adequate policies and proceduresassociated with complex accounting matters. In addition, we did not maintain policies and procedures to ensureadequate management review of information supporting our financial statements.

 

To date, we have taken the following step to remediatethis material weakness:

 

•                  We have hired aVice President of Compliance to coordinate our internal audit and internalcontrol compliance efforts.

 

*Inadequate personnel, processes andcontrols at our Southwest Business Unit*-We did not have adequate personnel, policies, and procedures at the Partnership’sSouthwest Business Unit to enable timely preparation of reliable financialinformation for that business unit. Specifically, we identified the following internal control deficienciesat our Southwest Business Unit.

 

To date, we have taken the following steps toremediate this material weakness:

 

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•                  We haveformalized the monthly account reconciliation process for all balance sheetaccounts.  We have also implemented aformal review of these reconciliations by our business unit accountingmanagement.

 

•                  We haveinstituted a quarterly corporate review of all account reconciliations by thecorporate accounting staff and management.

 

•                  We have providedspecific training for our Southwest Business Unit accountants on our accountingsystems.

 

•                  We initiated theprocess of consistently comparing each month’s accrual to the actual results inan effort to further refine our estimation process.

 

•                  We have systematizedthe data gather function for the accounts payable invoices received afterperiod end.  This accrual is now reviewedmonthly by corporate accounting staff.

 

*Inadequately designed controls andprocedures over property, plant and equipment –* We did not haveadequately designed policies and procedures to ensure that costs associatedwith activities relating to our facilities were properly accounted for ascapital expenditures or maintenance expense. This material weakness in internalcontrol over financial reporting resulted in a material misstatement ofproperty, plant and equipment, and facilities expenses.

 

To date, we have taken thefollowing steps to remediate this material weakness:

 

•              We capitalizeinterest on major construction projects. The financial reporting team in our corporate office has assumed theresponsibility for calculating and recording capitalized interest relating tomajor construction projects.

 

•              A periodic reviewmeeting is now held by our Business Unit Managers to review issues with active,open construction projects.

 

•              We hired an internalaudit professional accounting firm.

 

***Planned Remediationof Internal Control Weaknesses***

 

Going forward, we expect to implement the followingadditional measures to strengthen our internal control processes.

 

•                  We are in theprocess of recruiting a Chief Accounting Officer with public company accountingand reporting technical expertise, and we intend to add at least one additionalstaff person with specific technical accounting and SEC reporting expertise tosupplement our existing internal technical accounting resources.

 

•                  We have begunour implementation processes of our new risk management and derivativetransaction reporting software.

 

•                  We plan toconduct in-depth training for all persons with coding responsibilities toensure clear and consistent understanding of capitalization policies.

 

Our Audit Committee has been and expects to remain activelyinvolved in overseeing the remediation planning and implementation.  The Company is fully committed to remediatingthe material weaknesses described above, and we believe that we are taking thesteps that will properly address these issues during 2005.  However, the remediation of the design of thedeficient controls and the associated testing efforts are not complete, andfurther remediation may be required.

 

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***Changes in Internal Controls over FinancialReporting***

 

During the quarter ended December 31, 2004, there wereno changes in our internal control over financial reporting that havematerially affected, or are reasonably likely to materially affect, ourinternal control over financial reporting.

 

# **ITEM 9B.  OTHER INFORMATION**

# ** **

# **None.**

# ** **

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# **PART III**

# ** **

**ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THEREGISTRANT**

 

The followingtable shows information for the directors and executive officers of MarkWestHydrocarbon, Inc.  Executiveofficers are appointed and directors are elected for three-year terms.

 
| **Name**             | ** ** | **Age** | ** ** | **Position  with our General Partner**             | ** ** |
|----------------------|------------|---------|------------|----------------------------------------------------|------------|
|                 |       |    |       |                                               |       |
| John M. Fox          |       | 65      |       | Chairman of the Board  of Directors                |       |
| William F. Wallace   |       | 65      |       | Director                                           |       |
| William A. Kellstrom |       | 61      |       | Director                                           |       |
| Donald C. Heppermann |       | 61      |       | Director                                           |       |
| Donald D. Wolf       |       | 61      |       | Director                                           |       |
| Karen L. Rogers      |       | 48      |       | Director                                           |       |
| Anne E. Mounsey      |       | 38      |       | Director                                           |       |
| Frank M. Semple      |       | 53      |       | President, Chief  Executive Officer and Director   |       |
| James G. Ivey        |       | 53      |       | Senior Vice President  and Chief Financial Officer |       |
| David L. Young       |       | 44      |       | Senior Vice President,  Northeast Business Unit    |       |
| John C. Mollenkopf   |       | 43      |       | Senior Vice President,  Southwest Business Unit    |       |
| Randy S. Nickerson   |       | 43      |       | Senior Vice President,  Corporate Development      |       |
| Ted S. Smith         |       | 54      |       | Vice President and  Chief Accounting Officer       |       |
| C. Corwin Bromley    |       | 47      |       | Vice President, General  Counsel and Secretary     |       |
| Andrew L. Schroeder  |       | 46      |       | Vice President, Finance  and Treasurer             |       |

 

**JohnM. Fox** has served as MarkWest Hydrocarbon’s Chairman of theBoard of Directors since its inception in April 1988, and in the samecapacity for the general partner of MarkWest Energy since May 2002.  Mr. Fox also served as President andChief Executive Officer of MarkWest Hydrocarbon and the general partner ofMarkWest Energy from April 1988 until his retirement as President on November 1,2003 and his resignation as Chief Executive Officer effective December 31,2003.  Mr. Fox was a founder ofWestern Gas Resources, Inc. and was its Executive Vice President and ChiefOperating Officer from 1972 to 1986.

 

**William F. Wallace**has served as a member of theBoard of Directors of MarkWest Hydrocarbon since June 2004.  Prior to his retirement in 2001, Mr. Wallacewas Vice Chairman of the board of directors of Barrett Resources Corp. since1996, after being named to that position in 1995 following the merger ofBarrett Resources and Plains Petroleum Co., both oil and gas explorationcompanies.  From 1994 to 1995, Mr. Wallacewas President, Chief Operating Officer and a Director of Plains PetroleumCo.  Prior to joining Plains Petroleum, Mr. Wallacespent 23 years with Texaco Inc., an integrated oil and gas company, includingsix years as Vice President of Exploration for Texaco USA and as Regional VicePresident of Texaco’s Eastern Region.  Mr. Wallacehas served on the Kerr McKee Corporation board of directors since 2004.  Previously, he served as a director ofWestport Resources Corporation from 1997 until Westport’s merger with KerrMcKee Corporation in 2004.

 

**WilliamA. Kellstrom** has served as a member of the Board of Directorsof MarkWest Hydrocarbon since May 2000 and the general partner of MarkWestEnergy since its inception in May 2002. Mr. Kellstrom has held a variety of managerial positions in thenatural gas industry since 1968.  Theyinclude distribution, pipelines and marketing. He held various management andexecutive positions with Enron Corporation, including Executive Vice President,Pipeline Marketing and Senior Vice President, Interstate Pipelines.  In 1989, he created and was President ofTenaska Marketing Ventures, a gas marketing company for the Tenaska PowerGroup.  From 1992 until 1997 he was withNorAm Energy Corporation (since merged with Reliant Energy, Incorporated) wherehe was President of the Energy Marketing Company and Senior Vice President,Corporate Development.  Mr. Kellstromretired in 1997 and is periodically engaged as a consultant to energycompanies.

 

**DonaldC. Heppermann** served as Executive Vice President, ChiefFinancial Officer and Secretary of MarkWest Hydrocarbon, Inc. and thegeneral partner of MarkWest Energy since October 2003 until his retirementin

 

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March 2004.  Mr. Heppermann joined MarkWestHydrocarbon and the general partner of the Partnership in November 2002 asSenior Vice President and Chief Financial Officer, and served as SeniorExecutive Vice President beginning in January 2003.  Mr. Heppermann has served as a member ofthe Company’s Board of Directors since November 2002 and the generalpartner of the Partnership’s board of directors since its inception in May 2002and serves as Chairman of the Finance Committee.  Prior to joining MarkWest Hydrocarbon and thegeneral partner of MarkWest Energy, Mr. Heppermann was a private investorand a career executive in the energy industry with responsibilities inoperations, finance, business development and strategic planning.  From 1990 to 1997, Mr. Heppermann servedas President and Chief Operating Officer for InterCoast Energy Company, anunregulated subsidiary of Mid American Energy Company.  From 1987 to 1990, Mr. Heppermann wasemployed by Pinnacle West Capital Corporation, the holding company for ArizonaPublic Service Company, where he was Vice President of Finance.  From 1965 to 1987, Enron Corporation and itspredecessors employed Mr. Heppermann in a variety of positions, includingExecutive Vice President, Gas Pipeline Group.

 

**Donald D. Wolf**has served as a member of theCompany’s Board of Directors since June 1996.  In September 2004, Mr. Wolf joinedAspect Energy as President and Chief Executive Officer.  Mr. Wolf served as Chairman, ChiefExecutive Officer and Director of Westport Resources Corporation from April 2000until Westport’s merger with Kerr McKee Corporation in 2004.  He joined Westport Oil and Gas Company, Inc.in June 1996 as Chairman and Chief Executive Officer and has a diversified35-year career in the oil and natural gas industry.

 

**KarenL. Rogers**has served as a member of the Board of Directors ofMarkWest Hydrocarbon since June 2000. In June 2005, Ms. Rogers joined Blacksand Energy, Inc., aprivately held oil and gas development and production company, as the chieffinancial officer.  Prior to joiningBlacksand Energy, Inc. Ms. Rogers was employed since 2000 as VicePresident, Energy Group, for Wells Fargo Bank N.A.  Prior to 1997, Ms. Rogers was SeniorVice President and Manager of NationsBank Energy Group Denver, Inc.  She has more than 25 years of experience inenergy finance and corporate banking.

 

**Anne E. Mounsey**has served as a member of theCompany’s Board of Directors since October 2004.  From 1991 to 2003, Ms. Mounsey heldvarious positions with the Company, her most recent as Manager of Marketing andBusiness Development.  Ms. Mounseyis the daughter of John M. Fox, the Company’s Chairman of the Board of Directors.

 

**FrankM. Semple** was appointed as President of both MarkWestHydrocarbon and the general partner of MarkWest Energy on November 1,2003.  Mr. Semple also became ChiefExecutive Officer of both MarkWest Hydrocarbon and the general partner ofMarkWest Energy on January 1, 2004. Prior to his appointment, Mr. Semple served in various capacities,lastly as Chief Operating Officer, with WilTel Communications, formerlyWilliams Communications Group, Inc. (“WCG”) from 1997 to 2003.  Prior to his tenure at WilTel Communications,he was the Senior Vice President/General Manager of Williams Natural Gas from1995 to 1997 as well as Vice President of Marketing and Vice President ofOperations and Engineering for Northwest Pipeline and Director of Product Movementsand Division Manager for Williams Pipeline during his 22-year career with TheWilliams Companies.  During his tenure atWilliams Communications, he served on the board of directors for PowerTelCommunications and the Competitive Telecommunications Association (Comptel). Hecurrently serves on the board of directors for the Tulsa Zoo and the Children’sMedical Center.  On April 22, 2002,WCG and one of its subsidiaries (“Debtors”) filed a petition for relief underthe Bankruptcy Code with the United States Bankruptcy Court for the SouthernDistrict of New York.  On September 30,2002, the Bankruptcy Court entered an order confirming the Debtors’ plan ofreorganization that became effective October 15, 2002.

 

**JamesG. Ivey** has served as Chief Financial Officer of bothMarkWest Hydrocarbon and the general partner of MarkWest Energy since June 2004.  Prior to joining the Company, Mr. Iveyserved as Treasurer of The Williams Companies from 1999 to April 30, 2004and as acting Chief Financial Officer from mid 2002 to mid 2003.  Prior to joining Williams, Mr. Ivey heldsimilar positions with Tenneco Gas and NORAM Energy.  Prior to that, he held various engineeringpositions with Conoco and Fluor Corporation. He currently serves on the boards of directors for MACH Gen LLC,National Energy & Gas Transmission, Inc. and the Tulsa BoysHome.  Mr. Ivey retired in early2004 from the Army Reserve with the rank of colonel.

 

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**DavidL. Young**was appointed Senior Vice President, NortheastBusiness Unit of MarkWest Hydrocarbon and the Partnership’s general partnereffective February 1, 2004. Prior to joining MarkWest, Mr. Youngspent eighteen years at The Williams Companies, Inc. in Tulsa, Oklahoma,having served most recently as Vice President and General Manager of the videoservices business for WilTel Communications, formerly WCG from 1997 to2003.  Prior to that, Mr. Young’smanagement positions at The Williams Companies included serving as Senior VicePresident and General Manager for Texas Gas Pipeline and Williams CentralPipeline Company.  On April 22,2002, the Debtors filed a petition for relief under the Bankruptcy Code withthe United States Bankruptcy Court for the Southern District of New York.  On September 30, 2002, the BankruptcyCourt entered an order confirming the Debtors’ plan of reorganization thatbecame effective October 15, 2002.

 

**JohnC. Mollenkopf** was appointed Senior Vice President, SouthwestBusiness Unit, of MarkWest Hydrocarbon and the general partner of MarkWestEnergy in January 2004.  Previouslyhe served as Vice President, Business Development of the Company since January 2003.  Prior to that, he served as Vice President,Michigan Business Unit, of MarkWest Energy’s general partner since its inceptionin May 2002 and in the same capacity with MarkWest Hydrocarbon since December 2001.  Prior to that, Mr. Mollenkopf wasGeneral Manager of the Michigan Business Unit of MarkWest Hydrocarbon since1997. He joined MarkWest Hydrocarbon in 1996 as Manager, New Projects.  From 1983 to 1996, Mr. Mollenkopf workedfor ARCO Oil and Gas Company, holding various positions in process and projectengineering, as well as operations supervision.

 

**RandyS. Nickerson** has served as Senior Vice President, Corporate Developmentof MarkWest Hydrocarbon and MarkWest Energy’s general partner since October 2003.  Prior to that, Mr. Nickerson served asExecutive Vice President, Corporate Development of the Partnership’s generalpartner since January 2003 and as Senior Vice President of the Partnership’sgeneral partner since its inception in May 2002 and has served in the samecapacity with MarkWest Hydrocarbon since December 2001. Prior to that, Mr. Nickersonserved as MarkWest Hydrocarbon’s Vice President and the General Manager of theAppalachia Business Unit since June 1997. Mr. Nickerson joinedMarkWest Hydrocarbon in July 1995 as Manager, New Projects and served asGeneral Manager of the Michigan Business Unit from June 1996 until June 1997.  From 1990 to 1995, Mr. Nickerson was aSenior Project Manager and Regional Engineering Manager for Western GasResources, Inc.  From 1984 to 1990, Mr. Nickersonworked for Chevron USA and Meridian Oil Inc. in various process and projectengineering positions.

 

**TedS. Smith**was appointed as Vice President, Chief AccountingOfficer of MarkWest Hydrocarbon and the Partnership’s general partner in March 2004.  Prior to that, he served as a Vice Presidentof MarkWest Hydrocarbon and the Partnership’s general partner since March 2003.  Prior to that time, Mr. Smith had beenSenior Vice President and Chief Financial Officer for Pinnacle Natural GasCorporation since 1999.  From 1994through 1999, he was Chief Financial Officer for Total Safety Inc., and from1987 to 1994, Mr. Smith served as Assistant Treasurer and Director ofManagement Information Systems at American Oil and Gas Corporation in Houston,Texas.  Prior to that, Mr. Smithheld various senior executive finance and accounting positions with severalenergy services organizations.  Mr. Smithis a Certified Public Accountant licensed in the state of Texas.

 

**C.Corwin Bromley** has served as Vice President, General Counseland Secretary of both MarkWest Hydrocarbon and the general partner of MarkWestEnergy since September 2004.  Prior tothat, Mr. Bromley served as Assistant General Counsel at RAG American CoalHolding, Inc. from 1999 through 2004, and as General-Managing Attorney atCyprus Amax Minerals Company from 1989 to 1999. Prior to that, Mr. Bromley spent four years in private practicewith the law firm Popham, Haik, Schnobrich and Kaufman.  Preceding his legal career, Mr. Bromleywas employed by CBI, Inc. as a structural/design engineer involved inseveral LNG and energy projects.

 

**AndrewL. Schroeder******has served as Vice President and Treasurer ofMarkWest Hydrocarbon and the Partnership’s general partner since February 2003.Prior to his appointment, he was Director of Finance/Business Development atCrestone Energy Ventures from 2001 through 2002.  Prior to that, Mr. Schroeder worked atXcel Energy for two years as Director of Corporate Financial Analysis.  Prior to that, he spent seven years workingwith various energy companies.  He beganhis career with Touche, Ross & Co. and spent eight years in publicaccounting.  He is a Certified PublicAccountant licensed in the state of Colorado.

 

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**AuditCommittee Financial Expert**

 

The members of theCompany’s Audit Committee of the Board of Directors are Mr. Kellstrom(chairman), Ms. Rogers, Mr. Wallace and Mr. Wolf. Each of theindividuals serving on our Audit Committee satisfies the standards forindependence of the AMEX and the SEC as they relate to audit committees.  Our Board of Directors believes each of themembers of the Audit Committee is financially literate.  In addition, our Board of Directors hasdetermined that Mr. Kellstrom is financially sophisticated and qualifiesas an “audit committee financial expert” within the meaning of the regulationsof the SEC.

 

**AuditCommittee Pre-Approval Policy**

 

TheAudit Committee pre-approves all audit and permissible non-audit servicesprovided by the independent auditors on a case-by-case basis.  These services may include audit services,audit-related services, tax services and other services.  Our Chief Accounting Officer or ChiefFinancial Officer are responsible for presenting the Audit Committee with anoverview of all proposed audit, audit-related, tax or other non-audit servicesto be performed by the independent auditors. The presentation must be insufficient detail to define clearly the services to be performed.  The Audit Committee does not delegate itsresponsibilities to pre-approve services performed by the independent auditorto management or to an individual member of the Audit Committee.  The Audit Committee may, however, from timeto time delegate its authority to the Audit Committee Chairman, Mr. Kellstrom,who reports on the independent auditor services approved by the Chairman at thenext Audit Committee meeting.  A copy ofthe Audit Committee’s Charter is available on our Internet website atwww.markwest.com.

 

**Code ofBusiness Conduct and Ethics**

 

We have adopted aCode of Business Conduct and Ethics, applicable to the persons serving as ourdirectors, officers (including, our Chief Executive Officer, Chief FinancialOfficer, Chief Accounting Officer and Vice President and Treasurer) andemployees, which includes the prompt disclosure to the SEC on a Current Reporton Form 8-K of any waiver of the code for executive officers or directorsapproved by the Board of Directors. A copy of our Code of Business Conduct andEthics is available free of charge in print to any person who sends a requestto the office of the Secretary of MarkWest Hydrocarbon, Inc. at 155Inverness Drive West, Suite 200, Englewood, Colorado 80112-5000.  The Code of Business Conduct and Ethics isalso posted on our Internet website at www.markwest.com.

 

**Section 16(a) BeneficialOwnership Reporting Compliance**

 

Section 16(a) ofthe Securities Exchange Act of 1934 requires our directors and executiveofficers, and persons who own more than 10% of any class of our equitysecurities registered under Section 12 of the Exchange Act, to file withthe SEC initial reports of ownership and reports of changes in ownership insuch securities and other equity securities of our Company. SEC regulationsalso require directors, executive officers and greater than 10% stockholders tofurnish us with copies of all Section 16(a) reports they file.

 

To ourknowledge, based solely on review of the copies of such reports furnished to usand written representations that no other reports were required, we believe ourdirectors, executive officers and greater than 10% stockholders complied withall Section 16(a) filing requirements during the year ended December 31,2004, except for the following:

 
| ** **          | ** ** | **No. of  Late  Reported  Transactions** | ** ** | **No. of  Late  Form 3 Filings** | ** ** | **No. of  Late  Form 4 Filings** | ** ** |
|---------------------|------------|-----------------------------------------------|------------|--------------------------------------------|------------|--------------------------------------------|------------|
| Mr. Fox        |       | 20                                            |       | —                                     |       | 20                                         |       |
| Mr. Ivey       |       | 2                                             |       | 1                                          |       | 1                                          |       |
| Mr. Wallace    |       | 4                                             |       | 1                                          |       | 3                                          |       |
| Mr. Heppermann |       | 1                                             |       | —                                     |       | —                                     |       |
| Mr. Denney     |       | 3                                             |       | —                                     |       | 3                                          |       |
| Ms. Mounsey    |       | 2                                             |       | 1                                          |       | 1                                          |       |

 

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Weare not aware of any other failure to file a Section 16(a) form withthe SEC, or any transaction that was required to be reported, but that was notreported on a timely basis.

 

# **ITEM 11.  EXECUTIVECOMPENSATION**

# ** **

The followingtable sets forth the cash and non-cash compensation earned for fiscal years2004, 2003 and 2002 by each person who served as Chief Executive Officer of theCompany in 2004 and the four other highest paid officers, whose salary andbonus exceeded $100,000 for services rendered during 2004 (the “Named ExecutiveOfficers”).

 

***SummaryCompensation Table***

 
| ** **                        | ** ** | ** **              | ** ** | ** **            | ** ** | ** **                | ** ** | **Long-Term Compensation** | ** ** |
|-----------------------------------|------------|-------------------------|------------|-----------------------|------------|---------------------------|------------|----------------------------|------------|
| ** **                        | ** ** | **Annual Compensation** | ** ** | **Restricted  Unit**  | ** ** | **Securities Underlying** | ** ** | **LTIP**                   | ** ** | **Other** | ** ** |
| **Name and Principal Positions**  | ** ** | **FiscalYear**          | ** ** | **Salary****($) (1)** | ** ** | **Bonus****($) (2)**      | ** ** | **awards  ($) (3)**        | ** ** | **Options  (#) (4)** | ** ** | **Payouts  ($) (5)** | ** ** | **Compensation  ($) (6)** | ** ** |
| Frank M. Semple                   |       | 2004                    |       | $                     | 280,385    |                      | $          | 47,250                     |       | $ | 108,750 |   | — |   | $ | 20,500 |   | $ | 52,838 |   |
| President and  Chief Executive    |       | 2003                    |       | 36,346                |       | 6,413                     |       | 279,000                    |       | 22,000 |   | 4,800 |   | 623 |   |
| Officer                           |       | 2002                    |       | —                |       | —                    |       | —                     |       | — |   | — |   | — |   |
|                              |       |                    |       |                  |       |                      |       |                       |       |   |   |   |   |   |   |
| James G. Ivey (7)                 |       | 2004                    |       | $                     | 126,154    |                      | $          | 5,979                      |       | $ | 251,500 |   | 11,000 |   | $ | 8,640 |   | $ | 37,408 |   |
| Chief Financial  Officer          |       | 2003                    |       | —                |       | —                    |       | —                     |       | — |   | — |   | — |   |
|                              |       | 2002                    |       | —                |       | —                    |       | —                     |       | — |   | — |   | — |   |
|                              |       |                    |       |                  |       |                      |       |                       |       |   |   |   |   |   |   |
| Randy S. Nickerson                |       | 2004                    |       | $                     | 181,155    |                      | $          | 30,625                     |       | $ | 108,750 |   | — |   | $ | 5,363 |   | $ | 13,686 |   |
| Senior Vice  President, Corporate |       | 2003                    |       | 164,743               |       | 23,515                    |       | 26,875                     |       | — |   | 10,675 |   | 13,193 |   |
| Development                       |       | 2002                    |       | 154,943               |       | 2,601                     |       | 110,000                    |       | — |   | 6,150 |   | 12,395 |   |
|                              |       |                    |       |                  |       |                      |       |                       |       |   |   |   |   |   |   |
| John C. Mollenkopf                |       | 2004                    |       | $                     | 180,865    |                      | $          | 30,625                     |       | $ | 65,250 |   | — |   | $ | 6,703 |   | $ | 13,426 |   |
| Senior Vice  President, Business  |       | 2003                    |       | 144,354               |       | 20,684                    |       | 59,475                     |       | — |   | 11,985 |   | 12,331 |   |
| Development                       |       | 2002                    |       | 129,322               |       | 2,171                     |       | 110,000                    |       | — |   | 6,150 |   | 10,346 |   |
|                              |       |                    |       |                  |       |                      |       |                       |       |   |   |   |   |   |   |
| David L. Young (8)                |       | 2004                    |       | $                     | 161,538    |                      | $          | 25,521                     |       | $ | 77,000 |   | 2,750 |   | $ | 4,380 |   | $ | — |   |
| Senior Vice  President, Northeast |       | 2003                    |       | —                |       | ——              |       | —                     |       | — |   | — |   | — |   |
| Business Unit                     |       | 2002                    |       | —                |       | —                    |       | —                     |       | — |   | — |   | — |   |

 

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(1)          Represents actual salarypaid in each respective year for services rendered on behalf of both thePartnership and MarkWest Hydrocarbon.

(2)          Represents actual bonuspaid in each respective year for services rendered on behalf of both thePartnership and MarkWest Hydrocarbon. Bonuses are paid in accordance withprovisions of MarkWest Hydrocarbon’s Incentive Compensation Plan.

(3)          Represents the value ofthe executive officer’s phantom unit award (calculated by multiplying theclosing market price of the Partnership’s units on the date of grant by thenumber of Partnership units awarded). Messrs Semple, Ivey, Nickerson, Mollenkopf and Young had Partnershipphantom units of 7,073, 6,769, 2,980, 1,980 and 1,406, respectively at December 31,2004 and with a value of $0.3 million, $0.3 million, $0.1 million, $0.1 millionand $0.1 million on that date.  Thephantom units vest over a period of three years.

(4)          Securities underlyingoptions have been adjusted to reflect the effect of the 10% stock dividend forstockholders of record as of November 9, 2004.

(5)          Represents distributionsreceived for the Partnership’s phantom units.

(6)          Represents actualMarkWest Hydrocarbon contributions under MarkWest Hydrocarbon’s 401(k) Savingsand Profit Sharing Plan.  Included in Mr. Semple’sand Mr. Ivey’s other compensation are relocation payments of $34,453 and$37,408, respectively.

(7)          Mr. Ivey became theChief Financial Officer on May 25, 2004. Mr. Ivey is currently being paid an annual salary of $205,000.

(8)          Mr. Young becamethe Senior Vice President of the Northeast Business Unit on February 2,2004.  Mr. Young is currently beingpaid an annual salary of $175,000.

 

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# **Option Grants in Last Year**

 

Thefollowing table provides information on the options granted to the NamedExecutive Officers during the year ended December 31, 2004.  Alloptions were granted under the Company’s 1996 Stock Incentive Plan.

 
| ** **     | ** ** | **Individual Grants**                          | ** ** | ** **                                              | ** ** | ** **                  | ** ** | ** **     | ** ** |
|----------------|------------|------------------------------------------------|------------|---------------------------------------------------------|------------|-----------------------------|------------|----------------|------------|
| ** **     | ** ** | **Number  of securities  underlying  Options** | ** ** | **Percent of  total options  granted to  employees in** | ** ** | **Exercise or  base price** | ** ** | **Expiration** | ** ** | **Potential realizable value at  assumed annual rates of stock  price appreciation for option term** | ** ** |
| ** **     | ** ** | **granted (#)**                                | ** ** | **year**                                                | ** ** | **($/Sh)**                  | ** ** | **date**       | ** ** | **5% ($)** | ** ** | **10% ($)** | ** ** |
| James G. Ivey  |       | 11,000                                         |       | 33                                                      | %          | 9.84                        |       | 5/25/2014      |       | $ | 176,312 |   | $ | 280,747 |   |
| David L. Young |       | 2,750                                          |       | 8                                                       | %          | 9.77                        |       | 2/02/2014      |       | 43,764 |   | 69,687 |   |
|                |            |                                                |            |                                                         |            |                             |            |                |            |  |  |  |  |  |  |

 

# **SAR Grants in Last Year**

 

TheCompany has also entered into arrangements with certain directors and officersof the Company.  These arrangements arereferred to as the Participation Plan. Under the Participation Plan, the Company sells subordinated partnershipunits of the Partnership and interests in the Partnership’s general partner toemployees and directors of the Company under a purchase and saleagreement.  The interests in the generalpartner are sold with certain put and call provisions that allow the individualto require MarkWest Hydrocarbon to buy back or requires the individual to sellback their interest in the general partner to MarkWest Hydrocarbon.  As the formula used to determine the sale andbuy-back price is not based on fair value, coupled with the attributes of theput and call provisions, these transactions are considered compensatoryarrangements, similar to a stock appreciation right.  The subordinated partnership units of thePartnership are also sold to the employees and directors at a formula that isnot based on fair value.  Thesubordinated units are sold without any restrictions on transfer.  However, the Company has established animplied repurchase obligation through its pattern of buying back thesubordinated units each time an employee or director has left MarkWestHydrocarbon.  The following tableprovides information on the potential appreciation of the interests in thePartnership’s general partner that were sold to the Named Executive Officersduring the year ended December 31, 2004.  There were no subordinated partnershipunits sold during 2004.  All interestswere sold under the Company’s Participation Plan.  The plan has not been approved by theStockholders.

 
| ** **    | ** ** | **Individual Grants**                                  | ** ** | ** **                 | ** ** | ** **                 | ** ** | ** **     | ** ** | ** **                                          | ** ** | ** **                    | ** ** |
|---------------|------------|--------------------------------------------------------|------------|----------------------------|------------|----------------------------|------------|----------------|------------|-----------------------------------------------------|------------|-------------------------------|------------|
| ** **    | ** ** | **Percent of  General  Partner  Interest  underlying** | ** ** | **Percent of  total SARs** | ** ** | ** **                 | ** ** | ** **     | ** ** | **Potential realizable  value at assumed annual**   | ** ** | **Grant date  value**         | ** ** |
| ** **    | ** ** | **SAR  granted**                                       | ** ** | **granted to  employees**  | ** ** | **Exercise or base price** | ** ** | **Expiration** | ** ** | **rates of stock price  appreciation for SAR term** | ** ** | **Grant Date  Present Value** | ** ** |
| ** **    | ** ** | **(%)**                                                | ** ** | **in year**                | ** ** | **($/Sh)**                 | ** ** | **date**       | ** ** | **5% ($)(2)**                                       | ** ** | **10% ($)(2)**                | ** ** | **($)** | ** ** |
| James G. Ivey |       | 0.5                                                    | %          | 71                         | %          | (1                         | )          | (2             | )          | $                                                   | 323,411    |                          | $          | 514,977 |   | $ | 198,546 |   |
|               |            |                                                        |            |                            |            |                            |            |                |            |                                                     |            |                               |            |  |  |  |  |  |

 

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(1)          TheCompany sells interests in the Partnership’s general partner under a variableplan to certain directors and employees of the Company.  These arrangements are referred to as theParticipation Plan.  Under theParticipation Plan, MarkWest Hydrocarbon sold 0.5% interest in the Partnership’sgeneral partner to Mr. Ivey under a purchase and sale agreement forapproximately $0.2 million.  The interestin the Partnership’s general partner are sold with certain put and callprovisions that allow the individual to require MarkWest Hydrocarbon to buyback or requires the individual to sell their interest in the general partnerto MarkWest Hydrocarbon.  Specifically,the employees and directors can exercise their put if (1) MarkWestHydrocarbon or the Partnership’s general partner undergoes a change of control;(2) additional membership interests are issued and if the issuance ofadditional membership interests, on a pro forma basis, decreases thedistributions to all the then existing members; (3) any amendment,alteration or repeal of the provisions of the general partner agreement isundertaken which materially and adversely affects the then existing rights, duties,obligations or restrictions of the employees and directors; or (4) theemployee or director (i) becomes totally disabled while a director,officer or employee of the general partner, of MarkWest Hydrocarbon or of anyof their affiliates after reaching the age of 60 years.  The employee or his estate has 120 days afterthe put event to exercise the put under (4) and 30 days after notice toexercise under (1) through (3). MarkWest Hydrocarbon can exercise its call option if the employee ordirector ceases to be a director or employee of MarkWest Hydrocarbon or any ofits affiliates or if there is a change of

 

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control.  The Company has 12 months following thetermination date to exercise its call option. As the formula used to determine the sale and buy-back price is notbased on fair value, coupled with the attributes of the put and callprovisions, these transactions are considered compensatory arrangements, similarto a stock appreciation right.  As thestock appreciation right is exercised through a callable or puttable event,there is no defined expiration date.

(2)          Theinterests in the Partnership’s general partner are sold without an expirationdate.  As a result, when calculating thepotential realizable value of the appreciation of the award, the Companyassumed a 10 year life to be consistent with the terms used on the Company’sother stock based compensation awards.

 

# **Aggregated Option Exercises in Last Year and Year-EndOption Values**

 

Thefollowing table provides information as to options exercised during the yearended December 31, 2004 and the value of outstanding options held by theNamed Executive Officers at December 31, 2004.

 
| ** **         | ** ** | **Shares  Acquired on** | ** ** | **Value  Realized** | ** ** | **Number of Securities  Underlying Unexercised  Options at End of  2004 (#)** | ** ** | **Value of Unexercised  In-the-Money Options at  End of 2004 ($)****(1)** | ** ** |
|--------------------|------------|-------------------------|------------|---------------------|------------|-------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------|------------|
| ** **         | ** ** | **Exercise (#)**        | ** ** | **($)**             | ** ** | **Exercisable**                                                               | ** ** | **Unexercisable**                                                         | ** ** | **Exercisable** | ** ** | **Unexercisable** | ** ** |
| Frank M. Semple    |       | —                  |       | $                   | —     |                                                                          | —     |                                                                      | 22,000     |   | $ | 44,000 |   | $ | 132,000 |   |
| James G. Ivey      |       | —                  |       | —              |       | —                                                                        |       | 11,000                                                                    |       | — |   | 81,510 |   |
| Randy S. Nickerson |       | 20,324                  |       | 91,212              |       | 20,323                                                                        |       | 3,508                                                                     |       | 74,540 |   | 9,624 |   |
| John C. Mollenkopf |       | —                  |       | —              |       | 5,997                                                                         |       | 1,122                                                                     |       | 7,798 |   | 12,723 |   |
| David L. Young     |       | —                  |       | —              |       | 1,958                                                                         |       | 3,342                                                                     |       | 6,718 |   | 11,003 |   |
|                    |            |                         |            |                     |            |                                                                               |            |                                                                           |            |  |  |  |  |  |  |  |

 

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(1)             Valuebased on the difference between the closing price of our common stock, asreported by the American Stock Exchange on December 31, 2004, and theoption price per share multiplied by the number of shares subject to theoption.

# ** **

# **Aggregated SAR Exercises in Last Year and Year-End SARValues**

 

Thefollowing table provides information as to the value of the subordinatedpartnership units of the Partnership and interests in the Partnership’s generalpartner held by the Named Executive Officers at December 31, 2004.  We did not buy back any of the subordinatedpartnership units of the Partnership or interests in the Partnership’s generalpartner from the Named Executive Officers during the year ended December 31,2004.

 
| ** **         | ** ** | **Percent of  General Partner  Interest  Underlying  Unexercised SAR  at End of 2004  (%)(1)** | ** ** | **Number of  Partnership  subordinated units  Underlying  Unexercised SAR at  End of 2004 (#)(1)** | ** ** | **Value of  GP Interest  Underlying  SAR at End of  2004 ($)(2)** | ** ** | **Value of  Subordinated  Units Underlying  SAR at End of  2004 ($)(3)** | ** ** |
|--------------------|------------|------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------|------------|--------------------------------------------------------------------------|------------|
| Frank M. Semple    |       | 2.0                                                                                            | %          | 5,000                                                                                              |       | $796,085                                                          |       | $100,830                                                                 |       |
| James G. Ivey      |       | 0.5                                                                                            | %          | —                                                                                             |       | 49,578                                                            |       | —                                                                   |       |
| Randy S. Nickerson |       | 1.6                                                                                            | %          | 4,626                                                                                              |       | 693,048                                                           |       | 149,050                                                                  |       |
| John C. Mollenkopf |       | 1.6                                                                                            | %          | 4,626                                                                                              |       | 693,048                                                           |       | 149,050                                                                  |       |

 

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(1)          TheCompany sells subordinated partnership units of the Partnership and interestsin the Partnership’s general partner under a variable plan to certain directorsand employees of the Company.  Thesearrangements are referred to as the Participation Plan.  Under the Participation Plan, MarkWest Hydrocarbonsells subordinated partnership units of the Partnership and interests in thePartnership’s general partner to employees and directors of the Company under apurchase and sale agreement.  Theinterest in the Partnership’s general partner are sold with certain put andcall provisions that allow the individual to require MarkWest Hydrocarbon tobuy back or requires the individual to sell their interest in the generalpartner to MarkWest Hydrocarbon. Specifically, the employees and directors can exercise their put if (1) MarkWestHydrocarbon or the Partnership’s general partner undergoes a change of control;(2) additional membership interests are issued and if the issuance ofadditional membership interests, on a pro forma basis, decreases the distributionsto all the then existing members; (3) any amendment, alteration or repealof the provisions of the general partner agreement is undertaken whichmaterially and adversely affects the then existing rights, duties, obligationsor restrictions of the employees and directors; or (4) the employee ordirector (i) becomes totally disabled while a director, officer oremployee of the general partner, of MarkWest Hydrocarbon or of any of theiraffiliates after reaching the age of 60 years. The employee or his estate has 120 days after the put event to exercisethe put under (4) and 30 days after notice to exercise under (1) through(3).  MarkWest Hydrocarbon can exerciseits call option if the employee or director ceases to be a director or employeeof MarkWest Hydrocarbon or any of its affiliates or if there is a change ofcontrol.  The Company has 12 monthsfollowing the

 

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terminationdate to exercise its call option.  As theformula used to determine the sale and buy-back price is not based on fairvalue, coupled with the attributes of the put and call provisions, thesetransactions are considered compensatory arrangements, similar to a stockappreciation right.  The subordinatedpartnership units of the Partnership are also sold to the employees anddirectors at a formula that is not based on fair value.  The subordinated units are sold without anyrestrictions on transfer.  However, theCompany has established an implied repurchase obligation through its pattern ofbuying back the subordinated units each time an employee or director has leftMarkWest Hydrocarbon.  The employees’ anddirectors’ subordinated units converted into MarkWest Energy’s common units on August 15,2005.

(2)          Thevalue of the executive’s interests in the Partnership’s general partner ismeasured as the difference in the formula value of the general partnerinterest, as measured at December 31, 2004, and the amount paid by theexecutive.  The formula value is theamount MarkWest Hydrocarbon would have to pay the employees and directors torepurchase the Partnership’s general partner interests which is derived fromthe current market value of the Partnership’s common units, as reported by theAmerican Stock Exchange on December 31, 2004, and the quarterlydistributions previously paid by the Partnership.

(3)          Thevalue of the executive’s subordinated partnership units of the Partnershipunderlying the executive’s is measured as the difference in the market value ofthe Partnership’s common units, as reported by the American Stock Exchange on December 31,2004, and the amount paid by the named executive.

 

## **IndemnificationAgreements**

## ** **

In February 2004, MarkWest Hydrocarbon entered intoIndemnification Agreements with certain directors and officers (“Indemnitees”).  By the terms of the IndemnificationAgreement, the Company shall indemnify Indemnitees to the fullest extentpermitted by law against all expenses and liabilities (as defined in theIndemnification Agreement) if Indemnitees were or are, or are threatened to bemade a party to, any threatened, pending or completed action, suit, proceeding,or alternative dispute resolution mechanism, whether civil, criminal,administrative, investigative or other and whether brought by or in the rightof the Company or otherwise, by reason of (or arising in part out of) any eventor occurrence related to the fact that Indemnitees are or were a director,officer, employee, agent or fiduciary of the Company, or any subsidiary of theCompany, or are or were serving at the request of the Company as a director,officer, employee, agent or fiduciary of another corporation, partnership,joint venture, trust or other enterprise, or by reason of any action orinaction on the part of the Indemnitees while serving in such capacity.

 

## **Non-Competition,Non-Solicitation and Confidentiality Agreement and Severance Plan**

## ** **

David Young,Randy Nickerson and John Mollenkopf are each a party to a Non-Competition,Non-Solicitation and Confidentiality Agreement. As a result of signing theNon-Competition, Non-Solicitation and Confidentiality Agreement, they areeligible for the MarkWest Hydrocarbon 1997 Severance Plan (the “1997 SeverancePlan”). The Severance Plan provides for payment of benefits in the event that (i) theemployee terminates his or her employment for “good reason” (as defined), (ii) theemployee’s employment is terminated “without cause” (as defined), (iii) theemployee’s employment is terminated by reason of death or disability or (iv) theemployee voluntarily resigns. In the case of (i), (ii) and (iii) above,the employee shall be entitled to receive base salary and continued medicalbenefits for a period ranging from six months to twenty-four months, dependingupon the employee’s status at the time of the termination. In the case of (iv) above,the employee shall be entitled to receive base salary for a period ranging fromone month to six months and continued medical benefits for a period rangingfrom one month to six months, as consideration for entering into the Non-Competition,Non-Solicitation, and Confidentiality Agreement. In either case, the aggregateamount of benefits paid to an employee shall in no event exceed twice theemployee’s annual compensation during the year immediately preceding thetermination.

 

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**Employment Agreement**

 

**Frank M. Semple**

 

Mr. Sempleentered into an executive employment agreement with MarkWest Hydrocarbon on November 1,2003, pursuant to which Mr. Semple serves as MarkWest Hydrocarbon’sPresident and Chief Executive Officer and pursuant to which the Board ofDirectors of MarkWest Hydrocarbon appointed Mr. Semple to serve as thePresident and Chief Executive Officer of the Partnership’s general partner. Theemployment agreement may be terminated by either Mr. Semple or MarkwestHydrocarbon at any time.

 

Under the employment agreement, Mr. Semplereceives an annual base salary and is entitled to receive benefits for whichemployees and/or executive officers are generally eligible.  In addition, Mr. Semple was awardedphantom units in the Partnership under the Partnership’s long-term incentiveplan and was awarded stock options under the MarkWest Hydrocarbon incentivestock option plan. Mr. Semple also agreed to purchase from MarkWestHydrocarbon an interest in each of the Partnership’s general partner and thePartnership, subject to certain repurchase rights by MarkWest Hydrocarbonfollowing the termination of his employment.

 

Under his employment agreement, in the event Mr. Semple’semployment is terminated without cause, or if he resigns for good reason, he isentitled to severance payments equal to his base salary for a period ofthirty-six months. In addition, Mr. Semple is entitled to COBRA benefitsfor a period of twenty-four months.  Inthe event Mr. Semple voluntarily resigns, he is entitled to receiveseverance payments equal to his base salary and COBRA benefits for a period ofsix months, as consideration for entering into the Non-Competition,Non-Solicitation and Confidentiality Agreement. In the event Mr. Semple isterminated for cause, he shall not be entitled to receive any severance orCOBRA benefits.

 

**Reimbursement of Expenses of the General Partner**

 

Prior to December 31,2003, the General Partner did not receive any management fee or othercompensation for its management of the Partnership.  The General Partner and its affiliates werereimbursed for expenses incurred on behalf of the Partnership.  These allocable expenses include the costs ofemployee, officer and director compensation and benefits properly allocable tothe Partnership, and all other expenses necessary or appropriate to the conductof the business.

 

Effective January 1,2004, MarkWest Hydrocarbon entered into a Services Agreement for the managementof the Partnership’s day-to-day operations and the administration.  For such management services, MarkWestHydrocarbon will receive a $5,000 annual management fee.  The General Partner and its affiliates willcontinue to be reimbursed for expenses incurred on behalf of the Partnership.

 

# **Director Compensation**

# ** **

On January 20,2005, the Board of Directors of the Company approved director compensation for2005.  Each independent director willreceive an annual retainer of $18,000 and 1,000 restricted shares per year.  In addition, each independent director willreceive compensation of $2,000 for either in-person or telephonic attendance atmeetings of the Board of Directors or committees of the Board ofDirectors.  Members of committees willreceive $1,000 for each meeting, and the Chairs of the Audit Committee,Compensation Committee and Conflicts Committee will receive an additional$4,000, $2,000 and $2,000 per year, respectively.

 

Previously,each independent director received an annual retainer of $12,000 and options topurchase 1,000 shares of common stock per year. In addition, each independentdirector received compensation of $1,500 for in-person attendance and $700 fortelephonic attendance at meetings of the Board of Directors or committees ofthe Board of Directors. The members of the Audit and Compensation committeesreceived compensation of $1,000 for each committee meeting.  Additionally, members of the Audit andCompensation committees received an annual retainer of $3,000.

 

Eachindependent director will continue to be reimbursed for out-of-pocket expensesin connection with attending meetings of the Board of Directors or committees.Each director will also continue to be fully indemnified by

 

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us for actionsassociated with being a director to the extent permitted under Delawarelaw.  As previously disclosed, officersor employees of the Company who also serve as directors will not receiveadditional compensation.

 

**Compensation Committee Interlocks and Insider Participation**

 

Mr. Wolf(chairman), Mr. Fox, Mr. Kellstrom, Mr. Wallace and Ms. Mounseywere members of the Company’s Compensation Committee during the year ended December 31,2004.  There are no CompensationCommittee interlocks, and none of the Compensation Committee members during thelast year have been, at any time, an officer or employee of the registrant orany of its subsidiaries.

 

# **Board Compensation CommitteeReport On Executive Compensation**

# ** **

TheCompensation Committee of the Board of Directors is composed of fivenon-employee directors, including Mr. Wolf (chairman), Mr. Fox, Mr. Kellstrom,Mr. Wallace and Ms. Mounsey. The Committee is responsible for developing and approving our executivecompensation policies.  In addition, theCompensation Committee determines, on an annual basis, the compensation to bepaid to the Chief Executive Officer and to each of the other executiveofficers.  The overall objectives of ourexecutive compensation program are to provide compensation that will attractand retain superior talent and reward performance.

 

***Compensation Philosophy***

 

The goals of thecompensation program are to align compensation with business objectives andperformance and to enable us to attract, retain and reward executive officerswhose contributions are critical to long-term success.  Periodically, the compensation levels ofexecutive officers are compared to survey information to ensure ourcompensation levels are competitive. Actual compensation levels may be greater than competitive levels insurveyed companies based upon annual and long-term Company performance, as wellas individual performance.  TheCompensation Committee uses its discretion to set executive compensation atlevels warranted in its judgment.  Weapply a consistent philosophy to compensation for all employees, includingsenior management.  This philosophy isbased on the premise that our achievements result from the coordinated effortsof all individuals working toward common objectives.  We strive to achieve those objectives throughteamwork that is focused on meeting the expectations of customers andstockholders.  Executive officers areawarded based upon corporate performance and individual performance.  Corporate performance is evaluated byreviewing the extent to which strategic and business plan goals are met,including such factors as profitability, performance relative to competitorsand consummation of strategic projects or acquisitions.  Individual performance is evaluated by reviewingorganizational and management development progress against set objectives andthe degree to which teamwork and our Company values are fostered.

 

***Compensation Vehicles***

 

We have a successfulhistory of using a simple total compensation program that consists of cash- andequity-based compensation.  Thecomponents of our compensation program for our executive officers include basesalary, performance based cash bonuses, and long-term incentive compensation inthe form of stock options, restricted stock awards and restricted unit grantsof MarkWest Energy Partners, L.P.

 

***Base Salary***

 

The Chief ExecutiveOfficer makes annual recommendations regarding the base salaries of theexecutive officers (other than the Chief Executive Officer) to the CompensationCommittee.  Base salaries for theexecutive officers are intended to be based on the average of fixedcompensation levels for comparable management personnel employed by peercompanies of a similar size.  In makingbase salary recommendations, the Chief Executive Officer also takes intoaccount individual experience, performance and other specific issues.  The Compensation Committee considers theChief Executive Officer’s recommendations with respect to base salaries forother executive officers.

 

***Performance-Based Cash Bonuses***

 

Under our incentivecompensation program bonuses are awarded only if we achieve or exceed certaincorporate performance objectives.  Theincentive awards for each officer and executive for the 2004 performance

 

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year was derived fromthree measurement criteria: 1) MarkWest Hydrocarbon operating cash flow(weighted 40% of the total bonus award); 2) MarkWest Energy distributable cashflow (weighted 40% of the total bonus award); and 3) department/individualgoals and performance (weighted 20% of the total bonus award).  Thetargets are determined by the Board of Directors early in the year or duringthe last quarter of the prior year.  Thesize of the fund available for such bonuses increases in relation to the extentto which such executive’s salary ranging from approximately 20% to 65% and allother non-union employees depending on targets as established at the beginningof the year.  If the base performancecriteria are met, each executive officer is entitled to a base bonus amountequal to that percentage of the executive officer’s base salary.  A similar approach is used for all othernon-union personnel at differing percentage levels.

 

For the year 2004, we metour target goals set forth in the Incentive Compensation Plan.  In addition, we achieved several objectives,including strengthening the balance sheet and completing acquisitions forMarkWest Energy Partners, L.P., which are expected to increase long-term value.  With Board recommendation and approval, abonus was awarded to all non-union employees in February 2005.  Executive officers received bonuses rangingfrom 22% to 60% of their base salary.

 

***Stock Option Program***

 

Stock options andrestricted stock awards are granted to executive officers under the StockIncentive Plan.  The objectives of theStock Incentive Plan are to align executive and stockholder long-term interestsby creating a strong and direct link between executive pay and stockholderreturn, and to enable executives to develop and maintain a significantlong-term ownership position in our common stock.

 

The Stock Incentive Planauthorizes the Board of Directors or a committee of non-employee directors togrant stock options, restricted stock and other types of awards to executiveofficers.  To date, the only type ofawards granted to executive officers under the Stock Incentive Plan have beenstock options and restricted stock.  Allstock options currently outstanding were granted at an option price at leastequal to the fair market value of our common stock on the date of grant,generally have ten-year terms and generally become exercisable in installmentsover a four-year period.  All shares ofrestricted stock outstanding were granted with a ten-year term and generallyvest in installments over a three-year period.

 

Stock options may begranted upon commencement of employment based on the recommendation of theChief Executive Officer.  In determiningwhether to recommend additional option grants to an executive officer, the ChiefExecutive Officer typically considers the individual’s performance and anyplanned change in functional responsibility. Neither our profitability nor the market value of our stock areconsidered in setting the amount of executive officer stock option grants.  The stock option position of executiveofficers is reviewed on an annual basis. The determination of whether or not additional options will be grantedis based on a number of factors, including our performance, individualperformance and levels of options granted at the competitive median for ourpeer group.

 

***MarkWest Energy Restricted Units***

 

Phantom units in MarkWestEnergy were granted to executives and directors in 2004, amounting to 19,750units.  A restricted unit in MarkWestEnergy Partners, L.P., is a “phantom” unit that entitles the grantee to receivea common unit upon the vesting of the phantom unit, or in the discretion of theCompensation Committee, cash equivalent to the value of a common unit.  These restricted units are entitled toreceive distribution equivalents, which represent cash equal to the amount ofcash distributions made on common units during the vesting period, from thedate of grant.  The restricted units,unless certain targets are achieved, vest over a period of three years,starting with grants in September 2004, with 33% of the grant vesting atthe end of each year.  Prior to September 2004,phantom units were granted with a vesting period of four years, with 25% of thegrant vesting at the end of each of the second and third years and 50% vestingat the end of the fourth year.  Ifcertain targets are achieved, then the vesting of the phantom units acceleratesand the units convert to common units. The acceleration is based on increases in annual cash distribution ofthe units.  In the future, theCompensation Committee may determine to make additional grants under the planto employees and directors containing such terms as the Compensation Committeeshall determine under the plan.  TheCompensation Committee will determine the period over which restricted unitsgranted to employees and directors will vest. The committee may base its determination upon the

 

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achievement of specifiedfinancial objectives.  In addition, therestricted units will vest upon a change in control of MarkWest Hydrocarbon, Inc.,or MarkWest Energy Partners, L.P.

 

We intend the issuance of the common units uponvesting of the restricted units under the plan to serve as a means of incentivecompensation for performance and not primarily as an opportunity to participatein the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for thecommon units they receive, and we will receive no remuneration for the units.

 

***Savings Plan Benefits***

 

We make a matching contribution under our 401(k)Savings and Profit Sharing Plan.  We mayalso make a discretionary profit sharing payment annually to executives and allother employees under this plan based upon our financial performance comparedto corporate goals for that year.  Inaddition, we provide medical and other miscellaneous benefits to executiveofficers that are generally available to all employees.

 

***Chief Executive Officer Compensation***

 

*BaseSalary. *The basesalary of the Chief Executive Officer for 2004 was $280,000 and was establishedby the Compensation Committee.  Factorstaken into consideration in the determination of the Chief Executive Officer’sbase salary include the base salaries for chief executive officers of our peer group,historical compensation practices and the general experience of theCompensation Committee members in dealing with compensation matters at otherenergy companies.  In addition, insetting this amount, the Committee took into account the scope of Mr. Semple’sresponsibility and the Board’s confidence in Mr. Semple’s skills andability to implement the Company’s strategy and business model as evidenced byhis performance during 2004.

 

*Bonusesand Stock Option Awards. *Mr. Semplereceived a bonus of $108,000 for 2004 under the Incentive CompensationPlan.  Such bonus was paid in February 2005in accordance with the Plan provisions.  Mr. Semplereceived 22,000 options to purchase shares of our common stock in November 2003and 2,179 shares of restricted stock under the Stock Incentive Plan in January 2005.  Mr. Semple has also received 7,500phantom units in November 2003 and 2,500 phantom units in September 2004under the MarkWest Energy Partners, L.P. Long Term Incentive Plan.

 

*Deductibilityof Executive Compensation. *Section 162(m)of the Internal Revenue Code generally disallows a tax deduction forcompensation in excess of $1.0 million paid to the Company’s Chief ExecutiveOfficer and certain other highly compensated executive officers.  Qualifying “performance-based” compensationwill not be subject to the deduction limit if certain requirements aremet.  We anticipate that incentive-basedcompensation paid in excess of $1.0 million will be deductible under Section 162(m).  The Compensation Committee believes, however,that there may be circumstances in which our interests are best served byproviding compensation that is not fully deductible under Section 162(m)and reserves the ability to exercise discretion to authorize such compensation.

 
|   | Compensation  Committee            |
|--------|------------------------------------|
|   | Mr. Donald  D. Wolf, Chairman |
|   | Mr. John  M. Fox              |
|   | Mr. William  A. Kellstrom     |
|   | Mr. William  F. Wallace       |
|   | Ms. Anne  E. Mounsey          |

 

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**ITEM12.  SECURITY OWNERSHIP OF CERTAINBENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS**

 

Thefollowing table sets forth certain information as of September 9, 2005,regarding the beneficial ownership of our common stock held by beneficialowners of 5% or more of common stock, by each director, by each Named ExecutiveOfficer and by all of the directors and officers of the Company as a group.

 
| **Stockholder(1)**                                                 | ** ** | **Number  of  Shares** | ** ** | **Acquirable  Within  60 Days of  August 15(2)** | ** ** | **Total  Shares  Beneficially  Owned(3)** | ** ** | **Percent  of  Total  Shares(4)** | ** ** |
|--------------------------------------------------------------------|------------|------------------------|------------|-------------------------------------------------------|------------|-------------------------------------------|------------|-----------------------------------|------------|
| John M. Fox(5)                                                     |       | 4,632,128              |       | 4,628                                                 |       | 4,636,756                                 |       | 42.9                              | %          |
| Wellington Management Company, LLP(6)                              |       | 858,250                |       | —                                                |       | 858,250                                   |       | 8.0                               | %          |
| 75 State Street  Boston, Massachusetts 02109                       |       |                   |       |                                                  |       |                                      |       |                              |       |
| Kayne Anderson Capital Advisors, L.P. (7)                          |       | 714,850                |       | —                                                |       | 714,850                                   |       | 6.6                               | %          |
| 1800 Avenue of the Stars,  Second Floor  Los Angeles, CA 90067     |       |                   |       |                                                  |       |                                      |       |                              |       |
| Richard A. Kayne(7)                                                |       | 714,850                |       | —                                                |       | 714,850                                   |       | 6.6                               | %          |
| 1800 Avenue of the  Stars, Second Floor  Los Angeles, CA 90067     |       |                   |       |                                                  |       |                                      |       |                              |       |
| James G. Ivey                                                      |       | —                 |       | 2,750                                                 |       | 2,750                                     |       |                              | *          |
| Frank M. Semple                                                    |       | 5,960                  |       | 11,000                                                |       | 16,960                                    |       |                              | *          |
| Donald C. Heppermann                                               |       | 7,500                  |       | 10,175                                                |       | 17,675                                    |       |                              | *          |
| Donald D. Wolf                                                     |       | 23,310                 |       | 1,100                                                 |       | 24,410                                    |       |                              | *          |
| William F. Wallace                                                 |       | 3,000                  |       | 367                                                   |       | 3,367                                     |       |                              | *          |
| William A. Kellstrom                                               |       | 10,285                 |       | 5,720                                                 |       | 16,005                                    |       |                              | *          |
| Karen L. Rogers                                                    |       | 5,445                  |       | 3,300                                                 |       | 8,745                                     |       |                              | *          |
| Randy S. Nickerson                                                 |       | 6,735                  |       | 3,859                                                 |       | 10,594                                    |       |                              | *          |
| Anne E. Mounsey                                                    |       | 14,482                 |       | 367                                                   |       | 14,849                                    |       |                              | *          |
| John C. Mollenkopf                                                 |       | 609                    |       | 7,119                                                 |       | 7,728                                     |       |                              | *          |
| David L. Young                                                     |       | —                 |       | 687                                                   |       | 687                                       |       |                              | *          |
| All directors  and executive officers as  a group (12 individuals) |       | 4,709,454              |       | 51,072                                                |       | 4,760,526                                 |       | 43.9                              | %          |

 

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*                 Indicates lessthan 1.0%.

 

(1)          Unless otherwise noted,the address for the stockholder listed is c/o MarkWest Hydrocarbon, Inc.,155 Inverness Drive West, Suite 200, Englewood, Colorado 80112-5000.

 

(2)          This column reflects thenumber of shares that could be purchased by the exercise of options exercisableon September 9, 2005, or within sixty days thereafter under our stockoption plans.

 

(3)          For executive officers,the numbers include interests in shares held in employee benefit plans.  Unless otherwise indicated, the directors andNamed Executive Officers have sole voting and dispositive power over the shareslisted above, other than shared rights created under joint tenancy or maritalproperty laws as between the directors or named executive officers and theirrespective spouses.

 

(4)          All percentages havebeen determined at September 9, 2005, in accordance with Rule 13d-3under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forpurposes of this table, a person or group of persons is deemed to have “beneficialownership” of any shares of common stock that such person or group has theright to acquire within sixty days after September 9, 2005. For purposesof computing the percentage of outstanding shares of common stock held by eachperson or group of persons named above, any security which such person or grouphas the right to acquire within sixty days after September 9, 2005, isdeemed to be outstanding for the purpose of computing the percentage ownershipof such person or group. At September 9,

 

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2005, a total of10,794,729 shares were outstanding. Options to acquire a total of 83,270 sharesof common stock were exercisable within sixty days.

 

(5)          Includes an aggregate of(i) 4,097,694 shares owned directly by MWHC Holding, Inc., an entitycontrolled by Mr. Fox, of which Mr. Fox is also considered abeneficial owner (Mr. Fox has an indirect pecuniary interest in the MWHCshares); (ii) 171,901 shares held in the aggregate in the Brent A.Crabtree Trust, Brian T. Crabtree Trust and the Carrie L. Crabtree Trust (the “CrabtreeTrusts”), for each of which Mr. Fox is the Trustee; and (iii) 106,857shares held by the MaggieGeorge Foundation, for which certain family members ofMr. Fox are directors.  Mr. Foxdisclaims beneficial ownership of the shares held in the Crabtree Trusts and bythe MaggieGeorge Foundation within the meaning of Rule 13d-3 under theExchange Act.

 

(6)          Information is basedsolely on a Schedule 13G/A filed with the Securities and ExchangeCommission by Wellington Management Company, LLP (“Wellington”), on February 14,2005, with respect to shares held as of December 31, 2004. The Schedule 13Gindicates that Wellington has shared voting power with respect to 654,250shares and shared dispositive power with respect to 858,250.

 

(7)          Information is basedsolely on a Schedule 13G filed with the Securities and Exchange Commissionby Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne, on February 10,2005, with respect to shares held as of December 31, 2004. The Schedule 13Gindicates that Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne haveshared voting power and dispositive power with respect to 714,850 shares.  The reported shares are owned by investmentaccounts managed, with discretion to purchase or sell securities, by KayneAnderson Capital Advisors, L.P., as a registered investment advisor.  Kayne Anderson Capital Advisors, L.P. is thegeneral partner of the limited partnerships and investment adviser to the otheraccounts.  Richard A. Kayne is thecontrolling shareholder of the corporate owner of Kayne Anderson InvestmentManagement, Inc., the general partner of Kayne Anderson Capital Advisors,L.P.  Mr. Kayne is also a limitedpartner of each of the limited partnerships and a shareholder of the registeredinvestment company.  Kayne AndersonCapital Advisors, L.P. disclaims beneficial ownership of the shares reported,except those shares attributable to it by virtue of its general partnerinterests in the limited partnerships.  Mr. Kaynedisclaims beneficial ownership of the shares reported, except those shares heldby him or attributable to him by virtue of his limited partnership interests inthe limited partnerships, his indirect interest in the interest of KayneAnderson Capital Advisors, L.P. in the limited partnership, and his ownershipof common stock of the registered investment company.

 

***MarkWest Energy GP, L.L.C.***

 

Thefollowing table sets forth the beneficial ownership of the Partnership’sgeneral partner as of September 9, 2005, held by the directors, each namedexecutive officer and by all directors and officers of as a group.

 
| **Name of Beneficial Owner**                                 | ** ** | **Percentage of  Limited Liability Company  Interests Owned** | ** ** |
|--------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| John M. Fox (1)                                         |       | 91.3                                                          |       |
| Frank M. Semple                                              |       | 2.0                                                           |       |
| James G. Ivey                                                |       | 0.5                                                           |       |
| Randy S. Nickerson                                           |       | 1.6                                                           |       |
| John C. Mollenkopf                                           |       | 1.6                                                           |       |
| David L. Young                                               |       | 0.0                                                           |       |
| Donald D. Wolf                                               |       | 0.0                                                           |       |
| Donald C. Heppermann                                         |       | 1.0                                                           |       |
| William A. Kellstrom                                         |       | 0.0                                                           |       |
| William F. Wallace                                           |       | 0.0                                                           |       |
| Karen L. Rogers                                              |       | 0.0                                                           |       |
| Anne E. Mounsey                                              |       | 0.0                                                           |       |
| All directors and executive officers as a group (8  persons) |       | 98.0                                                          |       |
| Other (2)                                                    |       | 2.0                                                           |       |

 

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(1)          Includes a 1.6%ownership interest held directly by Mr. Fox and an 89.7% ownershipinterest held by MarkWest Hydrocarbon. As of December 31, 2004, Mr. Foxbeneficially owned approximately 43% of the voting securities of MarkWestHydrocarbon. Mr. Fox currently serves as MarkWest Hydrocarbon’s Chairmanof the Board. As a result, Mr. Fox may be deemed to be the beneficialowner of the ownership interests owned by MarkWest Hydrocarbon.

(2)          Held by two officers andone former executive of MarkWest Hydrocarbon.

 

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***MarkWest Energy Partners, L.P.***

 

The followingtable sets forth the beneficial ownership of the Partnership’s common andsubordinated units as of September 9, 2005, held by Company directors, byeach named executive officer listed in the summary compensation table includedin this Form 10-K and by all directors and officers as a group.

 
| **Name of Beneficial Owner**                                  | ** ** | **Common Units  Beneficially  Owned(1)** | ** ** | **Percentage of  Common  Units  Beneficially  Owned** | ** ** | **Subordinated  Units  Beneficially  Owned** | ** ** | **Percentage of  Subordinated  Units  Beneficially  Owned** | ** ** | **Percentage of  Total Units  Beneficially  Owned** | ** ** |
|---------------------------------------------------------------|------------|------------------------------------------|------------|-------------------------------------------------------|------------|----------------------------------------------|------------|-------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| John M. Fox(2)                                           |       | 32,000                                   |       |                                                  | *          | 2,489,122                                    |       | 83.0                                                        | %          | 23.7                                                | %          |
| Frank M. Semple                                               |       | 5,750                                    |       |                                                  | *          | 5,000                                        |       |                                                        | *          |                                                | *          |
| James G. Ivey                                                 |       | 2,500                                    |       |                                                  | *          | —                                       |       | —                                                      |       |                                                | *          |
| Randy S. Nickerson                                            |       | 6,875                                    |       |                                                  | *          | 4,626                                        |       |                                                        | *          |                                                | *          |
| John C. Mollenkopf                                            |       | 2,650                                    |       |                                                  | *          | 4,626                                        |       |                                                        | *          |                                                | *          |
| David L. Young                                                |       | 1,000                                    |       |                                                  | *          | —                                       |       | —                                                      |       |                                                | *          |
| Donald D. Wolf                                                |       | 5,250                                    |       |                                                  | *          | —                                       |       | —                                                      |       |                                                | *          |
| Donald C. Heppermann                                          |       | 7,500                                    |       |                                                  | *          | 4,000                                        |       |                                                        | *          |                                                | *          |
| William A. Kellstrom                                          |       | 3,750                                    |       |                                                  | *          | —                                       |       | —                                                      |       |                                                | *          |
| William L. Wallace                                            |       | —                                   |       |                                                  | *          | —                                       |       | —                                                      |       |                                                | *          |
| Karen L. Rogers                                               |       | 1,750                                    |       |                                                  | *          | —                                       |       | —                                                      |       |                                                | *          |
| Anne E. Mounsey                                               |       | —                                   |       |                                                  | *          | —                                       |       | —                                                      |       |                                                | *          |
| All directors  and executive officers as a group (11 persons) |       | 69,025                                   |       |                                                  | *          | 2,507,374                                    |       | 83.6                                                        | %          | 24.2                                                | %          |
| Other (2)                                                     |       | 1,500                                    |       |                                                  | *          | 3,000                                        |       |                                                        | *          | *                                                   |       |

 

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*                 Less than 1%

(1)          Beneficial ownership forthe purposes of the foregoing table is defined by Rule 13 d-3 under theSecurities Exchange Act of 1934. Under that rule, a person is generallyconsidered to be the beneficial owner of a security if he has or shares thepower to vote or direct the voting thereof (“Voting Power”) or to dispose ordirect the disposition thereof (“Investment Power”) or has the right to acquireeither of those powers within sixty (60) days.

(2)          Includes 4,626subordinated units owned directly by Mr. Fox, 2,469,496 subordinated unitsowned by MarkWest Hydrocarbon and its subsidiaries, and approximately 15,000subordinated units owned by Tortoise MWEP, L.P. in which Mr. Fox owns anequity interest. As of December 31, 2004, Mr. Fox beneficially ownedapproximately 43% of the voting securities of MarkWest Hydrocarbon. Mr. Foxcurrently serves as MarkWest Hydrocarbon’s Chairman of the Board. As a result, Mr. Foxmay be deemed to be the beneficial owner of the subordinated units owned byMarkWest Hydrocarbon.

(3)          Held by two key officersof MarkWest Hydrocarbon and our general partner for common and subordinatedunits, respectively.

 

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**Securities Authorized for Issuance under Equity Compensation Plans**

 

The followingtable provides information about the shares of our common stock that may beissued upon the exercise of options, warrants and rights under all of theCompany’s existing equity compensation plans, including the Stock IncentivePlan and Non-Employee Director Plan as of December 31, 2004.  We do not have equity plans that have notreceived stockholder approval.

 

**EquityCompensation Plan Information**

 
| ** **                                                  | ** ** | **Number of securities to  be issued upon exercise  of outstanding options,  warrants and rights** | ** ** | **Weighted-average  exercise price of  outstanding options,  warrants and rights** | ** ** | **Number of securities  remaining available for  future issuance under  equity compensation  plans (excluding  securities reflected in  column (a))** | ** ** |
|-------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------|------------|
| **Plan category**                                           | ** ** | **(a)**                                                                                            | ** ** | **(b)**                                                                            | ** ** | **(c)**                                                                                                                                               | ** ** |
| Equity  compensation plans approved by security holders     |       | 171,688                                                                                            |       | $                                                                                  | 8.43       |                                                                                                                                                  | 409,935    |   |
| Equity  compensation plans not approved by security holders |       | —                                                                                             |       | —                                                                             |       | —                                                                                                                                                |       |
|                                                        |       |                                                                                               |       |                                                                               |       |                                                                                                                                                  |       |
| Total                                                       |       | 171,688                                                                                            |       | $                                                                                  | 8.43       |                                                                                                                                                  | 409,935    |   |

 

**ITEM 13.  CERTAIN RELATIONSHIPS AND RELATEDTRANSACTIONS**

 

**Investment with Affiliate**

 

Through ourwholly owned subsidiary, MarkWest Resources, Inc. (“Resources”), we heldvaried undivided interests in several exploration and production assets inwhich MAK-J Energy Partners Ltd. (“MAK-J”) also owns or owned an undividedinterest, varying from 25% to 51%.  Thegeneral partner of MAK-J is a corporation owned and controlled by our formerPresident and Chief Executive Officer and current Chairman of the Board ofDirectors.  Two former officers, both ofwho left the Company during 2003, were limited partners in MAK-J.  The properties were operated pursuant tojoint operating agreements entered into between Resources and MAK-J.  Resources was the operator under suchagreements.  The joint operatingagreements were governed by a Participation and Operations Agreement, mostrecently amended June 2, 2003.  Thejoint property acquisitions and joint operating agreements were subject to theapproval of the independent members of our Board of Directors.  As the operator, Resources was obligated toprovide certain accounting and well operations services to the parties.  The Participation and Operations Agreementprovided for a monthly fee ($2,000 per month) payable to Resources to offsetthe costs of accounting and well operations on a monthly basis.  As a part of the sale of our San Juan Basinoil and gas properties to a third party on June 30, 2003, theParticipation and Operations Agreement was assigned to the purchasing thirdparty.

 

From time totime, MarkWest Hydrocarbon entered into hedges with counterparties on behalf ofMAK-J.  MarkWest Hydrocarbon billed orremitted to MAK-J, as circumstances dictated, its portion of transaction costsand settlements on a monthly basis.  Asof July 2003, all such hedges had been settled.

 

Through ourwholly owned subsidiary, Matrex, LLC, we hold interests in certain explorationand production assets in which MAK-J also owns interests.  Both parties are participants to jointoperating agreements with third parties operators.

 

We havereceivables due from MAK-J, representing its share of operating and capitalcosts generated in the normal course of business, of less than $0.1 million asof December 31, 2004 and 2003, respectively.  We also have payable to MAK-J, representingits share of revenues generated in the normal course of business, of less than$0.1 million as of December 31, 2004 and approximately $0.1 million as of December 31,2003.

 

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Mr. Foxhas agreed that as long as he is an officer or director of MarkWest Hydrocarbonand for two years thereafter, he will not, directly or indirectly, participatein any future oil and gas exploration or production activities with us exceptand to the extent that our independent and unaffiliated directors deem itadvisable and in our best interest to include one or more additionalparticipants, which participants may include entities controlled by Mr. Fox.

 

**Relationship of Directors with MarkWest Hydrocarbon**

 

Donald D. Wolf,a member of the Board of Directors, was the Chairman and Chief ExecutiveOfficer of Westport Resources Corporation and William F. Wallace, also a memberof the Board of Directors, was a director of Westport Resources Corporationuntil Westport’s merger with Kerr McKee Corporation in 2004.  Mr. Wallace is currently a director ofthe Kerr McKee Corporation.  WestportResources Corporation was a party to certain 1997 contracts with indirectsubsidiaries of MarkWest Hydrocarbon for transportation, treating andprocessing services in western Michigan. No services were performed in the last year pursuant to thesecontracts.  The terms of these contractswere negotiated on an arm’s length basis prior to Mr. Wolf’s 1999 electionand Mr. Wallace’s 2004 election to the Board of Directors.

 

**Related Transactions**

 

In February 2004,MarkWest Hydrocarbon entered into a Separation and Release Agreement withArthur J. Denney, Senior Vice President, pursuant to which the Company agreedto pay Mr. Denney his base salary through February 28, 2006, orapproximately $0.4 million.

 

In February 2004,MarkWest Hydrocarbon entered into a Separation and Release Agreement withDonald C. Hepperman, Chief Financial Officer, pursuant to which MarkWestHydrocarbon agreed to pay Mr. Heppermann his base salary through August 31,2004.

 

In March 2004,MarkWest Hydrocarbon entered into a Consulting Agreement with Donald C.Heppermann to advise MarkWest Hydrocarbon’s Board of Directors, chief executiveofficer, treasurer and controller on matters relating to banking, financing,mergers and acquisitions and general corporate strategy.  Pursuant to the agreement, MarkWest Hydrocarbonagreed to pay Mr. Heppermann $9,000 a month for his consulting servicesfor up to a period of two years (or $0.2 million), unless given notice byMarkWest Hydrocarbon.

 

In March 2004,MarkWest Hydrocarbon entered into a Separation and Release Agreement with JohnM. Fox, Chief Executive Officer, pursuant to which MarkWest Hydrocarbon agreedto pay Mr. Fox his base salary through December 31, 2004 orapproximately $0.4 million.

 

In April 2004,the Company entered into an agreement with a third party to buy Mr. Semple’shouse as a part of his relocation to Denver, Colorado.  Under the agreement, MarkWest Hydrocarbonagreed to pay the value of Mr. Semple’s equity in the house and associatedoperating costs of $0.3 million to the third party until the house wassubsequently sold to a buyer.  Upon thesale, the third party agreed to refund the equity paid by MarkWest Hydrocarbonto the extent that the proceeds covered the established value minus certaincosts incurred to sell the home.  In2005, the house was sold and the Company paid total costs of approximately $0.1million.

 

**Participation Plan**

 

From time to time,MarkWest Hydrocarbon sells to certain of its executive officers and directors (i) acertain amount of the subordinated units the Company obtained during theformation of MarkWest Energy in May 2002 and (ii) a portion of itsownership interest in the general partner, which was also obtained by theCompany during the formation of the Partnership.  These transactions are accounted for ascompensatory arrangements, consistent with the guidance in APB No. 25, *Accounting for Stock Issued to Employees*andEITF No 95-16, *Accounting for StockCompensation Arrangements with Employer Loan Features under APB Opinion No. 25,*which requires the Company to record compensation expense based onthe market value of the subordinated Partnership units and the formula value ofthe general partner interests held by the employees and directors, at the endof each reporting period. The sales are governed by a purchase and salesagreement that outlines the terms and conditions.

 

140

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Immediately after MarkWest Energy’s initial public offeringon May 24, 2002, MarkWest Hydrocarbon sold an 8.6% interest in the generalpartner of the Partnership and 24,864 of its Partnership subordinated units, tocertain officers of MarkWest Hydrocarbon for $0.2 million and $0.4 million,respectively.  The officers andexecutives paid approximately 30% of the purchase price in cash and financed theremainder with loans from MarkWest Hydrocarbon. The loans are evidenced by non-recourse promissory notes requiring theprincipal balance to be repaid no later than June 30, 2009 and bearinginterest at the rate of 7% per annum on the unpaid balance.   MarkWest Hydrocarbon has sold additionalinterests in the general partner to employees and directors of 3.9% for $0.2million and Partnership subordinated units of 12,500 for $0.3 million.  In 2004, the Company sold interestsaggregating 0.7% in the general partner of the Partnership to employees anddirectors for $0.2 million and 1,500 Partnership subordinated units for $0.1million.  Outstanding notes receivablefrom officers pertaining to the loans made in May 2002 were approximately$0.2 million as of December 31, 2004 and 2003.  In the second quarter of 2005, one formerdirector/executive re-paid his outstanding loan for less than $0.1 million.Outstanding notes receivable of approximately $0.1 million were payable by Mr. Mollenkopfand Mr. Nickerson at both December 31, 2004 and 2003.  In accordance with the Sarbanes-Oxley Act of2002, the Company no longer grants loans to employees.

 

## **Future Transactions**

## ** **

The terms of any futuretransactions between us and our directors, officers, principal stockholders orother affiliates, or the decision to participate or not participate intransactions offered by our directors, officers, principal stockholders orother affiliates will be approved by a majority of our independent andunaffiliated directors. Our Board of Directors will use such procedures inevaluating their terms as are appropriate considering the fiduciary duties ofthe Board of Directors under Delaware law. In any such review the Board may useoutside experts or consultants including independent legal counsel, secureappraisals or other market comparisons, refer to generally available statisticsor prices or take such other actions as are appropriate under thecircumstances. Although such procedures are intended to ensure thattransactions with affiliates will be at least as favorable to the Company as anarm’s length transaction with an unaffiliated third party, though no assurancecan be given that such procedures will produce such result.

 

**ITEM 14.  PRINCIPAL ACCOUNTANTFEES AND EXPENSES**

 

KPMGLLP served as our principal accountants for the year ended December 31,2004.  PricewaterhouseCoopers LLP servedas our principal accountant for the year ended December 31, 2003.  Fees and expenses to our principalaccountants for the year ended December 31, 2004 and 2003, KPMG LLP andPricewaterhouseCoopers LLP’s accounting fees and services (in thousands) wereas follows:

 
| ** **                          | ** ** | **2004** | ** ** | **2003** | ** ** |
|-------------------------------------|------------|----------|------------|----------|------------|
| Audit fees                          |       | $        | 2,945      |     | $          | 610 |   |
| Audit-related fees(1)               |       | 110      |       | 998      |       |
| Tax fees(2)                         |       | —   |       | 951      |       |
| All other fees(3)                   |       | —   |       | 3        |       |
|                                |       |     |       |     |       |
| Total accounting  fees and services |       | $        | 3,055      |     | $          | 2,562 |   |

 

----

(1)          Audit related feesinclude fees for reviews of registration statements and issuances of consents,reviews of private placement offering documents, benefit plan audits, issuanceof letter to underwriters, due diligence pertaining to potential businessacquisitions and a review of risk management policies and procedures.

 

(2)          Tax fees include feesfor tax return preparation and technical tax advice.

 

(3)   All other fees consist of a subscription toan on-line accounting research tool.

 

TheAudit Committee pre-approved the performance of the services describedabove.  See also Item 10, Audit CommitteePre-Approval Policy.

 

141

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**PART IV**

** **

**ITEM15.  EXHIBITS AND FINANCIAL STATEMENTSCHEDULES**

 

(a)          The following documentsare filed as part of this report:

 
| (1)           Financial  Statements:                                                   |   |   |
|------------------------------------------------------------------------------------------------------------------------------------------|--------|--------|
|                                                                                                                                     |   |   |
| Report of  KPMG LLP, Independent Registered Public Accounting Firm                                                                       |   |   |
|                                                                                                                                     |   |   |
| Report of  PricewaterhouseCoopers, LLP, Independent Registered Public Accounting Firm                                                    |   |   |
|                                                                                                                                     |   |   |
| Consolidated  Balance Sheets at December 31, 2004 and 2003                                                                          |   |   |
|                                                                                                                                     |   |   |
| Consolidated  Statements of Operations for each of the three years in the period ended December 31,  2004                           |   |   |
|                                                                                                                                     |   |   |
| Consolidated  Statements of Comprehensive Income (Loss) for each of the three years in the  period ended December 31, 2004          |   |   |
|                                                                                                                                     |   |   |
| Consolidated  Statements of Changes in Stockholders’ Equity for each of the three years in  the period ended December 31, 2004 |   |   |
|                                                                                                                                     |   |   |
| Consolidated  Statements of Cash Flows for each of the three years in the period ended  December 31, 2004                           |   |   |
|                                                                                                                                     |   |   |
| Notes to  Consolidated Financial Statements                                                                                              |   |   |

 

(2)                                  FinancialStatement Schedules:  None required.

 

(3)                                  Exhibits:  See (b) below.

 

(b)         Exhibits required by Item601 of Regulation S-K.

 
| **Exhibit  Number** | ** ** | **Exhibit Description**                                                                                                                                                                                                                                                                                |
|---------------------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                |       |                                                                                                                                                                                                                                                                                                        |
| 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                                                                                                                                  |

 

142

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|     |   | 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.                                                                                                                                                                                                                                                                                                                 |
|     |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 2.7(15)  |   | Asset Purchase and Sale  Agreement and addendum, thereto, dated as of July 1, 2004 by and between  American Central Eastern Texas Gas Company Limited Partnership, ACGC  Gathering Company, L.L.C. and MarkWest Energy East Texas Gas Company’s L.P.                                                                                                                                                                                                                                                                                                |
|     |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 3.1(1)   |   | Certificate of  Incorporation of MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
|     |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 3.2(1)   |   | Bylaws of MarkWest  Hydrocarbon, Inc.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
|     |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 4.1(7)   |   | Subordinated Unit  Purchase Agreement among MarkWest Hydrocarbon, Inc. and Tortoise MWEP,  L.P., dated as of November 20, 2002.                                                                                                                                                                                                                                                                                                                                                                                                                     |
|     |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 4.2(14)  |   | Purchase Agreement  dated as of June 13, 2003, by and among MarkWest Energy Partners, L.P.  and Tortoise Capital Advisors, LLC as attorney-in-fact for the Purchasers.                                                                                                                                                                                                                                                                                                                                                                                   |
|     |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 4.3(14)  |   | Registration Rights  Agreement dated as of June 13, 2003, by and among MarkWest Energy  Partners, L.P. and Tortoise Capital Advisors, LLC as attorney-in-fact for the  Purchasers.                                                                                                                                                                                                                                                                                                                                                                       |
|     |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 4.4(15)  |   | Unit Purchase Agreement dated as of  July 29, 2004 among MarkWest Energy Partners, L.P., and MarkWest Energy  GP, L.L.C. and each of Kayne Anderson Energy Fund II, L.P., and MarkWest  Energy GP, L.L.C. and each of Kayne Anderson Energy Fund II, L.P., Kayne  Anderson Capital Income Partners, L.P., Kayne Anderson MLP Fund, L.P., Kayne  Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR  RV Performance Master Trust, Tortoise Energy Infrastructure Corporation and  Energy Income and Growth Fund as Purchasers. |
|     |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 4.5(15)  |   | Registration Rights Agreement dated  as of July 29, 2004 among MarkWest Energy Partners, L.P., and each of  Kayne Anderson Energy Fund II, L.P., Kayne Anderson Capital Income Fund,  LTD., Kayne Anderson Income Partners, L.P., HFR RV Performance Master Trust,  Tortoise Energy Infrastructure Corporation and Energy Income and Growth Fund.                                                                                                                                                                                                        |
|     |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 4.6(16)  |   | Underwriting Agreement dated as of  September 15, 2004 by and among the Partnership, the underwriters named  therein and the other parties thereto related to the Common Units Offering.                                                                                                                                                                                                                                                                                                                                                                 |
|     |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 4.7(16)  |   | Purchase Agreement dated  October 19, 2004, among MarkWest Energy Partners, L.P., MarkWest Energy  Finance Corporation, the Guarantors named therein and the Initial Purchasers  named therein.                                                                                                                                                                                                                                                                                                                                                          |
|     |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 4.8(16)  |   | Registration Rights Agreement dated  October 25, 2004, among MarkWest Energy Partners, L.P., MarkWest Energy  Finance Corporation, the Guarantors named therein and the Initial Purchasers  named therein.                                                                                                                                                                                                                                                                                                                                               |
|     |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 4.9(16)  |   | Indenture dated as of  October 25, 2004, among MarkWest Energy Partners, L.P., MarkWest Energy  Finance Corporation, the Guarantors named therein and Wells Fargo Bank,  National Association, as Trustee.                                                                                                                                                                                                                                                                                                                                               |
|     |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 4.10(16) |   | Form of 6.875% Series A  Senior Notes due 2014 with attached notation of Guarantees (incorporated by  Reference to Exhibits A and D of Exhibit 4.9 hereto).                                                                                                                                                                                                                                                                                                                                                                                    |

 

143

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| 10.1(2) D  |   | 1996 Incentive  Compensation Plan.                                                                                                                                                                                                                                                                                                                                     |
|-----------------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|            |   |                                                                                                                                                                                                                                                                                                                                                                   |
| 10.2(1) D  |   | 1996 Stock Incentive  Plan.                                                                                                                                                                                                                                                                                                                                            |
|            |   |                                                                                                                                                                                                                                                                                                                                                                   |
| 10.3(1) D  |   | 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(9)        |   | Purchase and Sale  Agreement, dated as of June 5, 2003, by and among MarkWest  Hydrocarbon, Inc., MarkWest Resources, Inc., and XTO Energy Inc.                                                                                                                                                                                                         |
|            |   |                                                                                                                                                                                                                                                                                                                                                                   |
| 10.18(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.                                                                                                                                                                              |
|            |   |                                                                                                                                                                                                                                                                                                                                                                   |
| 10.19(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,                                                                                                                                                                                                     |

 

144

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|            |   | 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.                                                                                                                                                                                                                                                                                                                                                                                                                                           |
|-----------------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.20(14) D     |   | Executive Employment  Agreement effective November 1, 2003 between MarkWest  Hydrocarbon, Inc. and Frank Semple.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.21(15)       |   | Second Amended and  Restated Credit Agreement dated as of July 30, 2004 among MarkWest  Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners,  L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis  Capital Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and  Societe Generale, as Documentation Agent to the $315,000,000 Senior Credit  Facility.                                                                                                                                                                                                                            |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.22(15)       |   | First Amendment to the Second Amended  and Restated Credit Agreement dated as of August 20, 2004, among  MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy  Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent,  Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation  Agent and Societe Generale, as Documentation Agent.                                                                                                                                                                                                                                              |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.23(17)       |   | Third Amended and Restated Credit  Agreement dated as of October 25, 2004 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, N.A., as Syndication  Agent, Fortis Capital Corp., as Documentation Agent, U.S. Bank National  Association, as Documentation Agent, Societe Generale, as Documentation  Agent, and Wachovia Bank, National Association, as Documentation Agent, RBC  Capital Markets and J.P. Morgan Securities Inc., as Lead Arrangers and Joint  Bookrunners, to the $200,000,000 Senior Credit Facility. |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.24(5) D |   | MarkWest Energy Partners, L.P.  Long-Term Incentive Plan.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.24(5) D |   | First Amendment to MarkWest Energy  Partners, L.P. Long-Term Incentive Plan.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.25(18)       |   | Credit Agreement among  MarkWest Hydrocarbon, Inc. as the Borrower, Royal Bank of Canada, as  Administrative Agent and The Lenders Party Hereto to the $25,000,000 Senior  Credit Facility.                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.26+          |   | Purchase and Sale of  Natural Gas Agreement dated as of September 24, 2004, between MarkWest  Hydrocarbon, Inc. and Equitable Production Company.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.27+          |   | A Firm Natural Gas  Processing Agreement dated as of September 24, 2004, between MarkWest  Hydrocarbon, Inc. and Equitable Production Company.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.28+          |   | A Netting, Financial  and Security Agreement dated as of September 24, 2004, between MarkWest  Hydrocarbon, Inc. and Equitable Production Company.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 23.2 *          |   | Consent of KPMG 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                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |

 

145

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|   |   | Exchange Act.                                                                                                                                                       |
|--------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                |
| 31.3 * |   | Chief Financial Officer  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  Chief Financial Officer 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 Energy Partners, L.P.’s Current Report on  Form 8-K, filed with the Commission on June 29, 2003.                                                                                                                                  |
| (10) |   | Incorporated  by reference to MarkWest Hydrocarbon, Inc.’s Current Report on  Form 8-K, filed with the Commission on July 15, 2003.                                                                                                                                 |
| (11) |   | Incorporated  by reference to MarkWest Energy Partners, L.P.’s Current Report on  Form 8-K, filed with the Commission on September 17, 2003.                                                                                                                             |
| (12) |   | Incorporated  by reference to MarkWest Energy Partners, L.P.’s Current Report on  Form 8-K, filed with the Commission on December 16, 2003.                                                                                                                              |
| (13) |   | Incorporated  by reference to MarkWest Energy Partners, L.P.’s Current Report on  Form 8-K, filed with the Commission on December 31, 2003.                                                                                                                              |
| (14) |   | Incorporated  by reference to MarkWest Hydrocarbon, Inc.’s Annual Report on Form 10-K,  filed with the Commission on March 30, 2004.                                                                                                                                |
| (15) |   | Incorporated  by reference to MarkWest Energy Partners, L.P.’s Current Report on  Form 8-K/A, filed with the Commission on September 13, 2004.                                                                                                                           |
| (16) |   | Incorporated  by reference to MarkWest Energy Partners, L.P.’s Current Report on  Form 8-K, filed with the Commission on October 25, 2004.                                                                                                                               |
| (17) |   | Incorporated  by reference to MarkWest Energy Partners, L.P.’s Current Report on  Form 8-K, filed with the Commission on October 29, 2004.                                                                                                                               |
| (18) |   | Incorporated  by reference to MarkWest Hydrocarbon, Inc.’s Current Report on  Form 8-K, filed with the Commission on October 29, 2004.                                                                                                                              |
| +    |   | 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.                                                                                                                                                                                                                                                                        |
| D    |   | Identifies  each management contract or compensatory plan or arrangement.                                                                                                                                                                                                               |

 

146

----

 

**SIGNATURES**

 

Pursuant to therequirements of section 13 or 15(d) of the Securities Exchange Act of1934, the Registrant has duly caused this Report to be signed on its behalf bythe undersigned, thereunto duly authorized.

 
|                              |   | MarkWest Hydrocarbon, Inc.             |
|-----------------------------------|--------|---------------------------------------------|
|                              |   | (Registrant)                                |
|                              |   |                                        |
| Date:  October 20, 2005 | By:    |  /s/ FRANK M. SEMPLE                   |   |
|                              |   |  Frank M. Semple                       |
|                              |   |  President and Chief Executive Officer |
|                              |   |  (Principal Executive Officer)         |

 

Pursuant to therequirements of the Securities Exchange Act of 1934, this report has beensigned below by the following persons on behalf of the Registrant and in thecapacities and on the dates indicated.

 
| Date:  October 20, 2005 | By:    |  /s/ FRANK M. SEMPLE                   |   |
|-----------------------------------|--------|---------------------------------------------|--------|
|                              |   |  Frank M. Semple                       |
|                              |   |  President and Chief Executive Officer |
|                              |   |  (Principal Executive Officer)         |
|                              |   |                                        |
| Date:  October 20, 2005 | By:    |  /s/ TED S. SMITH                      |   |
|                              |   |  Ted S. Smith                          |
|                              |   |  Chief Accounting Officer              |
|                              |   |  (Principal Accounting Officer)        |
|                              |   |                                        |
| Date:  October 20, 2005 | By:    |  /s/ JAMES G. IVEY                     |   |
|                              |   |  James G. Ivey                         |
|                              |   |  Chief Financial Officer               |
|                              |   |                                        |
| Date:  October 20, 2005 | By:    |  /s/ JOHN M. FOX                       |   |
|                              |   |  John M. Fox                           |
|                              |   |  Chairman of the Board and Director    |
|                              |   |                                        |
| Date:  October 20, 2005 | By:    |  /s/ DONALD C. HEPPERMANN              |   |
|                              |   |  Donald C. Heppermann                  |
|                              |   |  Director                              |
|                              |   |                                        |
| Date:  October 20, 2005 | By:    |  /s/ WILLIAM A. KELLSTROM              |   |
|                              |   |  William A. Kellstrom                  |
|                              |   |  Director                              |
|                              |   |                                        |
| Date:  October 20, 2005 | By:    |  /s/ ANNE E. MOUNSEY                   |   |
|                              |   |  Ann E. Mounsey                        |
|                              |   |  Director                              |
|                              |   |                                        |
| Date:  October 20, 2005 | By:    |  /s/ KAREN L. ROGERS                   |   |
|                              |   |  Karen L. Rogers                       |
|                              |   |  Director                              |
|                              |   |                                        |
| Date:  October 20, 2005 | By:    |  /s/ WILLIAM F. WALLACE                |   |
|                              |   |  William F. Wallace                    |
|                              |   |  Director                              |
|                              |   |                                        |
| Date:  October 20, 2005 | By:    |  /s/ DONALD D. WOLF                    |   |
|                              |   |  Donald D. Wolf                        |
|                              |   |  Director                              |

 

147

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| **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.                                                                                                                                                                                                                                                                                                                 |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 2.7(15)             |       | Asset Purchase and Sale  Agreement and addendum, thereto, dated as of July 1, 2004 by and between  American Central Eastern Texas Gas Company Limited Partnership, ACGC Gathering  Company, L.L.C. and MarkWest Energy East Texas Gas Company’s L.P.                                                                                                                                                                                                                                                                                                |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 3.1(1)              |       | Certificate of  Incorporation of MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 3.2(1)              |       | Bylaws of MarkWest  Hydrocarbon, Inc.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 4.1(7)              |       | Subordinated Unit  Purchase Agreement among MarkWest Hydrocarbon, Inc. and Tortoise MWEP,  L.P., dated as of November 20, 2002.                                                                                                                                                                                                                                                                                                                                                                                                                     |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 4.2(14)             |       | Purchase Agreement  dated as of June 13, 2003, by and among MarkWest Energy Partners, L.P.  and Tortoise Capital Advisors, LLC as attorney-in-fact for the Purchasers.                                                                                                                                                                                                                                                                                                                                                                                   |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 4.3(14)             |       | Registration Rights  Agreement dated as of June 13, 2003, by and among MarkWest Energy  Partners, L.P. and Tortoise Capital Advisors, LLC as attorney-in-fact for the  Purchasers.                                                                                                                                                                                                                                                                                                                                                                       |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 4.4(15)             |       | Unit Purchase Agreement dated as of  July 29, 2004 among MarkWest Energy Partners, L.P., and MarkWest Energy  GP, L.L.C. and each of Kayne Anderson Energy Fund II, L.P., and MarkWest  Energy GP, L.L.C. and each of Kayne Anderson Energy Fund II, L.P., Kayne  Anderson Capital Income Partners, L.P., Kayne Anderson MLP Fund, L.P., Kayne  Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR  RV Performance Master Trust, Tortoise Energy Infrastructure Corporation and  Energy Income and Growth Fund as Purchasers. |
|                |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 4.5(15)             |       | Registration Rights Agreement dated  as of July 29, 2004 among MarkWest Energy Partners, L.P., and each of  Kayne Anderson Energy Fund II, L.P., Kayne Anderson Capital Income Fund,  LTD., Kayne Anderson Income Partners, L.P., HFR RV                                                                                                                                                                                                                                                                                                                 |

 

148

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|           |   | Performance Master Trust, Tortoise  Energy Infrastructure Corporation and Energy Income and Growth Fund.                                                                                                                                                                                                                                                               |
|----------------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|           |   |                                                                                                                                                                                                                                                                                                                                                                   |
| 4.6(16)        |   | Underwriting Agreement dated as of  September 15, 2004 by and among the Partnership, the underwriters named  therein and the other parties thereto related to the Common Units Offering.                                                                                                                                                                          |
|           |   |                                                                                                                                                                                                                                                                                                                                                                   |
| 4.7(16)        |   | Purchase Agreement dated  October 19, 2004, among MarkWest Energy Partners, L.P., MarkWest Energy  Finance Corporation, the Guarantors named therein and the Initial Purchasers  named therein.                                                                                                                                                                   |
|           |   |                                                                                                                                                                                                                                                                                                                                                                   |
| 4.8(16)        |   | Registration Rights Agreement dated  October 25, 2004, among MarkWest Energy Partners, L.P., MarkWest Energy  Finance Corporation, the Guarantors named therein and the Initial Purchasers  named therein.                                                                                                                                                        |
|           |   |                                                                                                                                                                                                                                                                                                                                                                   |
| 4.9(16)        |   | Indenture dated as of October 25,  2004, among MarkWest Energy Partners, L.P., MarkWest Energy Finance  Corporation, the Guarantors named therein and Wells Fargo Bank, National  Association, as Trustee.                                                                                                                                                        |
|           |   |                                                                                                                                                                                                                                                                                                                                                                   |
| 4.10(16)       |   | Form of 6.875% Series A  Senior Notes due 2014 with attached notation of Guarantees (incorporated by  Reference to Exhibits A and D of Exhibit 4.9 hereto).                                                                                                                                                                                             |
|           |   |                                                                                                                                                                                                                                                                                                                                                                   |
| 10.1(2) D |   | 1996 Incentive  Compensation Plan.                                                                                                                                                                                                                                                                                                                                     |
|           |   |                                                                                                                                                                                                                                                                                                                                                                   |
| 10.2(1) D |   | 1996 Stock Incentive  Plan.                                                                                                                                                                                                                                                                                                                                            |
|           |   |                                                                                                                                                                                                                                                                                                                                                                   |
| 10.3(1) D |   | 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                                                                                                                                                                                                                                                                                   |

 

149

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|            |   | 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(9)        |   | Purchase and Sale  Agreement, dated as of June 5, 2003, by and among MarkWest  Hydrocarbon, Inc., MarkWest Resources, Inc., and XTO Energy Inc.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.18(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.                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.19(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.                                                                                                                                                                                                                                                                        |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.20(14) D     |   | Executive Employment  Agreement effective November 1, 2003 between MarkWest  Hydrocarbon, Inc. and Frank Semple.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.21(15)       |   | Second Amended and  Restated Credit Agreement dated as of July 30, 2004 among MarkWest  Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners,  L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis  Capital Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and  Societe Generale, as Documentation Agent to the $315,000,000 Senior Credit  Facility.                                                                                                                                                                                                                            |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.22(15)       |   | First Amendment to the Second Amended  and Restated Credit Agreement dated as of August 20, 2004, among  MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy  Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent,  Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation  Agent and Societe Generale, as Documentation Agent.                                                                                                                                                                                                                                              |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.23(17)       |   | Third Amended and Restated Credit  Agreement dated as of October 25, 2004 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, N.A., as Syndication  Agent, Fortis Capital Corp., as Documentation Agent, U.S. Bank National  Association, as Documentation Agent, Societe Generale, as Documentation  Agent, and Wachovia Bank, National Association, as Documentation Agent, RBC  Capital Markets and J.P. Morgan Securities Inc., as Lead Arrangers and Joint  Bookrunners, to the $200,000,000 Senior Credit Facility. |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.24(5) D |   | MarkWest Energy Partners, L.P.  Long-Term Incentive Plan.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.24(5) D |   | First Amendment to MarkWest Energy  Partners, L.P. Long-Term Incentive Plan.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.25(18)       |   | Credit Agreement among  MarkWest Hydrocarbon, Inc. as the Borrower, Royal Bank of                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |

 

150

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|     |   | Canada, as  Administrative Agent and The Lenders Party Hereto to the $25,000,000 Senior  Credit Facility.                                                           |
|----------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|     |   |                                                                                                                                                                |
| 10.26+   |   | Purchase and Sale of  Natural Gas Agreement dated as of September 24, 2004, between MarkWest  Hydrocarbon, Inc. and Equitable Production Company.         |
|     |   |                                                                                                                                                                |
| 10.27+   |   | A Firm Natural Gas  Processing Agreement dated as of September 24, 2004, between MarkWest  Hydrocarbon, Inc. and Equitable Production Company.            |
|     |   |                                                                                                                                                                |
| 10.28+   |   | A Netting, Financial  and Security Agreement dated as of September 24, 2004, between MarkWest  Hydrocarbon, Inc. and Equitable Production Company.        |
|     |   |                                                                                                                                                                |
| 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.                                                                                                                             |
|     |   |                                                                                                                                                                |
| 23.2 *   |   | Consent of KPMG 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 *   |   | Chief Financial Officer  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  Chief Financial Officer 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 Energy Partners, L.P.’s Current Report on Form 8-K  filed with the Commission on June 29, 2003.                                                                    |
| (10) |   | Incorporated by  reference to MarkWest Hydrocarbon, Inc.’s Current Report on  Form 8-K, filed with the Commission on July 15, 2003.                                                                  |
| (11) |   | Incorporated by  reference to MarkWest Energy Partners, L.P.’s Current Report on  Form 8-K, filed with the Commission on September 17, 2003.                                                              |

 

151

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| (12) |   | Incorporated by  reference to MarkWest Energy Partners, L.P.’s Current Report on  Form 8-K, filed with the Commission on December 16, 2003.                                                                                                                              |
|------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (13) |   | Incorporated by  reference to MarkWest Energy Partners, L.P.’s Current Report on  Form 8-K, filed with the Commission on December 31, 2003.                                                                                                                              |
| (14) |   | Incorporated by  reference to MarkWest Hydrocarbon, Inc.’s Annual Report on  Form 10-K filed with the Commission on March 30, 2004.                                                                                                                                 |
| (15) |   | Incorporated by  reference to MarkWest Energy Partners, L.P.’s Current Report on  Form 8-K/A filed with the Commission on September 13, 2004.                                                                                                                            |
| (16) |   | Incorporated by  reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K  filed with the Commission on October 25, 2004.                                                                                                                                |
| (17) |   | Incorporated by  reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K  filed with the Commission on October 29, 2004.                                                                                                                                |
| (18) |   | Incoporated by  reference to MarkWest Hydrocarbon, Inc.’s Current Report on  Form 8-K filed with the Commission on October 29, 2004.                                                                                                                                |
| +    |   | 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.                                                                                                                                                                                                                                                                         |
| D    |   | Identifies each management  contract or compensatory plan or arrangement.                                                                                                                                                                                                               |

 

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