**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

 

**FORM 10-K**

 
| **ý** | ** ** | **Annual  report pursuant to Section 13 or 15(d) of the Securities Exchange  Act of 1934**                                                                                                                            |
|------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** ** | ** ** | **for the fiscal year ended December 31,  2005.**                                                                                                                                                                          |
|       |       |                                                                                                                                                                                                                            |
| **o**      | ** ** | **Transition  report pursuant to Section 13 or 15(d) of the Securities Exchange  Act of 1934**                                                                                                                        |
| ** ** | ** ** | **for the transition period from                   to                 .** |

 

**CommissionFile Number 001-14841**

 

**MARKWEST HYDROCARBON, INC.**

(Exact name of registrant asspecified in its charter)

 
| **Delaware**                                                     | ** ** | **84-1352233**                         |
|------------------------------------------------------------------|------------|----------------------------------------|
| (State or  other jurisdiction of  incorporation or organization) |       | (I.R.S.  Employer  Identification No.) |

 

**155Inverness 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 is a well-known seasonedissuer, as defined in Rule 405 of the Securities Act. Yes o No ý

 

Indicate by check mark if the registrantis not required to file reports pursuant to Section 13 or 15(d) ofthe Act. Yes o No ý

 

Indicate by check mark whether theregistrant (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding 12months (or for such shorter period that the registrant was required to filesuch reports), and (2) has been subject to such filing requirements forthe past 90 days.  Yes o No ý

 

Indicate by check mark if disclosure ofdelinquent filers pursuant to Item 405 of Regulation S-K is not containedherein, and will not be contained, to the best of registrant’s knowledge, indefinitive proxy or information statements incorporated by reference in Part IIIof this Form 10-K or any amendment to this Form 10-K.  o

 

Indicate by check mark whether the registrant is a large acceleratedfiler, an accelerated filer, or a non-accelerated filer.  See definition of “accelerated filer andlarge accelerated filer” in Rule 12b-2 of the Exchange Act.  (Check one)

Large accelerated filer o             Accelerated filer ý                                          Non-acceleratedfiler o

 

Indicate by check mark whether the registrant is a shell company (asdefined 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, 2005 was approximately$147,374,000.

 

 The registrant had 10,802,488shares of common stock, $0.01 per share par value, outstanding as of January 31,2006.

 

**DOCUMENTSINCORPORATED BY REFERENCE: None**

 

 

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**MarkWest Hydrocarbon, Inc.**

**Form 10-K**

**Table ofContents**

 
| **PART I**   |                                                                                             |
|-------------------|--------------------------------------------------------------------------------------------------|
| Item  1.          | Business                                                                                         |   |
| Item 1a.          | Risk  Factors                                                                                    |   |
| Item 1b.          | Unresolved Staff Comments                                                                        |   |
| Item 2.           | Properties                                                                                       |   |
| Item 3.           | Legal Proceedings                                                                                |   |
| Item 4.           | Submission of Matters to a Vote of Security  Holders                                             |   |
|              |                                                                                             |
| **PART II**  |                                                                                             |
| Item 5.           | Market for  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                                                      |   |
|              |                                                                                             |   |
| **SIGNATURES**    |                                                                                             |

 

Throughout this document we make statementsthat are classified as “forward-looking.” Please refer to the “Forward-LookingStatements” included later in this section for an explanation of thesetypes of assertions. Also, in this document, unless the context requiresotherwise, references to “we,” “us,” “our,” “MarkWest Hydrocarbon” or the “Company”are intended to mean MarkWest Hydrocarbon, Inc., and its consolidatedsubsidiaries.  “MarkWest Energy” or “MarkWestEnergy Partners” or the “Partnership” are intended to mean MarkWest EnergyPartners, L.P.

 

**Glossary of Terms**

 

In addition, the following is a list of certain acronyms and terms usedthroughout 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                                                     |
| Mcf                                                  |   | one thousand cubic feet of natural gas                              |
| Mcf/d                                                |   | one thousand cubic feet of natural gas per  day                     |
| MMBtu                                                |   | one million British thermal units, an  energy measurement           |
| MMcf                                                 |   | one million cubic feet of natural gas                               |
| MMcf/d                                               |   | one million cubic feet of natural gas per  day                      |
| MTBE                                                 |   | methyl tertiary butyl ether                                         |
| Net operating margin (a non-GAAP financial  measure) |   | revenues less purchased product costs                               |
| NGLs                                                 |   | natural gas liquids, such as propane,  butanes and natural gasoline |
| NA                                                   |   | not applicable                                                      |
| Tcf                                                  |   | one trillion cubic feet of natural gas                              |

 

2

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**Forward-Looking Statements**

 

Statements included in this annual report on Form 10-K that arenot historical facts are forward-looking statements within the meaning of Section 27Aof the Securities Act of 1933, as amended, and Section 21E of theSecurities and Exchange Act of 1934, as amended. We use words such as “may,” “believe,”“estimate,” “expect,”  “intend,” “project,”“anticipate,” and similar expressions to identify forward-looking statements.

 

These forward-looking statements are madebased upon management’s expectations, estimates, assumptions and beliefsconcerning future events impacting us and therefore involve a number of risksand uncertainties. We caution that forward-looking statements are notguarantees and that actual results could differ materially from those expressedor implied in the forward-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.

 

Importantfactors that could cause our actual results of operations or our actualfinancial condition to 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.

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

•     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 organic growth projects or acquisitionscomplementary to our business.

•     Damageto facilities and interruption of service due to casualty, weather, mechanicalfailure or any extended or extraordinary maintenance or inspection that may berequired.

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

•     Thethreat of terrorist attacks or war.

•     Winterweather conditions.

 

This list is not necessarily complete. Otherunknown or unpredictable factors could also have material adverse effects onfuture results. The Company does not update publicly any forward-lookingstatement with new information or future events.  Investors are cautioned not to put unduereliance on forward-looking statements as many of these factors are beyond ourability to control or predict. You should read “Risk Factors” included in Item1A of this Form 10-K for further information.

 

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# **PART I**

 

## **ITEM 1.BUSINESS**

 

##### **General**

 

MarkWestHydrocarbon was founded in 1988 as a partnership and later incorporated inDelaware.  We completed our initial public offering of common shares in1996.

 

MarkWestHydrocarbon is an energy company primarily focused on marketing natural gasliquids (NGLs) and increasing shareholder value by growing MarkWest Energy Partners,L.P. (“MarkWest Energy” or “MarkWest Energy Partners” or “The Partnership”),our consolidated subsidiary and a publicly-traded master limitedpartnership.  MarkWest Energy Partners isengaged in the gathering, processing and transmission of natural gas; thetransportation, fractionation and storage of natural gas liquids; and thegathering and transportation of crude oil. The Company discontinued its exploration and production activities in2003.

 

MarkWest Hydrocarbon’s assets consistprimarily of partnership interests in MarkWest Energy Partners and certainprocessing agreements in Appalachia.  As of December 31, 2005, theCompany owned a 21% interest in the Partnership, consisting of the following:

 

•    1,633,334 subordinated units and 836,162 commonunits, representing a 19% limited partner interest in the Partnership; and

•    an 89% ownership interest in MarkWest EnergyGP, L.L.C., the general partner of the Partnership, which in turn owns a 2%general partner interest and all of the incentive distribution rights in thePartnership.

 

**IndustryOverview, Competition**

 

MarkWestEnergy Partners provides services in most areas of the natural gas gathering,processing and fractionation industry. The following diagram illustrates the typical natural gas gathering,processing and fractionation process:

 

 

Thenatural gas gathering process begins with the drilling of wells intogas-bearing rock formations.  Oncecompleted, the well is connected to a gathering system.  Gathering systems typically consist of a networkof small diameter pipelines and, if necessary, compression systems, thatcollect natural gas from points near producing wells, and transport it tolarger pipelines for further transmission.

 

Naturalgas has a widely varying composition, depending on the field, the formationreservoir or facility from which it is produced. The principal constituents ofnatural gas are methane and ethane.  Mostnatural gas also contains varying amounts of heavier components, such aspropane, butane, natural gasoline and inert substances that may be removed byany number of processing methods.

 

Most naturalgas produced at the wellhead is not suitable for long-haul pipelinetransportation or commercial use.  Itmust be gathered, compressed and transported via pipeline to a centralfacility, and then processed to remove the heavier hydrocarbon components andother contaminants that interfere with pipeline transportation or the end-useof the gas.  Our business includesproviding these services either for a fee or a percentage of the NGLs removedor gas units processed.  Theindustry as a whole is characterized by regional competition, based on theproximity of gathering systems and processing plants to producing natural gaswells.

 

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MarkWest Energy also provides processing andfractionation services to crude oil refineries in the Corpus Christi, Texas,area through its Javelina Gas Processing and Fractionation facility. Whilesimilar to the natural gas industry diagram outlined above, the followingdiagram illustrates the significant gas processing and fractionation processesat the Javelina Facility:

 

 

Natural gas processing and treating involvesthe separation of raw natural gas into pipeline-quality or fuel quality naturalgas, principally methane, and NGLs, as well as the removal ofcontaminants.  Raw natural gas from thewellhead is gathered at a processing plant, typically located near theproduction area, where it is dehydrated and treated, and then processed torecover a mixed NGL stream.  In the caseof our Javelina facilities, the natural gas delivered to our processing plantis a byproduct of the crude oil refining process.

 

The removal and separation of individualhydrocarbons by processing is possible because of differences in physicalproperties.  Each component has adistinctive weight, boiling point, vapor pressure and other physicalcharacteristics. Natural gas may also be diluted or contaminated by water,sulfur compounds, carbon dioxide, nitrogen, helium or other components.  At the Javelina facility, MarkWest alsoproduces a height quality hydrogen stream that is delivered back to certainrefinery customers.

 

After being separated from natural gas at theprocessing plant, the mixed NGL stream is typically transported to acentralized facility for fractionation. Fractionation is the process by which NGLs are further separated intoindividual, more marketable components, primarily ethane, propane, normalbutane, isobutane and natural gasoline. Fractionation systems typically existeither as an integral part of a gas processing plant or as a “centralfractionator,” often located many miles from the primary production andprocessing facility. A central fractionator may receive mixed streams of NGLsfrom many processing plants.

 

Described below are the five basic NGLproducts and three other products, and their typical uses:

 

•                  *Ethane* is used primarily as feedstock inthe production of ethylene, one of the basic building blocks for a wide rangeof plastics and other chemical products. Ethane is not produced at our Siloam fractionator, as there is littlepetrochemical demand for ethane in Appalachia. It remains, therefore, in the natural gas stream.  Ethane, however, is produced and sold in ourEast Texas and Oklahoma operations.

 

•                  *Propane* is used for heating, engine andindustrial fuels, agricultural burning and drying, and as a petrochemicalfeedstock for the production of ethylene and propylene.  Propane is principally used as a fuel in ouroperating areas.

 

•                  *Normal butane* is principally used forgasoline blending, as a fuel gas, either alone or in a mixture with propane,and as a feedstock for the manufacture of ethylene and butadiene, a keyingredient of synthetic rubber.

 

•                  *Isobutane* is principally used by refinersto enhance the octane content of motor gasoline, as well as in the productionof MTBE, an additive in cleaner-burning motor gasoline.

 

•                  *Natural gasoline* is principally used as amotor gasoline blend stock or petrochemical feedstock.

 

•                  *Ethylene and propylene* are principallyused as petrochemical feedstocks.

 

•                  *Hydrogen*is**principally used in the refining process to assist in theproduction of low sulfur products.

 

5

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MarkWest Hydrocarbon faces competition formarketing NGL products and purchasing natural gas supplies. Competition forcustomers and purchases of natural gas are based primarily on price, deliverycapabilities, flexibility and maintenance of quality customer relationships.  The Company’s competitors are similar tothose of MarkWest Energy Partners (described below).

 

The Partnership faces competition for naturalgas and crude oil transportation; in obtaining natural gas supplies for ourprocessing 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, andthe ability to obtain a satisfactory price for products recovered. Competitivefactors affecting the Partnership’s fractionation services include availabilityof capacity, proximity to supply and industry marketing centers, costefficiency and reliability of service, and, in the case of Javelina, the valueof the recovered products compared to their equivalent value when consumed atthe refineries as fuel. Competition for customers is based primarily on price,delivery capabilities, flexibility, and maintenance of quality customerrelationships.

 

The Partnership’s competitors include:

 

•                                          other large natural gas gatherers that gather,process and market natural gas and NGLs;

 

•                                          majorintegrated oil companies;

 

•                                          mediumand large sized independent exploration and production companies;

 

•                                          majorinterstate and intrastate pipelines; and

 

•                                          alarge number of smaller gas gatherers of varying financial resources andexperience.

 

We believe the Partnership’s competitivestrengths include**:**

 

•                  *Location and efficiency of facilities.* Inmany locations, the Partnership’s facilities were installed more recently andare more efficient than those of its competitors. This provides the Partnershipwith a significant competitive advantage over its competitors. In otherlocations, there are no other viable facilities to provide similar services asthe Partnership provides.

 

•              *Long-term contracts.* We believe MarkWestEnergy Partners’ long-term contracts, which we define as contracts withremaining terms of four years or more, lend greater stability to its cash-flowprofile.

 

•              *Experienced management with operational, technicaland acquisition expertise. *Eachmember of our executive management team has substantial experience in theenergy industry. Our facility managers have extensive experience operating ourfacilities.  Our operational andtechnical expertise has enabled us to upgrade our existing facilities, as wellas to design and build new ones.  Sincethe Partnership’s initial public offering in May 2002, our management teamhas utilized a disciplined approach to analyze and evaluate numerousacquisition opportunities, and has completed eight acquisitions.  We intend to continue to use our management’sexperience and disciplined approach in evaluating and acquiring assets to growthrough accretive acquisitions – those acquisitions expected to increase our throughput volumes and cash flowdistributable to our unitholders.

 

To better understand our business and resultsof operations discussed in Item 6, “Selected Financial Data” and Item 7, “Management’sDiscussion and Analysis of Financial Condition and Results of Operation,” it isimportant to have an understanding of three factors:

 

•                  Thenature of our relationship with MarkWest Energy Partners;

•                  Thenature of the contracts from which we derive our revenues and from whichMarkWest Energy Partners derives its revenues; and

•                  Thelack of comparability within our results of operations across periods becauseof MarkWest Energy Partners’ significant acquisition activity.

 

***Our Relationship with MarkWest Energy Partners***

 

Wespun off the majority of our then-existing natural gas gathering and processingand NGL transportation, fractionation and storage assets into MarkWest EnergyPartners in May 2002, just before the Partnership completed its initialpublic offering. At the time of its formation and initial public offering, weentered into four contracts with MarkWest Energy

 

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Partnerswhereby MarkWest Energy Partners provides midstream services in Appalachia tous for a fee.  Additionally, MarkWestEnergy Partners receives 100% of all fee and percent-of-proceeds considerationfor the first 10 MMcf/d that it gathers and processes in Michigan. MarkWestHydrocarbon retains a 70% net profits interest in the gathering and processingincome earned on quarterly pipeline throughput in excess of 10 MMcf/d.  In accordance with generally acceptedaccounting principles, MarkWest Energy Partners’ financial results are includedin our consolidated financial statements.  All intercompany accounts andtransactions are eliminated during consolidation.

 

Asa result of the contracts mentioned above, the Company is one of thePartnership’s largest customers.  For the yearended December 31, 2005, we accounted for 13% of the Partnership’srevenues and 20% of its net operating margin. This represents a decrease from the year ended December 31, 2004,when we accounted for 20% of the Partnership’s revenues and 32% of its netoperating margin.  Weexpect we will continue to account for less of the Partnership’s business inthe future as it continues to acquire assets and increase its customer base ordiversify its business.

 

Wecontrol and operate MarkWest Energy Partners through our majority ownership inthe Partnership’s general partner.  Ouremployees are responsible for conducting the Partnership’s business andoperating its assets pursuant to a Services Agreement, which was formalized andmade effective January 1, 2004.

 

# ***MarkWest Hydrocarbon Contracts***

#  

Excludingthe revenues derived from MarkWest Energy Partners, we generate the majority ofour revenues and net operating margin  (netoperating margin is discussed further, below)from the Appalachia processing agreements. We outsource these services to thePartnership and pay the Partnership a fee for providing processing andfractionation services. As compensation for providing processing services toour Appalachian producers, we earn a fee and receive title to the NGLsproduced. In return, we are required to replace, in dry natural gas, the Btuvalue of the NGLs extracted.  This Btureplacement obligation is referred to in the industry as a “keep-whole”arrangement. In keep-whole arrangements, our principal cost is purchasing anddelivering dry gas of an equivalent Btu content to replace Btus extracted fromthe gas stream in the form of NGLs, or consumed as fuel during processing. The spread between the NGL product sales price and the purchase price ofnatural gas with an equivalent Btu content is called the “frac spread.”Generally, the frac spread is positive and offsets all or a portion of the feesthat we pay the Partnership.  In theevent natural gas becomes more expensive on a Btu equivalent basis than NGLproducts and the associated fees that we pay the Partnership, the net operatingmargin associated with the Appalachian processing agreements results inoperating losses.

 

In Appalachia, we have entered into operating agreements with acustomer with respect to natural gas delivered into its transmissionfacilities, upstream of MarkWest Energy’s Kenova, Boldman and Cobb facilities.Under the terms of these operating agreements, the customer has agreed to usereasonable, diligent efforts to supply these facilities with consistent volumesof natural gas shipped by the customer, on behalf of the Appalachian producers.The initial terms of our agreements with this customer run through December 31,2015, with annual renewals thereafter.

 

In September 2004, we entered intoseveral new and amended agreements, expiring December 31, 2009, with oneof the largest Appalachia producers, which allow us to significantly reduce ourexposure to commodity price risk, for approximately 25% of our keep-whole gasvolumes.  Under these agreements, the Company’s exposure to the keep-wholenatural gas is limited in the event natural gas becomes more expensive than theNGL product sales price, thereby mitigating the risk of incurring operatinglosses.

 

Atthe closing of MarkWest Energy Partners’ initial public offering on May 24,2002, we outsourced our midstream services to the Partnership.  Pursuant to the terms of the operatingagreements, we retained all the benefits and associated risks of our keep-wholecontracts with producers.  Our NGLmarketing and natural gas supply operations were retained by us and notcontributed to MarkWest Energy Partners.

 

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, in turn, mayincrease the volatility of our standalone results and cash flows.  We attempt to mitigate our commodity pricerisk through our commodity price risk management program (see Item 7A, “Quantitativeand Qualitative Disclosures about Market Risk” for further details about ourcommodity price risk management program).

 

7

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***MarkWest Energy Partners’ Contracts***

 

The Partnership generates the majority of itsrevenues and net operating margin (defined as revenues less purchased productcosts – see explanation of net operating margin below) from natural gasgathering, processing and transmission; NGL transportation, fractionation andstorage; crude oil gathering and transportation; and refinery off-gasprocessing. It has a variety of contract types. In many cases, the Partnership provides services under contracts thatcontain a combination of more than one of the arrangements described below.

 

•                  *Fee-based arrangements.*  The Partnership receives fees for gathering,processing and transmission of natural gas; transportation, fractionation andstorage of NGLs; and gathering and transportation of crude oil. The revenue itearns from these arrangements is directly related to the volume of natural gas,NGLs or crude oil that flows through its systems and facilities, and is notdirectly dependent on commodity prices. In certain cases, these arrangements provide for minimum annualpayments. If a sustained decline in commodity prices resulted in a decline involumes, our revenues from these arrangements would be reduced.

 

•                  *Percent-of-proceeds arrangements.*  The Partnership generally gathers andprocesses natural gas on behalf of producers, sells the resulting residue gasand NGLs at market prices, and remits to producers an agreed-upon percentage ofthe proceeds based on an index price. In other cases, instead of remitting cashpayments to the producer, the Partnership delivers an agreed-upon percentage ofthe residue gas and NGLs to the producer, and sells the volumes it keeps tothird parties at market prices.  Under thesetypes of arrangements, its revenues and net operating margins generallyincrease as natural gas prices and NGL prices increase, and its revenues andnet operating margins decrease as natural gas and NGL prices decrease. The mostcommon arrangement is a percent of liquids or POL contract.

 

•                  *Percent-of-index arrangements.*  The Partnership generally purchases naturalgas at either (1) a percentage discount to a specified index price, (2) aspecified index price less a fixed amount, or (3) a percentage discount toa specified index price less an additional fixed amount. It then gathers anddelivers the natural gas to pipelines, where it resells the natural gas at theindex price, or at a different percentage discount to the index price. The netoperating margins the Partnership realizes under these arrangements decrease inperiods of low natural gas prices, because these net operating margins arebased on a percentage of the index price. Conversely, our net operating marginsincrease during periods of high natural gas prices.

 

•                  *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 the extraction of the NGLs from the naturalgas during processing reduces the Btu content of the natural gas, thePartnership must either purchase natural gas at market prices for return toproducers, or make cash payment to the producers equal to the energy content ofthis natural gas. Accordingly, under these arrangements, its revenues and netoperating margins increase as the price of NGLs increases relative to the priceof natural gas, and decreases as the price of natural gas increases relative tothe price of NGLs.

 

 •               *Settlement margin.*  Typically, the terms of the Partnership’sgathering 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 gatheringsystem is operated more efficiently than specified per contract allowance, thePartnership is entitled to retain the difference for its own account.

 

In its current areas of operations, MarkWestEnergy Partners utilizes a combination of contract types.  In many cases, the Partnership providesservices under contracts that contain a combination of more than one of thearrangements described above.  The termsof MarkWest Energy Partners’ contracts vary based on gas quality, thecompetitive environment at the time the contracts are signed and customerrequirements.  The Partnership’s contractmix and, accordingly, its exposure to natural gas and NGL prices, may changedue to changes in producer preferences, the Partnership’s expansion in regionswhere some types of contracts are more common, and other market factors.  Any change in the contract portfolio willinfluence its financial results.

 

Management evaluates contract performance onthe basis of net operating margin (a “non-GAAP” financial measure), which isdefined as income (loss) from operations, excluding facility expenses, selling,general and administrative expense, depreciation, amortization, impairments andaccretion of asset retirement obligations. These charges have been excluded for the purpose of enhancing theunderstanding, by both management and investors, of the underlying baselineoperating performance of our contractual arrangements, which management uses toevaluate our financial performance, for purposes of planning and forecastingfuture periods.   Net operating margindoes not have any standardized definition and,

 

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therefore, is unlikely to becomparable to similar measures presented by other reporting companies. Netoperating margin results should not be evaluated in isolation of, or as asubstitute for, our financial results prepared in accordance with United StatesGAAP. Our usage of net operating margin, and the underlying methodology inexcluding certain charges, is not necessarily an indication of the results ofoperations that may be expected in the future, or that we will not, in fact,incur such charges in future periods. The following reconciles this non-GAAP financial measure to income fromoperations, the most comparable GAAP financial measure (in thousands):

 

| ** **                                    | ** ** | **December 31,  2005** | ** ** | **December 31,  2004** | ** ** | **December 31,  2003** | ** ** |
|-----------------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| Revenues                                      |       | $                           | 714,177    |                        | $          | 460,113                     |       | 209,268 |   |
|                                          |       |                        |       |                        |       |                        |       |
| Purchased  product costs                      |       | 583,084                     |       | 363,261                     |       | 187,544                     |       |
|                                          |       |                        |       |                        |       |                        |       |
| Net  operating margin                         |       | 131,093                     |       | 96,852                      |       | 21,724                      |       |
|                                          |       |                        |       |                        |       |                        |       |
| Facility expenses                             |       | 45,577                      |       | 28,580                      |       | 20,957                      |       |
| Selling,  general and administrative expenses |       | 33,350                      |       | 28,132                      |       | 15,865                      |       |
| Depreciation                                  |       | 20,829                      |       | 16,895                      |       | 8,795                       |       |
| Amortization  of intangible assets            |       | 9,656                       |       | 3,640                       |       | —                      |       |
| Accretion of  asset retirement obligation     |       | 160                         |       | 15                          |       | —                      |       |
| Impairments                                   |       | —                      |       | 130                         |       | 2,187                       |       |
| Income from  operations                       |       | $                           | 21,521     |                        | $          | 19,460                      |       | (26,080 | ) |

 

For the year ended December 31, 2005,the following table summarizes the percentages of revenue and net operatingmargin we generated by types of contracts, exclusive of the impact of commodityderivatives:

 
| ** **            | ** ** | **Fee-Based (1)** | ** ** | **Percent-of-Proceeds  (2)** | ** ** | **Percent-of-Index (3)** | ** ** | **Keep-Whole (4)** | ** ** | **Total** | ** ** |
|-----------------------|------------|-------------------|------------|------------------------------|------------|--------------------------|------------|--------------------|------------|-----------|------------|
| Revenues              |       | 23                | %          | 3                            | %          | 24                       | %          | 50                 | %          | 100       | %          |
| Net  operating margin |       | 35                | %          | 15                           | %          | 29                       | %          | 21                 | %          | 100       | %          |

 

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(1)   Includes gas marketing and NGL wholesale revenues.

(2)   Includes other types of arrangements tied to NGL prices.

(3)   Includes settlement margin, condensate sales and other types ofarrangementes tied to natural gas prices.

(4)   Includes settlement margin, condensate sales and other types ofarrangements tied to both NGL and natural gas prices.

 

##### ***Items Affecting Comparability ofFinancial Results***

 

In reading the discussion of our historicalresults of operations, you should be aware of the impact of MarkWest EnergyPartners’ recent significant acquisitions, which influence the comparability ofour results of operations for the periods discussed.

 

***MarkWestEnergy Partners’ Recent Acquisitions***

 

Since its initial public offering, thePartnership has completed eight acquisitions for an aggregate purchase price ofapproximately $794.4 million, net of working capital.  The following table sets forth informationregarding each of these acquisitions:

 

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| **Name**                | ** ** | **Assets**                                                       | ** ** | **Location**                       | ** ** | **Consideration  (in millions)** | ** ** | **Closing Date** | ** **              |
|-------------------------|------------|------------------------------------------------------------------|------------|------------------------------------|------------|----------------------------------|------------|------------------|-------------------------|
| Javelina                |       | Gas processing and  fractionation facility                       |       | Corpus Christi, TX                 |       | $                                | 398.3      |             | November 1,  2005  |   |
|                    |       |                                                             |       |                               |       |                             |       |             |                    |   |
| Starfish (1)            |       | Natural gas  pipeline, gathering system and dehydration facility |       | Gulf of  Mexico/Southern Louisiana |       | $                                | 41.7       |             | March 31,  2005    |   |
|                    |       |                                                             |       |                               |       |                             |       |             |                    |   |
| East Texas              |       | Gathering system  and gas procession assets                      |       | East Texas                         |       | $                                | 240.7      |             | July 30, 2004      |   |
|                    |       |                                                             |       |                               |       |                             |       |             |                    |   |
| Hobbs                   |       | Natural gas  pipeline                                            |       | New Mexico                         |       | $                                | 2.3        |             | April 1, 2004      |   |
|                    |       |                                                             |       |                               |       |                             |       |             |                    |   |
| Michigan Crude Pipeline |       | Common carrier crude  oil pipeline                               |       | Michigan                           |       | $                                | 21.3       |             | December 18,  2003 |   |
|                    |       |                                                             |       |                               |       |                             |       |             |                    |   |
| Western Oklahoma        |       | Gathering system                                                 |       | Western Oklahoma                   |       | $                                | 38.0       |             | December 1,  2003  |   |
|                    |       |                                                             |       |                               |       |                             |       |             |                    |   |
| Lubbock Pipeline        |       | Natural gas  pipeline                                            |       | West Texas                         |       | $                                | 12.2       |             | September 2,  2003 |   |
|                    |       |                                                             |       |                               |       |                             |       |             |                    |   |
| Pinnacle                |       | Natural gas  pipelines and gathering systems                     |       | East Texas                         |       | $                                | 39.9       |             | March 28,  2003    |   |

 

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(1)          Represents a 50%, non-controlling interest.

 

***Segment Reporting***

 

*Segments*.  We have two segments:  MarkWest Hydrocarbon Standalone and MarkWestEnergy Partners.  For furtherinformation, see “Management’s Discussion and Analysis of Financial Conditionand Results of Operations – Our Contracts,” included in Item 7 of this Form 10-K,and “Financial Statements and Supplementary Data,” included in Item 8 of this Form 10-K.

 

***MarkWestHydrocarbon Standalone***

 

Our marketing group markets our NGLproduction in Appalachia.  In 2005, we sold approximately 157 milliongallons of NGLs extracted at the Partnership’s Siloam facility.  We shipNGL products from Siloam by truck, rail and barge. Our marketing customersinclude propane retailers, refineries, petrochemical plants and NGL productresellers.  Most marketing sales contracts have terms of one year or less,are made on best-efforts basis and are priced in reference to Mt. Belvieu indexprices or plant posting prices.  In addition to our NGL product sales, ourmarketing operations are also responsible for the purchase of natural gasdelivered for the account of producers, pursuant to our keep-whole processingcontracts.  Also, we operate a wholesalepropane marketing business.

 

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

 

In Appalachia, we have entered into operatingagreements with one specific customer 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, thiscustomer has agreed to use reasonable, diligent efforts to supply thesefacilities with consistent volumes of natural gas shipped by this customer, onbehalf of the Appalachian producers. The initial terms of our agreements withthis customer run through December 31, 2015, with annual renewalsthereafter.

 

Consistent with the Partnership’s operatingagreements with this same customer, the Partnership enters into contracts withthe natural gas producers for their production to be processed in thePartnership’s Kenova, Boldman and Cobb facilities, before delivery of theproducer’s natural gas to the customer’s transmission facilities. We have contractualcommitments with approximately 260 such producers in Appalachia. Approximately54% of these contracts, representing approximately 27% of the committedvolumes, expire in 2009. The other 46% of the contracts, representingapproximately 73% of the committed volumes, expires in 2015.  Under theprovisions of our contracts with the Appalachian producers, the producers have

 

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committed all of the naturalgas they deliver into the customer’s transmission facilities upstream ofMarkWest Energy’s Kenova, Boldman and Cobb facilities for processing.

 

As compensation for providing processingservices to our Appalachian producers (we have since outsourced these servicesto MarkWest Energy as discussed below), we earn both a fee and retain the NGLsproduced under keep-whole agreements.  In return, we are required toreplace, in dry natural gas, the energy content of the NGLs extracted.

 

In September 2004, we entered intoseveral new and amended agreements, expiring December 31, 2009, with oneof the largest Appalachia producers, which allow us to significantly reduce ourexposure to commodity price risk, for approximately 25% of our keep-whole gasvolumes.  Under these agreements, we purchase natural gas from theproducer based on the value of the NGLs that we sell, thereby mitigating therisk of incurring operating losses.

 

At the closing of MarkWest Energy’s initialpublic offering on May 24, 2002, we outsourced our midstream services tothe Partnership, which performs natural gas gathering and processing and NGLtransportation, fractionation and storage services for us for a fee pursuant tothe terms of our operating agreements with the Partnership.  Under thoseagreements, we retained all the benefits and associated risks of our keep-wholecontracts with producers.  Our NGL marketing and gas supply operationswere not contributed to MarkWest Energy.

 

Our keep-whole contracts expose us tocommodity price risk, both on the sales side (of NGLs) and on the purchase side(of natural gas), which may make our marketing results and cash flows volatile.From time to time, we attempt to mitigate our commodity price risk through ourhedging program. You should read Item 7A, “Q*uantitativeand Qualitative Disclosures About Market Risk*,”**for furtherdetails about our commodity price risk management program.

 

Beginning in February 2004, we initiateda wholesale propane marketing business through an agency relationship with athird party marketer located in Kansas City, Missouri.  We buy propane ona wholesale basis and resell it to third parties, primarily propaneretailers.  This operation is fundamentally a high-volume, low marginbusiness.  For the years ended December 31, 2005 and 2004, 9%and 7%, respectively, of our revenue stemmed from our wholesale propanemarketing business.   The wholesalepropane marketing business’ net operating margin in 2005 and 2004, as a percentof consolidated net operating margin, was 1% and 1%, respectively.

 

***MarkWestEnergy Partners***

 

MarkWest Energy Partners’ operations may besummarized as follows:

 

**Southwest BusinessUnit**

 

•                 ***East Texas****.* MarkWest Energy Partners owns the East Texas System, consisting ofnatural gas-gathering system pipelines, centralized compressor stations, and anatural gas processing facility and NGL pipeline that are currently underconstruction. The East Texas System is located in Panola County and servicesthe Carthage Field, one of Texas’ largest onshore natural gas fields.  Producing formations in Panola County consistof the Cotton Valley, Pettit and Travis Peak formations, which together formone of the largest natural gas-producing regions in the United States.  The Carthage Field has an estimated 18 Tcf ofremaining recoverable reserves, and cumulative historical production in excessof 12 Tcf.

 

•                 ***Oklahoma***. MarkWestEnergy Partners owns the Foss Lake gathering system and the Arapahogas-processing plant, located in Roger Mills and Custer counties of WesternOklahoma.  The gathering portion consistsof a pipeline system that is connected to natural gas wells and associatedcompression facilities.   All of thegathered gas ultimately is compressed and delivered to the processingplant.  After processing, the residue gasis delivered to a third-party pipeline and natural gas liquids are sold to asingle customer.

 

•                 ***Other Southwest***.MarkWest Energy Partners owns 17 natural gas-gathering systems located inTexas, Louisiana, Mississippi and New Mexico. These systems generally service long-lived natural gas basins that continueto experience drilling activity.  ThePartnership gathers a significant portion of the gas produced from fieldsadjacent to its gathering systems.   Inaddition, the Partnership owns four lateral pipelines in Texas and New Mexico.

 

**Northeast Business Unit**

 

•                 ***Appalachia*.**  MarkWest Energy Partners is the largestprocessor of natural gas in the Appalachian Basin with fully integratedprocessing, fractionation, storage and marketing operations.  The Appalachian Basin is a large naturalgas-producing region characterized by long-lived reserves and modest declinerates.

 

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•                 ***Michigan*. **MarkWest Energy Partners owns aninterstate crude oil gathering pipeline in Michigan and refers to this systemas the Michigan Crude Pipeline. The Partnership also owns a natural gasgathering system and a natural gas processing plant in Michigan.

 

**GulfCoast Business Unit**

 

•                 ***Javelina.***  On November 1, 2005, MarkWest EnergyPartners acquired 100% of the equity interests in Javelina Company, JavelinaPipeline Company and Javelina Land Company, L.L.C., which were owned 40%, 40%and 20%, respectively, by subsidiaries of El Paso Corporation, Kerr-McGeeCorporation, and Valero Energy Corporation. The Javelina entities own and operate a natural gas processing facilityin Corpus Christi, Texas, which treats and processes off-gas from six localrefineries.

 

•                 ***Starfish.***  On March 31, 2005, the Partnershipacquired a 50% non-operating ownership interest in Starfish Pipeline CompanyL.L.C. (“Starfish”), which operates, through its subsidiaries, certain GulfCoast offshore and onshore facilities. Starfish owns the FERC-regulatedStingray natural gas pipeline, and the unregulated Triton natural gas gatheringsystem and West Cameron dehydration facility. For external reporting purposes, we do not include Starfish informationin this segment.  However, managementincludes Starfish in its decision making and management of the Gulf CoastBusiness Unit.

 

# **RegulatoryMatters**

 

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

 

In many cases, various phases of our gas,liquids and crude oil operations in the states in which we operate are subjectto rate and service regulation. Applicable statutes generally require that ourrates, and terms and conditions of service, provide no more than a fair returnon the aggregate value of the facilities used to render services.

 

In general, the Federal Energy Regulatory Commission(“FERC”) has jurisdiction over natural gas pipelines and operators that providenatural gas pipeline transportation services in interstate commerce.   Section 1(b) of the Natural GasPolicy Act (“NGA”), however, exempts natural gas-gathering facilities from thejurisdiction of FERC. We own a number of natural gas pipelines that we haveevaluated, and concluded they meet the traditional tests FERC has used toestablish a pipeline’s status as a gatherer not subject to the agency’sjurisdiction.  Additionally, ourintrastate natural gas pipeline operations generally are not subject to rateregulation by FERC, although they are regulated by various agencies of thestates in which they are located, principally the Texas Railroad Commission, orTRRC.

 

MarkWest EnergyPartners’ Appalachian pipeline carries NGLs across state lines. The primaryshipper on the pipeline is MarkWest Hydrocarbon, which has entered intoagreements with the Partnership, providing for a fixed transportation chargefor the term of the agreements.  Theyexpire on December 31, 2015.  ThePartnership is the only other shipper on the pipeline. As the Company neitheroperates the Appalachian pipeline as a common carrier nor holds it 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.  The likelihood ofother entities seeking to utilize our Appalachian pipeline is remote, so itshould not be subject to regulation by the FERC in the future. We cannotprovide assurance, however, that FERC will not at some point determine thatsuch transportation is within its jurisdiction, or that such an assertion wouldnot adversely affect our results of operations. In such a case, we would berequired to file a tariff with FERC and provide a cost justification for thetransportation charge.  Regardless of anyFERC action, however, the Company has agreed to not challenge the status of theAppalachian pipeline or the transportation charge during the term of its agreements.With respect to the Company’s Michigan Crude Pipeline, in response to a shipperinquiry to the Federal Energy Regulatory Commission and following unsuccessfulFERC-requested rate structure discussions with the shippers, FERC recentlyrequested that we file a tariff.   Wefiled a tariff with the agency establishing a cost-of-service rate structure tobe effective starting January 1, 2006. Two shippers and a producer protested the filing.  The Company vigorously defended its tariff,and on December 29, 2005, the Commission rejected the protestors’ requestfor interim rates and accepted the filing. The new rate structure became effective January 1, 2006.  The Commission established hearing proceduresfor the tariff filing, but held them in abeyance pending the outcome ofFERC-sponsored settlement discussions, which the parties now have been referredto under the agency’s procedures.  TheCompany cannot predict whether the FERC tariff protest or any settlement willadversely affect its Michigan Crude Pipeline results of operations.

 

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# **EnvironmentalMatters**

#  

***MarkWestHydrocarbon***

 

We are subject to environmental risksnormally incidental to our operations and construction activities including,but not limited to, uncontrollable flows of natural gas, fluids and othersubstances into the environment, explosions, fires, pollution and otherenvironmental and safety risks.  Our business is subject to comprehensivestate and federal environmental regulations.  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 in environmental legislation andregulations is toward stricter standards, and this will likely continue in thefuture.

 

Our activities are subject to environmentaland safety regulation by federal and state authorities, including, withoutlimitation, the state environmental agencies and the federal EnvironmentalProtection Agency, which can increase the costs of designing, installing andoperating our facilities. In most instances, the regulatory requirements relateto the discharge of substances into the environment and include measures tocontrol water and air pollution.

 

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

 

***MarkWestEnergy Partners***

 

*General.*  The Partnership’s processing andfractionation plants, pipelines, and associated facilities are subject tomultiple environmental obligations and potential liabilities under a variety offederal, state and local laws and regulations. These include, without limitation: the Comprehensive EnvironmentalResponse, Compensation, and Liability Act; the Resource Conservation andRecovery Act; the Clean Air Act; the Federal Water Pollution Control Act or theClean Water Act; the Oil Pollution Act; and analogous state and local laws and regulations.  Such laws and regulations affect many aspectsof the Partnership’s present and future operations, and generally require it toobtain and comply with a wide variety of environmental registrations, licenses,permits, inspections and other approvals, with respect to air emissions, waterquality, wastewater discharges, and solid and hazardous waste management.  Failure to comply with these requirements mayexpose the Partnership to fines, penalties and/or interruptions in itsoperations that could influence its results of operations.  If an accidental leak, spill or release ofhazardous substances occurs at any facilities the Partnership owns, operates orotherwise uses, or where it sends materials for treatment or disposal, thePartnership 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.  ThePartnership could also be required to perform remedial operations to preventfuture contamination for properties owned, leased or acquired by it which mayhave been previously operated by third parties that may have released ordisposed of hazardous substances or wastes. Any or all of this could materially affect the Partnership’s results ofoperations and cash flows.

 

The Partnership believes that its operationsand facilities are in substantial compliance with applicable environmental lawsand regulations, and that the cost of compliance with such laws and regulationswill not have a material adverse effect on the Partnership’s results ofoperations or financial condition.  ThePartnership cannot ensure, however, that existing environmental regulationswill not be revised or that new regulations will not be adopted or becomeapplicable.  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 currentlyanticipate.  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 material adverse effect on its business, financialcondition, results of operations and cash flow.

 

*OngoingRemediation and Indemnification from a Third Party.* The previous owner/operator of the Partnership’s Boldman and Cobbfacilities has been, or is currently involved in, investigatory or remedialactivities with respect to the real property underlying these facilities.  These arise out of a September 1994 “AdministrativeOrder by Consent for Removal Actions” with EPA Regions II, III, IV, and V;and an “Agreed Order” entered into with the Kentucky Natural Resources andEnvironmental Protection Cabinet in October 1994.  The previous owner/operator has accepted soleliability and responsibility for, and indemnifies MarkWest Hydrocarbon against,any environmental liabilities associated with the EPA Administrative Order, theKentucky Agreed Order or any other environmental condition related to the realproperty prior to the effective dates of the Company’s lease or purchase of thereal property. In addition, the previous owner/operator has

 

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agreed to perform all therequired response actions at its expense in a manner that minimizesinterference with MarkWest Hydrocarbon’s use of the properties. On May 24,2002, the Company assigned to the Partnership the benefit of this indemnityfrom the previous owner/operator.  Todate, the previous owner/operator has been performing all actions requiredunder these agreements and, accordingly, we do not believe that the remediationobligation of these properties will have a material adverse impact on thePartnership’s financial condition or results of operations.

 

**Pipeline Safety Regulations**

 

The Company’s pipelines are subject toregulation by the U.S. Department of Transportation (“DOT”) under thePipeline Safety Act of 1992, as amended (“Pipeline Safety Act”), and theHazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”), as amended; and thePipeline Integrity Management (“PIM”) in High Consequence Areas (GasTransmission Pipelines) amendment to 49 CFR Part 192, effective February 14,2004, relating to the design, installation, testing, construction, operation,replacement and management of pipeline facilities. The Pipeline Safety Actrequires the Research and Special Programs Administration of the DOT to considerenvironmental impacts, as well as its traditional public safety mandate, whendeveloping pipeline safety regulations. The DOT’s pipeline operatorqualification rules require minimum qualification requirements forpersonnel performing operations and maintenance activities on hazardousliquid pipelines.  HLPSA covers crudeoil, carbon dioxide, NGL and petroleum products pipelines and requires anyentity which owns or operates pipeline facilities to comply with the regulationsunder HLPSA, to permit access to and allow copying of records and to makecertain reports and provide information as required by the Secretary ofTransportation. The Pipeline Integrity Management in High Consequence Areas(Gas Transmission Pipelines) amendment to 49 CFR Part 192 (PIM) requiresoperators of gas transmission pipelines to ensure the integrity of theirpipelines through hydrostatic pressure testing, the use of in-line inspectiontools or through risk-based direct assessment techniques.  While we believe that our pipeline operationsare in substantial compliance with applicable requirements, due to thepossibility of new or amended laws and regulations, or reinterpretation ofexisting laws and regulations, there can be no assurance that future compliancewith the requirements will not have a material adverse effect on our results ofoperations or financial positions.

 

On November 8, 2004, a leak and releaseof vapors occurred in a pipeline transporting NGLs from the Partnership’sMaytown gas processing 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 and injuriesto some of the residents.  Pursuant to aCorrective Action Order issued by the federal Office of Pipeline Safety (“OPS”)on November 18, 2004 and amended November 24, 2004, OPS requiredpipeline and valve integrity evaluation, testing and repair efforts, whichMarkWest successfully completed on the affected pipeline segment.  Based on, among other things, the successfulintegrity testing of the affected pipeline, OPS authorized a partial return toservice of the affected pipeline in October 2005.  The Partnership is currently preparing itsapplication for return to full service.

 

**Employee Safety**

 

The workplaces associated with the processingand storage facilities and the pipelines we operate are also subject tooversight from the federal Occupational Safety and Health Administration, (“OSHA”),as well as comparable state statutes that regulate the protection of the healthand safety of workers. In addition, the OSHA hazard-communication standardrequires that we maintain information about hazardous materials used orproduced in operations, and that this information be provided to employees,state and local government authorities, and citizens. We believe that we haveconducted our operations in substantial compliance with OSHA requirements,including general industry standards, record-keeping requirements andmonitoring of occupational exposure to regulated substances.

 

In general, we expect industry and regulatorysafety standards to become stricter over time, 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, 2005, we had 235employees, who operate the Partnership’s facilities and provide general andadministrative services. The Paper, Allied Industrial, Chemical and EnergyWorkers International Union Local 5-372 represents 15 employees at thePartnership’s Siloam fractionation facility in South Shore, Kentucky. Thecollective bargaining agreement with this Union was renewed on July 11,2005, for a term of three years. The agreement covers only hourly,non-supervisory employees. We consider labor relations to be satisfactory atthis time.

 

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**Available Information**

 

Our principal executive office is located at155 Inverness Drive West, Suite 200, Englewood, Colorado, 80112-5000. Ourtelephone number is 303-290-8700. Our common stock trades on the American StockExchange under the symbol “MWP.”  You canfind more information about us at our Internet website, www.markwest.com.  Our Annual Report on Form 10-K, ourQuarterly Reports on Form 10-Q, our current reports on Form 8-K andany amendments to those reports are available free of charge through ourinternet website as soon as reasonably practicable after we electronically fileor furnish such material with the Securities & Exchange Commission.

 

## **ITEM 1A**.                                            RISKFACTORS

## ** **

*In addition to theother information set forth elsewhere in this Form 10-K, you shouldcarefully consider the following factors when evaluating MarkWest Hydrocarbon.*

 

**Risks Inherent in Our Business**

 

***Weare highly dependent upon the earnings and distributions of MarkWest EnergyPartners.***

 

A significant decline in MarkWest EnergyPartners’ earnings and/or cash distributions would have a correspondingnegative impact on us.  For moreinformation on these earnings and cash distributions, please see MarkWestEnergy Partners’ 2005 Annual Report on Form 10-K.

 

***Ifwe are unable to successfully integrate the Partnership’s recent or futureacquisitions, our future financial performance may be negatively impacted.***

 

Our future growth will depend in part on ourability to integrate the Partnership’s recent acquisitions, as well as itsability to acquire additional assets and businesses at competitive prices.  The Partnership recently completed theStarfish and Javelina acquisitions, which geographically expanded itsoperations into offshore and onshore Gulf of Mexico operations.  We cannot assure you that the Partnershipwill successfully integrate these or any other acquisitions into itsoperations, or that the Partnership will achieve the desired profitability fromsuch acquisitions.  Failure to do socould adversely affect our financial condition and results of operations.

 

The integration of acquisitions with ourexisting business involves numerous risks, including:

 

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

•                  difficulties in the assimilation of the assets andoperations of the acquired businesses, especially if the assets acquired are ina new business segment or geographical area;

•                  the loss of customers or key employees from theacquired businesses;

•                  the diversion of management’s attention from otherbusiness concerns;

•                  the failure to realize expected synergies and costsavings;

•                  coordinating geographically disparate organizations,systems and facilities;

•                  integrating personnel from diverse businessbackgrounds and organizational cultures; and

•                  consolidating corporate and administrativefunctions.

 

Further, unexpected costs and challenges mayarise whenever businesses with different operations or management are combined,and we may experience unanticipated delays in realizing the benefits of anacquisition.  Following an acquisition,the Partnership may discover previously unknown liabilities subject to the samestringent environmental laws and regulations relating to releases of pollutantsinto the environment and environmental protection as the Partnership’s existingplants, pipelines and facilities.  If so,the Partnership’s operation of these new assets could cause us to incurincreased costs to attain or maintain compliance with such requirements.  If the Partnership consummates any futureacquisition, its capitalization and results of operation may changesignificantly, and you will not have the opportunity to evaluate the economic,financial and other relevant information that we will consider in determiningthe application of these funds and other resources.

 

The Partnership’s acquisition strategy isbased, in part, on our expectation of ongoing divestitures of assets within themidstream petroleum and natural gas industry. A material decrease in such divestitures could limit the Partnership’sopportunities for future acquisitions, and could adversely affect itsoperations and cash flows available for distribution to its unitholders.

 

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***Our commodity derivative activities may reduce our earnings,profitability and cash flows.***

 

Our operations expose us to fluctuations incommodity prices. We utilize derivative financial instruments related to thefuture price of natural gas and certain NGLs with the intent of reducingvolatility in our cash flows due to fluctuations in commodity prices.

 

We account for derivative instruments inaccordance with the provisions of Statement of Financial Accounting Standards(SFAS) No. 133, Accounting for Derivative Instruments and HedgingActivities.   The extent of our commodityprice exposure is related largely to the effectiveness and scope of our hedgingactivities. We have a policy to enter into derivative transactions related toonly a portion of the volume of our expected production or fuel requirementsand, as a result, we will continue to have direct commodity price exposure tothe unhedged portion. Please read “*Management’s Discussionand Analysis of Financial Condition and Results of Operations —Quantitative and Qualitative Disclosures about Market Risk.*”

 

Our actual future production or fuelrequirements may be significantly higher or lower than we estimate at the timewe enter into derivative transactions for such period. If the actual amount ishigher than we estimate, we will have greater commodity price exposure than weintended. If the actual amount is lower than the amount that is subject to ourderivative financial instruments, we might be forced to satisfy all or a portionof our derivative transactions without the benefit of the cash flow from oursale or purchase of the underlying physical commodity. As a result of thesefactors, our hedging activities may not be as effective as we intend inreducing the volatility of our cash flows, and in certain circumstances mayactually increase the volatility of our cash flows.

 

In addition, our hedging activities aresubject to the risks that a counterparty may not perform its obligation underthe applicable derivative instrument, the terms of the derivative instrumentsare imperfect, and our hedging policies and procedures are not properlyfollowed. It is possible that the steps we take to monitor our derivativefinancial instruments may not detect and prevent violations of our riskmanagement policies and procedures, particularly if deception or otherintentional misconduct is involved.

 

***Ourmanagement has discretion in conducting our risk management activities and maynot accurately predict future price fluctuations and therefore expose us tofinancial risks and reduce our opportunity to benefit from price increases.***

 

We evaluate our exposure to commodity pricerisk from an overall portfolio basis. Our management has discretion in determining whether and how to managethe commodity price risk associated with our physical and derivative positions.

 

To the extent that we do not manage thecommodity price risk relating to a position that is subject to commodity pricerisk, and commodity prices move adversely, we could suffer losses.  Such losses could be substantial, and couldadversely affect our financial condition and results of operations.

 

***Changesin commodity prices subject us to margin calls, which may adversely affect ourliquidity.***

 

Unfavorable commodity price changes may subjectus to margin calls that require us to provide cash collateral to ourcounterparties in amounts that may be material. Such funding requirements could exceed our ability to access our creditline or other sources of capital.  If weare unable to meet these margin calls with borrowings or cash on hand, we wouldbe forced to sell product to meet the margin calls, or to terminate thecorresponding futures contracts.  If weare forced to sell product to meet margin calls, we may have to sell product atprices that are not advantageous, which could adversely affect our financialcondition, results of operations and cash flows.

 

***ThePartnership’s substantial debt and other financial obligations could impair ourfinancial condition, results of operations and cash flows and our ability tofulfill our debt obligations.***

 

The Partnership has substantial indebtednessand other financial obligations.

 

Subject to the restrictions governing thePartnership’s indebtedness and other financial obligations, and the indenture governingour existing debt, the Partnership may incur significant additionalindebtedness and other financial obligations, which may be secured and/orstructurally senior to its existing debt.

 

The Partnership’s substantial indebtednessand other financial obligations could have important consequences.  For example, they could:

 

•                  make it more difficult for the Partnership tosatisfy its obligations with respect to its existing debt;

•                  impair the Partnership’s ability to obtainadditional financings in the future for working capital, capital expenditures,acquisitions, general corporate purposes or other purposes;

•                  have a material adverse effect on the Partnership ifit fails to comply with financial and restrictive covenants in the Partnership’sdebt agreements and an event of default occurs as a result of that failure thatis not cured or

 

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waived;

•                  require the Partnership to dedicate a substantialportion of its cash flow to payments on its indebtedness and other financialobligations, thereby reducing the availability of the Partnership’s cash flowto fund working capital, capital expenditures, distributions and other generalpartnership requirements;

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

•                  place the Partnership at a competitive disadvantagecompared to its competitors that have proportionately less debt.

 

These restrictions could limit thePartnership’s ability, and the ability of its subsidiaries, to obtain futurefinancings, make needed capital expenditures, withstand a future downturn inits business or the economy in general, conduct operations or otherwise takeadvantage of business opportunities that may arise.  The Partnership’s existing credit facilitycontains covenants requiring it to maintain specified financial ratios andsatisfy other financial conditions.  ThePartnership may be unable to meet those ratios and conditions.  Any future breach of any of these covenantsor the Partnership’s failure to meet any of these ratios or conditions couldresult in a default under the terms of the Partnership’s credit facility, whichcould result in acceleration of its debt and other financial obligations.  If the Partnership were unable to repay thoseamounts, the lenders could initiate a bankruptcy proceeding or liquidationproceeding or proceed against the collateral.

 

***Asignificant decrease in natural gas and refinery off-gas supplies in thePartnership’s areas of operation due to the decline in production from existingwells, refinery operations, depressed commodity prices, reduced drillingactivities or other factors otherwise could adversely affect our revenues andoperating income and cash flow.***

 

Our profitability is influenced by the volumeof natural gas the Partnership gathers, transmits and processes, and NGLs thePartnership transports and fractionates at its facilities.  A decrease in natural gas or refinery off-gassupplies in the Partnership’s areas of operation would result in a decline inthe volume of natural gas delivered to its pipelines and facilities forgathering, transporting and processing and NGLs delivered to its pipelines andfacilities for fractionation, storage, transportation and sales.  This would reduce the Partnership’s revenueand operating income.  Fluctuations inenergy prices can greatly affect production rates and investments by thirdparties in the development of new oil and natural gas reserves.  Drilling activity generally decreases as oiland natural gas prices decrease.  We haveno control over the level of drilling activity in the areas of operations, theamount of reserves underlying the wells and the “decline rate,” or the rate atwhich production from a well declines.  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 ofcapital.  Failure to connect new wells tothe Partnership’s gathering systems would, therefore, result in a reduction ofthe amount of natural gas it gathers, transmits and processes and the amount ofNGLs the Partnership transports and fractionates.  Over time upon exhaustion of the currentwells, this could cause the Partnership to abandon its gathering systems and,possibly, cease gathering operations.  Asa consequence of such declines, our revenues would decrease.

 

***Weare exposed to the credit risk of our customers and counterparties, and ageneral increase in the nonpayment and nonperformance by our customers couldreduce our revenues and cash flow.***

 

We are diligent in attempting to ensure thatwe issue credit to only credit-worthy customers. Even if our credit review andanalysis mechanisms work properly, however, we may experience losses in dealingwith operators and other parties. Any increase in the nonpayment andnonperformance by our customers could reduce our revenues and cash flow.

 

***ThePartnership may not be able to retain existing customers or acquire newcustomers, which would reduce its revenues and limit its future profitability.***

 

The renewal or replacement of existingcontracts with the Partnership’s customers at rates sufficient to maintaincurrent revenues and cash flows depends on a number of factors beyond itscontrol, including competition from other gatherers, processors, pipelines,fractionators, and the price of, and demand for, natural gas, NGLs and crudeoil in the markets we serve.  ThePartnership’s competitors include large oil, natural gas, refining andpetrochemical companies, some of which have greater financial resources, morenumerous or greater capacity pipelines, processing and other facilities, andgreater access to natural gas and NGL supplies than the Partnership does.  Additionally, the Partnership’s customersthat gather gas through facilities that are not otherwise dedicated to thePartnership may develop their own processing and fractionation facilities inlieu of using the Partnership’s services. Certain of the Partnership’s competitors may also have advantages incompeting for acquisitions, or other new business opportunities, because oftheir financial resources and synergies in operations.

 

As a consequence of the increase incompetition in the industry, and the volatility of natural gas prices,end-users

 

17

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and utilities are reluctant to enter into long-term purchase contracts.  Many end-users purchase natural gas from morethan one natural gas company and have the ability to change providers at anytime.  Some of these end-users also havethe ability to switch between gas and alternative fuels in response to relativeprice fluctuations in the market. Because there are numerous companies of greatly varying size andfinancial capacity that compete with the Partnership in the marketing ofnatural gas, the Partnership often competes in the end-user and utilitiesmarkets primarily on the basis of price. The inability of the Partnership’s management to renew or replace itscurrent contracts as they expire and to respond appropriately to changingmarket conditions could affect its profitability.

 

***Relativechanges in NGL product and natural gas prices may adversely impact our resultsdue to frac spread, natural gas and liquids exposure.***

 

We are exposed tofrac spread risk.  Under our keep-wholearrangements, our principal cost is delivering dry gas of an equivalent Btucontent to replace Btus extracted from the gas stream in the form of NGLs, orconsumed as fuel during processing.  The spread between the NGL productsales price and the purchase price of natural gas with an equivalent Btucontent is called the “frac spread.” Generally, the frac spread and, consequently, the net operating marginsare positive under these contracts.  Inthe event natural gas becomes more expensive on a Btu equivalent basis than NGLproducts, the cost of keeping the producer “whole” results in operating losses.

 

Dueto timing of gas purchases and liquid sales, direct exposure to either gas orliquids can be created because there is no longer an offsetting purchase orsale that remains exposed to market pricing. Through our marketing and derivatives activity, direct exposure mayoccur naturally or we may choose direct exposure to either gas or liquids whenwe favor that exposure over frac spread risk. Given that we have positions, adverse movement in prices to the positionswe have taken will negatively impact our results.

 

***Throughour interest in the Partnership, our profitability is affected by thevolatility of NGL product and natural gas prices.***

 

Crude oil, NGL products and natural gasprices have been volatile in recent years in response to relatively minorchanges in the supply and demand for NGL products and natural gas, marketuncertainty, and a variety of additional factors that are beyond our control,including:

 

•                                          the level of domestic oil, natural gas and NGLproduction;

•                                          imports of crude oil, natural gas and NGLs;

•                                          seasonality;

•                                          the condition of the U.S. economy;

•                                          political conditions in other oil-producing andnatural gas-producing countries; and

•                                          domestic government regulation, legislation andpolicies.

 

The net operating margins of the Partnershipunder its various types of commodity-based contracts are directly affected bychanges in NGL product prices and natural gas prices, and thus are moresensitive to volatility in commodity prices than its fee-based contracts.  Additionally, its purchase and resaleof gas in the ordinary course of business exposes it to significant risk with volatility in gas prices due to the potentialdifference in the time of the purchases and sales, and the existence of adifference in the gas price associated with each transaction.  The Partnership’s Javelina processingagreements are also potentially affected by the profitability of the NGLs andother products relative to the fuel value of the refinery off-gas stream.Finally, changes in natural gas prices may indirectly affect the Partnership’sprofitability, since prices can influence drilling activity and well operationsand, thus, the volume of gas it gathers and processes.  In the past, the prices of natural gas andNGLs have been extremely volatile, and we believe this volatility may continue.

 

***Wehave found material weaknesses in our internal controls that requireremediation and concluded, pursuant to Section 404 of the Sarbanes-OxleyAct of 2002, that our internal controls over financial reporting at December 31,2005, were not effective.***

 

As we discuss in our Management’s Report onInternal Control over Financial Reporting in Part II, Item 9A, “Controlsand Procedures,” of this Form 10-K, we have discovered deficiencies,including material weaknesses, in our internal controls over financialreporting as of December 31, 2005. In particular, we identified, and Deloitte & Touche’s auditreport on management’s assessment of the effectiveness of internal control overfinancial reporting and the effectiveness of internal control over financialreporting as of December 31, 2005 confirmed the presence of, thefollowing material weaknesses:

 

18

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•                  Ineffective control environment;and

 

•                  Risk management and accountingfor derivative financial instruments.

 

We are fully committed to remediating thematerial weaknesses described above, and we believe that we are taking thesteps that will properly address these issues.  Further, our AuditCommittee has been and expects to remain actively involved in the remediationplanning and implementation.  However, the remediation of the design ofthe deficient controls and the associated testing efforts are not complete, andfurther remediation may be required. While we are taking immediate steps and dedicating substantial resourcesto correct these material weaknesses, they will not be considered remediateduntil the new and improved internal controls operate for a period of time, aretested and are found to be operating effectively.  Pending the successful completion of suchtesting and the hiring of additional personnel, we will perform mitigatingprocedures.  If we fail to remediate anymaterial weaknesses, we could be unable to provide timely and reliablefinancial information, which could have a material adverse effect on ourbusiness, results of operations or financial condition.

 

***Weare subject to operating and litigation risks that may not be covered byinsurance.***

 

Our industry is subject to numerous operatinghazards and risks incidental to processing, transporting, fractionating andstoring natural gas and NGLs and to transporting and storing crude oil.  These include:

 

•                                          damage to pipelines, plants, related equipment andsurrounding properties caused by floods and other natural disasters;

•                                          inadvertent damage from construction and farmequipment;

•                                          leakage of crude oil, natural gas, NGLs and otherhydrocarbons;

•                                          fires and explosions; and

•                                          other hazards, including those associated withhigh-sulfur content, or sour gas that could also result in personal injury andloss of life, pollution and suspension of operations.

 

As a result, we may be the defendants invarious legal proceedings and litigation arising from our operations.  We may not be able to maintain or obtaininsurance of the type and amount we desire at reasonable rates.  Market conditions could cause certaininsurance premiums and deductibles to become unavailable, or available only forreduced amounts of coverage.  Forexample, insurance carriers now require broad exclusions for losses due to warrisk and terrorist acts.  If we were toincur a significant liability for which we were not fully insured, it couldhave a material adverse effect on our financial position.

 

***Transportationon certain of the Partnership’s pipelines may be subject to federal or staterate and service regulation, and the imposition and/or cost of compliance withsuch regulation could adversely affect our profitability.***

 

Some of the Partnership’s gas, liquids andcrude oil transmission operations may be subject to rate and serviceregulations under FERC, or various state regulatory bodies, depending uponjurisdiction.  FERC generally regulatesthe transportation of natural gas and oil in interstate commerce, and FERC’sregulatory authority includes: facilities construction, acquisition, extensionor abandonment of services or facilities; accounts and records; anddepreciation and amortization policies. Intrastate natural gas pipeline operations are generally not subject toregulation by FERC, and the Natural Gas Act (“NGA”) specifically exempts  some gathering systems.  Yet such operations may still be subject toregulation by various state agencies. The applicable statutes and regulations generally require that our ratesand terms and conditions of service provide no more than a fair return on theaggregate value of the facilities used to render services. FERC rate cases caninvolve complex and expensive proceedings. For more information regarding regulatory matters that could affect ourbusiness, please see Item 1, *Regulatory Matters.*

 

***ThePartnership is indemnified for liabilities arising from an ongoing remediationof property on which its facilities are located and its results of operationand its ability to make payments of principal and interest on its debt could beadversely affected if the indemnifying party fails to perform itsindemnification obligation.***

 

Columbia Gas is the previous or current ownerof the property on which the Partnership’s Kenova, Boldman, Cobb and Kermitfacilities are located, and is the previous operator of its Boldman and Cobbfacilities. Columbia Gas has been, or is currently, involved in investigatoryor remedial activities with respect to the real property underlying the Boldmanand Cobb facilities, pursuant to an “Administrative Order by Consent forRemoval Actions” entered into by Columbia Gas and the U.S. EnvironmentalProtection Agency and, in the case of the Boldman facility, an “Agreed Order”with the Kentucky Natural Resources and Environmental Protection Cabinet.

 

19

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Columbia Gas has agreed to retain soleliability and responsibility for, and to indemnify MarkWest Hydrocarbonagainst, any environmental liabilities associated with these regulatory ordersor the real property underlying these facilities to the extent such liabilitiesarose prior to the effective date of the agreements pursuant to which suchproperties were acquired or leased from Columbia Gas. At the closing of ourinitial public offering, MarkWest Hydrocarbon assigned us the benefit of itsindemnity from Columbia Gas with respect to the Cobb, Boldman and Kermitfacilities. While the Partnership is not a party to the agreement under whichColumbia Gas agreed to indemnify MarkWest Hydrocarbon with respect to theKenova facility, MarkWest Hydrocarbon has agreed to provide to the benefit ofits indemnity, as well as any other third party environmental indemnity ofwhich it is a beneficiary. MarkWest Hydrocarbon has also agreed to provide anadditional environmental indemnity pursuant to the terms of the OmnibusAgreement. The Company’s results of operation and ability to make cashdistributions could be adversely affected if, in the future, Columbia Gas failsto perform under the indemnification provisions of which the Company is thebeneficiary.

 

***Ourbusiness is subject to federal, state and local laws and regulations withrespect to environmental, safety and other regulatory matters, and theviolation of or the cost of compliance with such laws and regulations couldadversely affect our profitability.***

 

Numerous governmental agencies enforcecomplex and stringent laws and regulations on a wide range of environmental,safety and other regulatory matters.  Wecould be adversely affected by increased costs due to stricterpollution-control requirements or liabilities resulting from non-compliancewith operating or other regulatory permits. New environmental laws and regulations might adversely influence ourproducts and activities.  Federal, stateand local agencies also could impose additional safety requirements, any ofwhich could affect our profitability.  Inaddition, we face the risk of accidental releases or spills associated with ouroperations. These could result in material costs and liabilities, includingthose relating to claims for damages to property and persons.  Our failure to comply with environmental orsafety-related laws and regulations could result in administrative, civil andcriminal penalties, the imposition of investigatory and remedial obligationsand even injunctions that restrict or prohibit our operations.  For more information regarding theenvironmental, safety and other regulatory matters that could affect ourbusiness, please see Item 1, *Regulatory Matters andEnvironmental Matters*.

 

***MarkWest Energy Partners may not be able tosuccessfully execute its business plan and may not be able to grow itsbusiness, which could adversely affect the value of our investment in thelimited partner units and the general partnership interests in MarkWest EnergyPartners.***

 

MarkWest Energy Partners’ ability tosuccessfully operate its business, generate sufficient cash to pay the minimumquarterly cash distributions to its unitholders, and to allow for growth, issubject to a number of risks and uncertainty. Similarly, MarkWest Energy Partners may not be able to successfullyexpand its business through acquiring or growing its assets, because of variousfactors, including economic and competitive factors beyond its control.  If MarkWest Energy Partners is unable to growits business, or execute on its business plan, the market price of the commonunits is likely to decline, causing the limited partner units and the generalpartner interest we hold in MarkWest Energy Partners to also decline in value.

 

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

 

The Partnership’s operations depend upon theinfrastructure that it has developed, including processing and fractionationplants, storage facilities, and various means of transportation. Anysignificant interruption at these facilities or pipelines, or the Partnership’sinability to transmit natural gas or NGLs, or transport crude oil to or fromthese facilities or pipelines for any reason, would adversely affect ourresults of operations and cash flows. Operations at the Partnership’sfacilities could be partially or completely shut down, temporarily orpermanently, as the result of circumstances not within its control, such as:

 

•                                          unscheduled turnarounds orcatastrophic events at our physical plants;

 

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

 

•                                          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 businesses would reducethe Partnership’s ability to make distributions to its unitholders.***

 

20

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We rely on the revenues generated from thePartnership’s gathering, processing, transportation, transmission,fractionation and storage businesses.  Anadverse development in one of these businesses would have a significantlygreater impact on our financial condition and results of operations than if wemaintained more diverse assets.

 

***Thetax treatment of MarkWest Energy Partners depends upon its status as apartnership for federal income tax purposes, as well as it not being subject toentity-level taxation by states.  If theInternal Revenue Service were to treat MarkWest Energy Partners as acorporation, or if it were to become subject to entity-level taxation for statetax purposes, then its cash available for distribution would be significantlyreduced.***

 

Weown limited partner units representing approximately 19% of the limitedpartnership interests in MarkWest Energy Partners, in addition to a 2% generalpartnership interest.  The anticipatedafter-tax benefit of an investment in the limited partner units of MarkWestEnergy Partners depends largely on MarkWest Energy Partners being treated as apartnership for federal income tax purposes.

 

IfMarkWest Energy Partners were treated as a corporation for federal income taxpurposes, it would pay federal income tax on its income at the corporate taxrate, which is currently a maximum of 35%. Cash distributions to the holders of limited partnership interests,including the subordinated units we hold and the common units held by thepublic, would generally be taxed again as corporate distributions, and no income,gains, losses, deductions or credits would flow through to the holders of thelimited partnership interests to shelter a substantial portion of suchdistributions from state and federal income taxes.  Because a tax would be imposed upon MarkWestEnergy Partners as a corporation, its cash available for distribution tolimited partners would be significantly reduced.  Thus, treatment of MarkWest Energy Partnersas a corporation would result in a material reduction in the anticipated cashflow and after-tax return to its owners, including us, as a holder of thelimited partner units, likely causing a significant reduction in the value ofthe market price of the common units.

 

***Ashortage of skilled labor may make it difficult for us to maintain laborproductivity, and competitive costs and could adversely affect ourprofitability.***

 

ThePartnership’s operations require skilled and experienced laborers withproficiency in multiple tasks. In recent years, a shortage of workers trainedin various skills associated with the midstream energy business has caused usto conduct certain operations without full staff, which decreases ourproductivity and increases our costs. This shortage of trained workers is theresult of the previous generation’s experienced workers reaching the age forretirement, combined with the difficulty of attracting new laborers to themidstream energy industry. Thus, this shortage of skilled labor could continueover an extended period. If the shortage of experienced labor continues orworsens, it could have an adverse impact on our labor productivity and costsand our ability to expand production in the event there is an increase in thedemand for our products and services, which could adversely affect ourprofitability.

 

## **ITEM 1B.**                                            UNRESOLVEDSTAFF COMMENTS

 

None.

 

## **ITEM 2.**                                                     PROPERTIES

 

***MarkWest******HydrocarbonStandalone***

 

MarkWest Hydrocarbon has minimal properties,since discontinuing its exploration and production business in 2003, andtransferring its natural gas gathering and processing, and NGL transportation,fractionation and storage assets to MarkWest Energy Partners in 2002.  At December 31, 2004 and 2003, we had agross interest (a well in which a working interest is owned) in 3 wells, with acorresponding net interest (one net well is deemed to exist when the sum of thefractional ownership working interest in gross wells equals one producing well)in 0.62 wells.  We had no interest indrilling and recompletion activity in 2005 or 2004.  As of December 31, 2003, we had a grossinterest in 94 wells, with a corresponding net interest in 69.8 wells,primarily for natural gas.

 

***MarkWestEnergy Partners’ Assets***

 

**Thelocations and  approximate throughputcapacity of MarkWest Energy Partners’ gas processing plants as of and for theyear ended December 31, 2005, are as follows:**

 

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**Gas Processing Facilities:**

 
| ** **                    | ** ** | ** **          | ** ** | ** **                       | ** ** | ** **                       | ** ** | **Year Ended December 31, 2005** | ** ** |
|-------------------------------|------------|---------------------|------------|----------------------------------|------------|----------------------------------|------------|---------------------------------------|------------|
| **Facility**                  | ** ** | **Location**        | ** ** | **Year of Initial Construction** | ** ** | **Design  Throughput  Capacity** | ** ** | **Natural Gas  Throughput**           | ** ** | **Utilization of  Design  Capacity** | ** ** | **NGL  Throughput** | ** ** |
| ** **                    | ** ** | ** **          | ** ** | ** **                       | ** ** | **(Mcf/d)**                      | ** ** | **(Mcf/d)**                           | ** ** | ** ** | ** ** | **(gal/day)** | ** ** |
| **East Texas:**               |       |                |       |                             |       |                             |       |                                  |       |   |   |   |   |
| East Texas processing plant   |       | Panola, County, TX  |       | 2005                             |       | 200,000                          |       | NA                                    |       | NA |   | NA |   |
|                          |       |                |       |                             |       |                             |       |                                  |       |   |   |   |   |
| **Western Oklahoma:**         |       |                |       |                             |       |                             |       |                                  |       |   |   |   |   |
| Arapaho processing plant      |       | Custer County, OK   |       | 2000                             |       | 90,000                           |       | 76,000                                |       | 84 | % | 167,000 |   |
|                          |       |                |       |                             |       |                             |       |                                  |       |   |   |   |   |
| **Appalachia:**               |       |                |       |                             |       |                             |       |                                  |       |   |   |   |   |
| Kenova Processing Plant (1)   |       | Wayne County, WV    |       | 1996                             |       | 160,000                          |       | 131,000                               |       | 82 | % | NA |   |
| Boldman Processing Plant (1)  |       | Pike County, KY     |       | 1991                             |       | 70,000                           |       | 43,000                                |       | 61 | % | NA |   |
| Maytown Processing Plant      |       | Floyd County, KY    |       | 2000                             |       | 55,000                           |       | 63,000                                |       | 115 | % | NA |   |
| Cobb Processing Plant         |       | Kanawha County, WV  |       | 2005                             |       | 25,000                           |       | 24,000                                |       | 96 | % | NA |   |
| Kermit Processing Plant (2)   |       | Mingo County, WV    |       | 2001                             |       | 32,000                           |       | NA                                    |       | NA |   | NA |   |
|                          |       |                |       |                             |       |                             |       |                                  |       |   |   |   |   |
| **Michigan:**                 |       |                |       |                             |       |                             |       |                                  |       |   |   |   |   |
| Fisk Processing Plant         |       | Manistee County, MI |       | 1998                             |       | 35,000                           |       | 6,600                                 |       | 19 | % | 16,000 |   |
|                          |       |                |       |                             |       |                             |       |                                  |       |   |   |   |   |
| **Gulf Coast:**               |       |                |       |                             |       |                             |       |                                  |       |   |   |   |   |
| Javelina processing plant (3) |       | Corpus Christi, TX  |       | 1989                             |       | 142,000                          |       | 102,000                               |       | 72 | % | 22,100 |   |

 

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(1)          A portion of the gas processed at Maytown andBoldman plants, and all of the gas processed at Kermit plant, is furtherprocessed at Kenova plant to recover additional NGLs.

(2)          The Kermit processing plant is operated by athird party solely to prevent liquids from condensing in the gathering andtransmission pipelines upstream of MarkWest Energy Partners’ Kenova plant. ThePartnership does not receive Kermit gas volume information but does receive allof the liquids produced at the Kermit facility.

(3)          MarkWest Energy Partners acquired the Javelinaprocessing plant on November 1, 2005.

 

The location, approximate capacity, andthroughput of MarkWest Energy Partners’ fractionation facility as of and forthe year ended December 31, 2005, is as follows:

 

**Fractionation Facility:**

 
| ** **                 | ** ** | ** **       | ** ** | ** **                        | ** ** | ** **                               | ** ** | **Year Ended  December 31, 2005** | ** ** |
|----------------------------|------------|------------------|------------|-----------------------------------|------------|------------------------------------------|------------|-----------------------------------|------------|
| **Facility**               | ** ** | **Location**     | ** ** | **Year of Initial  Construction** | ** ** | **Design  Throughput  Capacity (gal/d)** | ** ** | **NGL  Throughput  (gal/day)**    | ** ** | **Utilization of  Design  Capacity** | ** ** |
| ** **                 | ** ** | ** **       | ** ** | ** **                        | ** ** | ** **                               | ** ** | ** **                        | ** ** | ** ** | ** ** |
| **Appalachia:**            | ** ** | ** **       | ** ** | ** **                        | ** ** | ** **                               | ** ** | ** **                        | ** ** | ** ** | ** ** |
| Siloam fractionation plant |       | South Shore,  KY |       | 1957                              |       | 600,000                                  |       | 430,000                           |       | 72 | % |

 

Thename, approximate length in miles, geographical location, and throughput ofMarkWest Energy Partners’ pipelines as of and for the year ended December 31,2005, are as follows:

 

**Natural Gas Pipelines:**

 
| ** **                      | ** ** | ** **                              | ** ** | ** ** | ** ** | ** **                         | ** ** | **Year Ended December 31, 2005** | ** ** | ** **                   | ** ** |
|---------------------------------|------------|-----------------------------------------|------------|------------|------------|------------------------------------|------------|----------------------------------|------------|------------------------------|------------|
| **Facility**                    | ** ** | **Location**                            | ** ** | **Miles**  | ** ** | **Year of  Initial  Construction** | ** ** | **Design  Throughput  Capacity** | ** ** | **Natural  Gas  Throughput** | ** ** | **Utilization  of  Design  Capacity** | ** ** | **NGL  Throughput** | ** ** |
| ** **                      | ** ** | ** **                              | ** ** | ** ** | ** ** | ** **                         | ** ** | **(Mcf/d)**                      | ** ** | **(Mcf/d)**                  | ** ** | ** ** | ** ** | **(gal/day)** | ** ** |
| **East  Texas:**                |       |                                    |       |       |       |                               |       |                             |       |                         |       |   |   |   |   |
| East Texas  gathering system    |       | Panola County, TX                       |       | 311        |       | 1990                               |       | 350,000                          |       | 321,000                      |       | 92 | % | NA |   |
|                            |       |                                    |       |       |       |                               |       |                             |       |                         |       |   |   |   |   |
| **Western  Oklahoma:**          |       |                                    |       |       |       |                               |       |                             |       |                         |       |   |   |   |   |
| Foss Lake  Gathering System     |       | Roger Mills and Custer County, OK       |       | 240        |       | 1998                               |       | 90,000                           |       | 76,000                       |       | 84 | % | NA |   |
|                            |       |                                    |       |       |       |                               |       |                             |       |                         |       |   |   |   |   |
| **Other  Southwest:**           |       |                                    |       |       |       |                               |       |                             |       |                         |       |   |   |   |   |
| Appleby Gathering  System       |       | Nacogdoches County, TX                  |       | 139        |       | 1990                               |       | 40,000                           |       | 33,000                       |       | 83 | % | NA |   |
| Other Gathering  Systems (4)    |       | Various                                 |       |       |       |                               |       | 52,570                           |       | 16,500                       |       | 31 | % | NA |   |
|                            |       |                                    |       |       |       |                               |       |                             |       |                         |       |   |   |   |   |
| **Michigan:**                   |       |                                    |       |       |       |                               |       |                             |       |                         |       |   |   |   |   |
| 90-mile Gas  Gathering Pipeline |       | Manistee, Mason and Oceana Counties, MI |       | 90         |       | 1994 -1998                         |       | 35,000                           |       | 6,600                        |       | 19 | % | 15,600 |   |

 

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(4)   MarkWest Energy Partners acquired theAppleby gathering system, along with 20 other gathering systems, as part of itsMarch 28, 2003 Pinnacle acquisition.

 

### ***NGL Pipelines:***

 
| ** **               | ** ** | ** **                              | ** ** | ** ** | ** ** | ** **                        | ** ** | **Year  Ended December 31, 2005** | ** ** |
|--------------------------|------------|-----------------------------------------|------------|------------|------------|-----------------------------------|------------|----------------------------------------|------------|
| **Pipeline**             | ** ** | **Location**                            | ** ** | **Miles**  | ** ** | **Year of Initial  Construction** | ** ** | **Design  Throughput  Capacity**       | ** ** | **NGL  Throughput** | ** ** | **Utilization of  Design  Capacity** | ** ** |
| ** **               | ** ** | ** **                              | ** ** | ** ** | ** ** | ** **                        | ** ** | **(gal/day)**                          | ** ** | **(gal/day)** | ** ** | ** ** | ** ** |
| **Appalachia:**          |       |                                    |       |       |       |                              |       |                                   |       |   |   |   |   |
| Maytown to Institute (5) |       | Floyd  County, KY to Kanawha County, WV |       | 100        |       | 1956                              |       | 250,000                                |       | 120,000 |   | 48 | % |
| Ranger to Kenova (6)     |       | Lincoln  County, WV to Wayne County, WV |       | 40         |       | 1976                              |       | 831,000                                |       | 120,000 |   | 14 | % |
| Kenova to Siloam         |       | Wayne  County, WV to South Shore, KY    |       | 40         |       | 1957                              |       | 831,000                                |       | 273,000 |   | 33 | % |
|                     |       |                                    |       |       |       |                              |       |                                   |       |   |   |   |   |
| **East Texas:**          | ** ** | ** **                              | ** ** | ** ** | ** ** | ** **                        | ** ** | ** **                             | ** ** | ** ** | ** ** | ** ** | ** ** |
| E. Texas Liquidline      |       | Panola County,  Texas                   |       | 37.5       |       | 2005                              |       | 630,000                                |       | — |   | NA |   |

 

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(5)          Includes 40 miles of currently unused pipelineextending from Ranger to Institute.

(6)          NGLs transported through the Ranger to Kenovapipeline are combined with NGLs recovered at the Kenova facility and thecombined NGL stream is transported in the Kenova to Siloam pipeline to Siloam.

 

### ***Michigan Crude Pipeline :***

 
| **Pipeline**             | ** ** | **Location**                                | ** ** | **Miles**  | ** ** | **Design  Throughput  Capacity (gal/day)** | ** ** | **Year Ended December 31, 2005** | ** ** |
|--------------------------|------------|---------------------------------------------|------------|------------|------------|--------------------------------------------|------------|---------------------------------------|------------|
| **NGL**                  | ** ** | **Utilization of**                          | ** ** |
| **Throughput (gal/day)** | ** ** | **Design Capacity**                         | ** ** |
| ** **               | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** **                                 | ** ** | ** **                            | ** ** | ** ** | ** ** |
| **Michigan:**            |       |                                        |       |       |       |                                       |       |                                  |       |   |   |
| Michigan Crude Pipeline  |       | Manistee  County, MI to Crawford County, MI |       | 150        |       | 60,000                                     |       | 14,200                                |       | 24 | % |

 

**Title to Properties**

 

We believe the Company has satisfactory titleto all of its assets.

 

## **ITEM 3.  LEGAL PROCEEDINGS**

 

The Company, in the ordinary course ofbusiness, is subject to a variety of risks and disputes normallyincident to its business, a defendant in various lawsuits and a party tovarious other legal proceedings.  We maintain insurance policies with insurersin amounts and with coverage and deductibles as we believe are reasonable andprudent. We cannot assure, however, that the insurance companies will promptlyhonor their policy obligations or that the coverage or levels of insurance willbe adequate to protect us from all material expenses related to potentialfuture claims for property loss or business interruption to the Company or forthird party claims of personal and property damage, or that the coverage orlevels of insurance it presently has will be available in the future ateconomical prices.

 

In early 2005, the Company and several of itsaffiliates, including MarkWest Energy Partners, were served with two lawsuits, RickyJ. Conn, *et al.* v. MarkWestHydrocarbon, Inc. *et al*.(filedFebruary 7, 2005),*. and*Charles C. Reid, *et al.* v.MarkWest Hydrocarbon, Inc. *et al.*,(filed February 8, 2005),  presentlyremoved to and under the jurisdiction of the U.S. District Court for theEastern District of Kentucky, Pikeville Division.  The Company, the Partnership and several ofits

 

23

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affiliates were served with anadditional lawsuit, Community Trust and Investment Co., *et al.* v. MarkWest Hydrocarbon, Inc. *et al.*, filed November 7, 2005 inFloyd County Circuit Court, Kentucky, that added five new claimants butessentially alleged the same facts and claims as the earlier two suits. Theseactions are for third-party claims of property and personal injury damagessustained as a consequence of an NGL pipeline leak and an ensuing explosion andfire that occurred on November 8, 2004. The pipeline was owned by an unrelated business entity and leased andoperated by the Partnership’s subsidiary, MarkWest Energy Appalachia, LLC.  It transports NGLs from the Maytown gasprocessing plant to the Partnership’s Siloam fractionator.  The fire from the leaked vapors resulted inproperty damage to five homes and injuries to some of the residents.  The pipeline owner, the U.S. Department ofTransportation, Office of Pipeline Safety (“OPS”), and the Company continue toinvestigate the incident.

 

The Company notified its general liabilityinsurance carriers of the incident and of the filed Kentucky actions in atimely manner and is coordinating the defense of these third-party lawsuitswith the insurers.  At this time, theCompany believes that it has adequate general liability insurance coverage forthird-party property damage and personal injury liability resulting from theincident.  To date, the Partnership hassettled with several of the claimants for third-party property damage claims(damage to residences and personal property), in addition to reachingsettlement for some of the personal injury claims.  These settlements have been paid for orreimbursed under the Partnership’s general liability insurance.   As a result, the Company has not providedfor a loss contingency.

 

Pursuant to OPS regulation mandates and to aCorrective Action Order issued by the OPS on November 18, 2004, pipelineand valve integrity evaluation, testing and repairs were conducted on theaffected pipeline segment before service could be resumed.  Based on, among other things, the successfulintegrity testing of the affected pipeline, OPS authorized a partial return toservice of the affected pipeline in October 2005.  MarkWest is currently preparing itsapplication for return to full service.

 

The Company has filed an independent actioncaptioned MarkWest Hydrocarbon, Inc., *etal*. v. Liberty Mutual Ins. Co., *etal*.  (District Court,Arapahoe County, Colorado, Case No. 05CV3953 filed August 12, 2005)),as removed to the U.S. District Court for the District of Colorado, CivilAction No. 1:05-CV-1948, on October 7, 2005), against its All-RisksProperty and Business Interruption insurance carriers as a result of theinsurance companies’ refusal to honor their insurance coverage obligation topay the Company for certain expenses. These include the Company’s internal expenses and costs incurred fordamage to, and loss of use of the pipeline, equipment, products, the extratransportation costs incurred for transporting the liquids while the pipelinewas out of service, the reduced volumes of liquids that could be processed, andthe costs of complying with the OPS Corrective Action Order (hydrostatictesting, repair/replacement and other pipeline integrity assurance measures).These expenses and costs have been expensed as incurred and any potentialrecovery from the All-Risks Property and Business Interruption insurancecarriers will be treated as “other income” if and when they are received.  The Company has not provided for a receivablefor these claims because of the uncertainty as to whether and how much theCompany will ultimately recover under these policies. The Company has alsoasserted that the cost of pipeline testing, replacement and repair are subjectto an equitable sharing arrangement with the pipeline owner, pursuant to the termsof the pipeline lease agreement.

 

The Company has also been involved in a lawsuitcaptioned *Ross Bros. Construction v.MarkWest Hydrocarbon, Inc.*, (U.S. Court of Appealsfor the 6th Circuit, Case No. 05-6251, appealed from U.S. District Court Eastern District ofKentucky, Ashland Division, Civ. Action No. 01-CV-205). The underlyinglawsuit involved the construction of the Siloam, Kentucky, plant and a disputeas to the monetary value of additional work beyond the contract’s lump sumprice performed by the contractor.  Thelawsuit involved a claim of approximately $0.7 million in extra costs. TheCompany was granted Summary Judgment on its defense asserting accord andsatisfaction. In August 2005, Plaintiffs filed an appeal of the SummaryJudgment to the U.S. Court of Appeals for the 6th Circuit. The Company believes that, while it is not able topredict the outcome of this matter, based on the judge’s discussion on thegrant of the summary judgment and denial of Ross Brothers’ motion forreconsideration, it is probable that the Company will prevail in the appeal. Asa result, the Company has not provided for a loss contingency.

 

The Company has also been involved in an arbitrationproceeding captioned *Kevin Stowe andScott Daves v. MarkWest Hydrocarbon, Inc.*, AmericanArbitration Association arbitration, Case No. 77 168 Y 0052 05 BEAH,Denver, Colorado, 2005. Claimants in this Arbitration had filed a proceedingagainst the Company seeking further payments out of a dispute and settlementover interests in certain wells in Colorado. On February 8, 2006, theCompany was granted Summary Judgment and the Arbitration was accordinglydismissed.

 

24

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## **ITEM 4.  SUBMISSION OF MATTERS TO AVOTE OF SECURITY HOLDERS**

 

At the Annual Meeting of Stockholders held onDecember 28, 2005, the stockholders of the Company elected the followingnominees to the Board of Directors until the next annual stockholder meeting oruntil their successors are qualified, with votes cast as follows:

 

| ** **            | ** ** | **Number of votes** | ** ** |
|-----------------------|------------|---------------------|------------|
| **Director Nominees** | ** ** | **For**             | ** ** | **Authority  Withheld** | ** ** |
| John M. Fox           |       | 9,270,765           |       | 808,759 |   |
| Frank M. Semple       |       | 9,443,281           |       | 636,243 |   |
| Donald D. Wolf        |       | 10,003,083          |       | 76,441 |   |

 

There were no abstentions or broker non-votesapplicable to the election of directors.

 

The stockholders approved certainamendments to the 1996 Stock Incentive Plan (the “Plan”) to includenon-employee directors as eligible participants under the Plan and to minimizethe potential application of additional taxes imposed on any Awards grantedunder the Plan as a result of recent changes in the US Tax Code Section 409.

 

| For:       |   | 6,927,490 |   |
|------------|--------|-----------|--------|
| Against:   |   | 124,641   |   |
| Abstained: |   | 25,602    |   |

 

The stockholders ratified the appointment ofDeloitte & Touche, LLP as independent auditors of MarkWest Hydrocarbon, Inc.for the 2005 fiscal year, with votes cast as follows:

 

| For:       |   | 10,050,586 |   |
|------------|--------|------------|--------|
| Against:   |   | 5,395      |   |
| Abstained: |   | 23,543     |   |

 

Abstentions had the effect of votes “against”this proposal. Broker non-votes were not counted as votes “for” or “against”this proposal and therefore had no impact on the outcome.

 

25

----

 

## **ITEM 5.**  MARKETFOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

 

Our common stock trades on the American Stock Exchange (“AMEX”)national market under the symbol “MWP.”  As of January 31, 2006, therewere 10,802,488 shares of common stock outstanding held by approximately 44holders of record. The following table sets forth quarterly high and low salesprices as reported by the American Stock Exchange, as retroactively restated togive effect 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 2005 and 2004.

 
| **Quarter Ended**        | ** ** | **High** | ** ** | **Low** | ** ** | **Dividend** | ** ** | **Record Date** | ** ** | **Payment Date** | ** **              |
|--------------------------|------------|----------|------------|---------|------------|--------------|------------|-----------------|------------|------------------|-------------------------|
|                     |       |     |       |    |       |         |       |            |       |             |                    |
| December 31,  2005  |       | $        | 25.49      |    | $          | 21.05        |       | $               | 0.125      |             | February 15,  2006 |   | February 22,  2006 |   |
| September 30,  2005 |       | $        | 26.95      |    | $          | 22.05        |       | $               | 0.125      |             | November 15,  2005 |   | November 22,  2005 |   |
| June 30,  2005      |       | $        | 24.99      |    | $          | 19.85        |       | $               | 0.100      |             | August 15,  2005   |   | August 22,  2005 |   |
| March 31,  2005     |       | $        | 24.24      |    | $          | 17.17        |       | $               | 0.100      |             | May 16,  2005      |   | May 23,  2005 |   |
|                     |       |     |       |    |       |         |       |            |       |             |                    |
| December 31,  2004  |       | $        | 18.18      |    | $          | 13.86        |       | $               | 0.075      |             | February 9,  2005  |   | February 21,  2005 |   |
| September 30,  2004 |       | $        | 13.92      |    | $          | 10.45        |       | $               | 0.050      |             | 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 |   |

 

**DividendPolicy**

 

The Company does nothave a formal dividend policy. The Company’s objective, however, is to maintaina regular quarterly dividend.  Payment of dividends in the future willdepend on our earnings, financial condition and contractual restrictions,including those under our bank line of credit or imposed by law and otherfactors deemed relevant by our Board of Directors.

 

**SpecialCash Dividend**

 

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

 

**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 onNovember 9, 2004.  The stock dividend was paid on November 19,2004, with an ex-dividend date of November 5, 2004.

 

OnJuly 10, 2003, the Board of Directors declared a stock dividend of one sharefor each ten shares owned by stockholders of record as of the close of businessJuly 31, 2003.  The stock dividend waspaid on August 11, 2003, with an ex-dividend date of July 29, 2003.

 

26

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**ITEM 6. SELECTED FINANCIAL DATA**

 

The following table sets forth selected consolidated historicalfinancial and operating data for MarkWest Hydrocarbon.  The selectedfinancial information for the Company, as of and for the years endedDecember 31, 2005, 2004 and 2003, is derived from our audited ConsolidatedFinancial Statements included in Item 8 in this Form 10-K.  Theselected consolidated statement of operations and balance sheet data set forthbelow, as of and for the years ended December 31, 2002 and 2001, have beenderived from audited financial statements not included in this Form 10-K.  The selected financial data should be read inconjunction with the combined and consolidated financial statements, includingthe notes thereto, and Item 7, “Management’s Discussion and Analysis ofFinancial Condition and Results of Operations.”

 
|                                                                                             |       | **Year Ended  December 31,**                                |       |
|--------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------|------------|
|                                                                                             |       | **2005**                                                         |       | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** |   |
| ** **                                                                                       | ** ** | **(1)**                                                          | ** ** | **(2)** | ** ** | **(3)** | ** ** | ** ** | ** ** | ** ** | ** ** |
|                                                                                             |       | **(in  thousands, except per share amounts and operating data)** |       |
| ** **                                                                                       |       |                                                             |       |   |   |   |   |   |   |   |   |
| **Statement of Operations:**                                                                     |       |                                                             |       |   |   |   |   |   |   |   |   |
| Revenues                                                                                         |       | $                                                                | 714,177    |   | $ | 460,113 |   | $ | 209,268 |   | $ | 155,787 |   | $ | 173,890 |   |
| Operating expenses:                                                                              |       |                                                             |       |   |   |   |   |   |   |   |   |
| Purchased product costs                                                                          |       | 583,084                                                          |       | 363,261 |   | 187,544 |   | 127,526 |   | 140,225 |   |
| Facility expenses                                                                                |       | 45,577                                                           |       | 28,580 |   | 20,957 |   | 17,145 |   | 16,522 |   |
| Selling, general and administrative                                                              |       | 33,350                                                           |       | 28,132 |   | 15,865 |   | 9,614 |   | 7,502 |   |
| Depreciation                                                                                     |       | 20,829                                                           |       | 16,895 |   | 8,795 |   | 6,016 |   | 5,156 |   |
| Amortization of intangible assets                                                                |       | 9,656                                                            |       | 3,640 |   | — |   | — |   | — |   |
| Accretion of asset retirement obligation                                                         |       | 160                                                              |       | 15 |   | — |   | — |   | — |   |
| Impairments                                                                                      |       | —                                                           |       | 130 |   | 2,187 |   | — |   | — |   |
| Total operating expenses                                                                         |       | 692,656                                                          |       | 440,653 |   | 235,348 |   | 160,301 |   | 169,405 |   |
| Income (loss) from operations                                                                    |       | 21,521                                                           |       | 19,460 |   | (26,080 | ) | (4,514 | ) | 4,485 |   |
|                                                                                             |       |                                                             |       |   |   |   |   |   |   |   |   |
| Loss from unconsolidated affiliates                                                              |       | (2,153                                                           | )          | — |   | — |   |   |   |   |   |
| Interest income                                                                                  |       | 1,060                                                            |       | 647 |   | 106 |   | 65 |   | (3,700 | ) |
| Interest expense                                                                                 |       | (22,622                                                          | )          | (9,383 | ) | (4,347 | ) | (2,474 | ) | — |   |
| Amortization of deferred financing costs                                                         |       | (6,979                                                           | )          | (5,281 | ) | (2,104 | ) | (4,343 | ) | — |   |
| Gain on sale of non-operating assets                                                             |       | —                                                           |       | — |   | — |   | 5,454 |   | — |   |
| Dividend                                                                                         |       | 392                                                              |       | 259 |   | — |   | — |   | — |   |
| Miscellaneous income (expense)                                                                   |       | 266                                                              |       | 788 |   | (92 | ) | (73 | ) | (231 | ) |
| Income (loss) before income taxes                                                                |       | (8,515                                                           | )          | 6,490 |   | (32,517 | ) | (5,885 | ) | 554 |   |
|                                                                                             |       |                                                             |       |   |   |   |   |   |   |   |   |
| Income tax (expense) benefit                                                                     |       | 1,804                                                            |       | (78 | )  | 13,085 |   | 3,057 |   | (239 | ) |
| Non-controlling interest in net income of  consolidated subsidiary                               |       | (91                                                              | )          | (7,315 | ) | (2,988 | ) | (1,947 | ) | — |   |
| Income (loss) from continuing operations                                                         |       | (6,802                                                           | )          | (903 | ) | (22,420 | ) | (4,775 | ) | 315 |   |
|                                                                                             |       |                                                             |       |   |   |   |   |   |   |   |   |
| Income from discontinued operations                                                              |       | —                                                           |       | — |   | 11,443 |   | 1,766 |   | 2,495 |   |
| Income (loss) before cumulative effect of  accounting change                                     |       | (6,802                                                           | )          | (903 | ) | (10,977 | ) | (3,009 | ) | 2,810 |   |
|                                                                                             |       |                                                             |       |   |   |   |   |   |   |   |   |
| Cumulative effect of change in accounting  for asset retirement obligations, net of income taxes |       | —                                                           |       | — |   | (29 | ) | — |   | — |   |
|                                                                                             |       |                                                             |       |   |   |   |   |   |   |   |   |
| Net income (loss)                                                                                |       | $                                                                | (6,802     | ) | $ | (903 | ) | $ | (11,006 | ) | $ | (3,009 | ) | $ | 2,810 |   |
|                                                                                             |       |                                                             |       |   |   |   |   |   |   |   |   |
| Income (loss) from continuing operations  per share:                                             |       |                                                             |       |   |   |   |   |   |   |   |   |
| Basic                                                                                            |       | $                                                                | (0.63      | ) | $ | (0.08 | ) | $ | (2.17 | ) | $ | (0.46 | ) | $ | 0.03 |   |
| Diluted                                                                                          |       | (0.63                                                            | )          | (0.08 | ) | (2.17 | ) | (0.46 | ) | 0.03 |   |
|                                                                                             |       |                                                             |       |   |   |   |   |   |   |   |   |
| Net income (loss) per share:                                                                     |       |                                                             |       |   |   |   |   |   |   |   |   |
| Basic                                                                                            |       | (0.63                                                            | )          | (0.08 | ) | (1.07 | ) | (0.29 | ) | 0.27 |   |
| Diluted                                                                                          |       | (0.63                                                            | )          | (0.08 | ) | (1.07 | ) | (0.29 | ) | 0.27 |   |
|                                                                                             |       |                                                             |       |   |   |   |   |   |   |   |   |
| Weighted average number of outstanding  shares of common stock:                                  |       |                                                             |       |   |   |   |   |   |   |   |   |
| Basic                                                                                            |       | 10,785                                                           |       | 10,686 |   | 10,328 |   | 10,285 |   | 10,259 |   |
| Diluted                                                                                          |       | 10,785                                                           |       | 10,686 |   | 10,328 |   | 10,285 |   | 10,284 |   |
|                                                                                             |       |                                                             |       |   |   |   |   |   |   |   |   |
| **Balance Sheet Data (at December 31):**                                                         |       |                                                             |       |   |   |   |   |   |   |   |   |
| Working capital                                                                                  |       | $                                                                | 61,156     |   | $ | 53,907 |   | $ | 44,747 |   | $ | (4,331 | ) | $ | 13,498 |   |
| Property, plant and equipment, net                                                               |       | 494,698                                                          |       | 283,193 |   | 232,257 |   | 211,518 |   | 200,853 |   |
| Total assets                                                                                     |       | 1,132,304                                                        |       | 593,574 |   | 280,495 |   | 257,503 |   | 250,511 |   |
| Total long-term debt                                                                             |       | 608,762                                                          |       | 225,000 |   | 126,200 |   | 64,223 |   | 104,850 |   |
| Stockholder’s equity                                                                        |       | 39,982                                                           |       | 49,761 |   | 50,914 |   | 53,139 |   | 69,033 |   |
|                                                                                             |       |                                                             |       |   |   |   |   |   |   |   |   |
| **Cash Flow Data:**                                                                              |       |                                                             |       |   |   |   |   |   |   |   |   |
| Net cash flow provided by (used in):                                                             |       |                                                             |       |   |   |   |   |   |   |   |   |
| Operating activities                                                                             |       | $                                                                | 16,874     |   | $ | 26,616 |   | $ | (6,411 | ) | $ | 36,301 |   | $ | 12,980 |   |
| Investing activities                                                                             |       | (445,848                                                         | )          | (303,017 | ) | (36,887 | ) | (22,719 | ) | (77,643 | ) |
| Financing activities                                                                             |       | 437,098                                                          |       | 247,101 |   | 78,956 |   | (9,520 | ) | 66,087 |   |

 

27

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----

(1) MarkWestEnergy Partners completed its investment in Starfish on March 31, 2005, andacquired Javelina on November 1, 2005.

(2) MarkWestEnergy Partners acquired the East Texas System in late July 2004.

(3) MarkWestEnergy Partners acquired the Foss Lake gathering system in December 2003.

MarkWest Energy Partners acquired the Arapahoprocessing plant in December 2003.

MarkWest Energy Partners acquired the MichiganCrude Pipeline in December 2003.

MarkWest Energy Partners acquired the Pinnaclegathering systems in late March 2003.

MarkWest Energy Partners acquired the Lubbockpipeline in September 2003 and the Hobbs lateral pipeline in April 2004.

MarkWest Energy Partners sold most of itsexploration and production operations in July 2003 (U.S.) and December 2003(Canada).

 

***OperatingData***

 
| ** **                                          | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------|------------|----------------------------------|------------|
| ** **                                          | ** ** | **2005**                         | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** |
|                                                |       |                             |       |   |   |   |   |   |   |   |   |
| **MarkWest  Hydrocarbon**                           |       |                             |       |   |   |   |   |   |   |   |   |
| **Marketing:**                                      |       |                             |       |   |   |   |   |   |   |   |   |
| NGL product sales (gallons) (1)                     |       | 162,000,000                      |       | 178,000,000 |   | 177,000,000 |   | 183,000,000 |   | 152,200,000 |   |
|                                                |       |                             |       |   |   |   |   |   |   |   |   |
| **Wholesale:**                                      |       |                             |       |   |   |   |   |   |   |   |   |
| NGL product sales (gallons) (2)                     |       | 68,879,000                       |       | 42,154,000 |   | NA |   | NA |   | NA |   |
|                                                |       |                             |       |   |   |   |   |   |   |   |   |
| **MarkWest  Energy Partners:**                      |       |                             |       |   |   |   |   |   |   |   |   |
| ***Southwest:***                                    |       |                             |       |   |   |   |   |   |   |   |   |
| *East  Texas (3)*                                   |       |                             |       |   |   |   |   |   |   |   |   |
| Gathering systems throughput (Mcf/d)                |       | 321,000                          |       | 259,300 |   | NA |   | NA |   | NA |   |
| NGL product sales (gallons)                         |       | 126,476,000                      |       | 41,478,000 |   | NA |   | NA |   | NA |   |
|                                                |       |                             |       |   |   |   |   |   |   |   |   |
| *Oklahoma*                                          |       |                             |       |   |   |   |   |   |   |   |   |
| Foss Lake gathering systems throughput  (Mcf/d) (4) |       | 75,800                           |       | 60,900 |   | 57,000 |   | NA |   | NA |   |
| Arapaho NGL product sales (gallons) (5)             |       | 60,903,000                       |       | 45,273,000 |   | 2,910,000 |   | NA |   | NA |   |
|                                                |       |                             |       |   |   |   |   |   |   |   |   |
| *Other*                                             |       |                             |       |   |   |   |   |   |   |   |   |
| Appleby gathering systems throughput  (Mcf/d) (6)   |       | 33,400                           |       | 27,100 |   | 23,800 |   | NA |   | NA |   |
| Other gathering systems throughput (Mcf/d)  (6)     |       | 16,500                           |       | 17,000 |   | 20,500 |   | NA |   | NA |   |
| Lateral throughput volumes (Mcf/d) (7)              |       | 81,000                           |       | 75,500 |   | 32,100 |   | NA |   | NA |   |
|                                                |       |                             |       |   |   |   |   |   |   |   |   |
| ***Appalachia:***                                   |       |                             |       |   |   |   |   |   |   |   |   |
| Natural gas processed for a fee (Mcf/d) (8)         |       | 197,000                          |       | 203,000 |   | 202,000 |   | 202,000 |   | 192,000 |   |
| NGLs fractionated for a fee (Gal/day)               |       | 430,000                          |       | 475,000 |   | 458,000 |   | 476,000 |   | 423,000 |   |
| NGL product sales (gallons)                         |       | 41,700,000                       |       | 42,105,000 |   | 40,305,000 |   | 38,813,000 |   | — |   |
|                                                |       |                             |       |   |   |   |   |   |   |   |   |
| ***Michigan:***                                     |       |                             |       |   |   |   |   |   |   |   |   |
| Natural gas processed for a fee (Mcf/d)             |       | 6,600                            |       | 12,300 |   | 15,000 |   | 13,800 |   | 8,800 |   |
| NGL product sales (gallons)                         |       | 5,697,000                        |       | 9,818,000 |   | 11,800,000 |   | 11,100,000 |   | 8,000,000 |   |
| Crude oil transported for a fee (Bbl/d) (9)         |       | 14,200                           |       | 14,700 |   | 15,100 |   | NA |   | NA |   |
|                                                |       |                             |       |   |   |   |   |   |   |   |   |
| ***Gulf Coast:***                                   |       |                             |       |   |   |   |   |   |   |   |   |
| Natural gas processed for a fee (Mcf/d) (10)   |       | 115,000                          |       | NA |   | NA |   | NA |   | NA |   |
| NGLs fractionated for a fee (gal/day) (10)          |       | 19,400                           |       | NA |   | NA |   | NA |   | NA |   |

 

28

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----

(1) Representssales at the Siloam fractionator.

(2) Representssales from our wholesale business. Volumes are from the period since theCompany started the line of business in February 2004.

(3) ThePartnership acquired its East Texas System in late July 2004. Volumes arefor the period of time the Partnership owned the facility during 2004.

(4) ThePartnership acquired its Foss Lake gathering system in December 2003.

(5) ThePartnership acquired its Arapaho processing plant in December 2003.

(6) ThePartnership acquired its Pinnacle gathering systems in late March 2003.

(7) ThePartnership acquired its Lubbock pipeline (a/k/a the Power-tex LateralPipeline) in September 2003 and its Hobbs lateral pipeline inApril 2004. The Lubbock and Hobbs pipelines are the only laterals thePartnership own that produce revenue on a per-unit-of-throughput basis. ThePartnership receives a flat fee from its other lateral pipelines and,consequently, the throughput data from these lateral pipelines are excludedfrom this statistic.

(8) Includesthroughput from the Partnership’s Kenova, Cobb and Boldman processing plants.

(9) ThePartnership acquired its Michigan Crude Pipeline in December 2003.

(10) The Partnership acquired the Javelina facilitiesin November 2005.

 

29

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# **ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTSOF OPERATIONS**

 

*Management’s Discussion and Analysis (“MD&A”)contains statements that are forward-looking and should be read in conjunctionwith “Selected Consolidated Financial Data” and our consolidated financial statementsand accompanying notes included elsewhere in this report.  These statements are based on currentexpectations and assumptions that are subject to risks and uncertainties.  Actual results could differ materially fromthose expressed or implied in the forward-looking statements as a result of anumber of factors.*

 

##### **Overview**

##### ** **

We reported a net loss of $6.8 million for the year ended December 31,2005, or a $0.63 loss per diluted share, compared to a net loss of $0.9million, or an $0.08 loss per diluted share, for the year ended December 31,2004.

 

On January 26, 2006, the board of directors of the Company declared aquarterly cash dividend of $0.125 per share for the fourth quarter of2005.  The fourth quarter dividend waspaid February 22, 2006, to unitholders of record on February 15, 2006.

 

***DevelopmentsImpacting Financial Results***

 

***MarkWestHydrocarbon***

 

In October 2005, MarkWest Hydrocarbon disposed of all production andexploration assets held by its subsidiary, Matrex, L.L.C.

 

During the year ended December 31, 2003, MarkWest Hydrocarbondiscontinued its exploration and production business.  Through a series of dispositions, we sold offsubstantially all of our U.S. and Canadian oil and gas properties.   For the years ended December 31, 2003,revenues from our discontinued operations were $30.1 million, and income fromdiscontinued operations before income taxes was $2.1 million.

 

**The dispositions were as follows:**

** **

***Sales of SanJuan Basin Properties***

** **

**During the second and thirdquarters of 2003, we completed the sale of our San Juan Basin (U.S.) oil andgas 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.**

** **

***Sales ofCanadian Properties***

** **

**During December 2003, wecompleted 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.**

** **

***Sale of EasternMichigan Properties***

** **

**During December 2003, wecompleted the sale of certain oil and gas properties and related assets locatedin Eastern Michigan for net proceeds of less than $0.1 million. We recognized apretax loss of $1.8 million on the sale.**

** **

***MarkWestEnergy Partners***

 

The Partnership completed eight acquisitions in three years for anaggregate purchase price of $794.4 million, net of working capital.  Four of these acquisitions occurred in 2003and their results are included in the Partnership’s results of operations fromthe acquisition date.

 

•                  ThePinnacle acquisition closed on March 28, 2003, for consideration of$39.9 million.

 

•                  TheLubbock pipeline acquisition (also known as the Power-Tex Lateral pipeline)closed September 2, 2003, for consideration of $12.2 million.

 

•                  TheWestern Oklahoma acquisition closed December 1, 2003, for consideration of$38.0 million.

 

30

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•                  TheMichigan Crude Pipeline acquisition closed December 18, 2003, forconsideration of $21.3 million.

 

Two acquisitions occurred in 2004 and are included in the results ofoperations from the acquisition date.

 

•                  TheHobbs acquisition closed April 1, 2004, for consideration of $2.3 million.  As a result, only nine months of activity forHobbs is reflected in the results of operations for the year ended December 31,2004.

 

•                  TheEast Texas acquisition closed on July 30, 2004, for consideration of $240.7million, so only five months of activity for East Texas is reflected in theresults of operations for the year ended December 31, 2004.

 

Two acquisitions occurred in 2005 and are included in the results ofoperations from the acquisition date.

 

•                  TheStarfish acquisition closed on March 31, 2005, for consideration of $41.7million.  As a result, the acquisition isnot reflected in the results of operations in 2004.  Nine months of Starfish activity is reflectedin results of operations for the year ended December 31, 2005.

 

•                  TheJavelina acquisition closed on November 1, 2005, for consideration of $357.0million, plus $41.3 million for net working capital.  As a result, only two months of activity forJavelina is reflected in the results of operations for the year ended December31, 2005.

 

**Results of Operations**

 

***Segment Reporting***

 

Our two reportable segments are: MarkWest Hydrocarbon Standalone andMarkWest Energy Partners.  We captureinformation by reportable segment, except that certain items below the “OperatingIncome” line are not allocated to our business segments because management doesnot consider them in its evaluation of business unit performance.  The segment information appearing in Note 21to the consolidated financial statements, *SegmentInformation*, is presented on a basis consistent with the Company’sinternal management reporting, in accordance with SFAS No. 131, *Disclosure about Segments of an Enterprise andRelated Information*.

 

***Year EndedDecember 31, 2005, Compared to Year Ended December 31, 2004***

# ** **

| ** **                                           | ** ** | **MarkWest Hydrocarbon  Standalone** | ** ** | **MarkWest Energy  Partners** | ** ** | **Eliminating  Entries** | ** ** | **Total**  | ** ** |
|------------------------------------------------------|------------|-------------------------------------------|------------|-------------------------------|------------|--------------------------|------------|------------|------------|
| ** **                                           | ** ** | **(in thousands)**                        | ** ** |
| **Year Ended December 31, 2005:**                    | ** ** | ** **                                | ** ** | ** **                    | ** ** | ** **               | ** ** | ** ** | ** ** |
| Revenues                                             |       | $                                         | 280,015    |                          | $          | 499,084                  |       | $          | (64,922    | ) | $ | 714,177 |   |
| Purchased product costs                              |       | 258,188                                   |       | 366,878                       |       | (41,982                  | )          | 583,084    |       |
| Facility expenses                                    |       | 20,545                                    |       | 47,972                        |       | (22,940                  | )          | 45,577     |       |
| Selling, general and administrative  expenses        |       | 11,777                                    |       | 21,573                        |       | —                   |       | 33,350     |       |
| Depreciation                                         |       | 1,295                                     |       | 19,534                        |       | —                   |       | 20,829     |       |
| Amortization of intangible assets                    |       | —                                    |       | 9,656                         |       | —                   |       | 9,656      |       |
| Accretion of asset retirement and lease  obligations |       | 1                                         |       | 159                           |       | —                   |       | 160        |       |
| Total operating expenses                             |       | $                                         | 291,806    |                          | $          | 465,772                  |       | $          | (64,922    | ) | $ | 692,656 |   |
|                                                 |       |                                      |       |                          |       |                     |       |       |       |
| Operating income (loss)                              |       | $                                         | (11,791    | )                             | $          | 33,312                   |       | $          | —     |   | $ | 21,521 |   |
|                                                 |       |                                      |       |                          |       |                     |       |       |       |
| **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 and lease  obligations |       | 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 |   |
|                                                      |            |                                           |            |                               |            |                          |            |            |            |  |  |  |  |  |  |  |

 

31

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| ** **                                                                                               | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                               | ** ** | **2005**                    | ** ** | **2004** | ** ** |
| ** **                                                                                               | ** ** | **(in thousands)**          | ** ** |
|                                                                                                     |       |                        |       |   |   |
| Operating income                                                                                         |       | $                           | 21,521     |   | $ | 19,460 |   |
| Loss from unconsolidated subsidiary                                                                      |       | (2,153                      | )          | $ | — |   |
| Interest income                                                                                          |       | 1,060                       |       | 647 |   |
| Interest expense                                                                                         |       | (22,622                     | )          | (9,383 | ) |
| Amortization of deferred financing cost (a  component of interest expense)                               |       | (6,979                      | )          | (5,281 | ) |
| Dividend income                                                                                          |       | 392                         |       | 259 |   |
| Other income                                                                                             |       | 266                         |       | 788 |   |
| Income (loss) before non-controlling  interest in net income of consolidated subsidiary and income taxes |       | (8,515                      | )          | 6,490 |   |
| Income tax  (expense) benefit                                                                            |       | 1,804                       |       | (78 | ) |
| Non-controlling interest in net income of  consolidated subsidiary                                       |       | (91                         | )          | (7,315 | ) |
| Loss from continuing operations                                                                          |       | $                           | (6,802     | ) | $ | (903 | ) |

 

***MarkWest Hydrocarbon Standalone***

 

*Revenues.*  Revenuesincreased $61.7 million, or 28%, for the year ended December 31, 2005, comparedto the corresponding period of 2004. Higher volumes and better pricing drove revenue in our wholesale propanemarketing business, representing a $30.9 million increase in revenue, and ourgas marketing business, representing an $18.8 million increase.  NGL product revenues increased $18.5 milliondue to favorable pricing, offset by a decrease in volumes.  Increases to revenues were offset by a $5.2million unfavorable mark-to-market adjustment to replacement gas that resultedfrom an increase in natural gas prices, and a $1.0 million decrease in Michiganoperations, primarily from a reduction in volumes.

 

*Purchased Product Costs.*  Purchased product costs increased $72.2million, or 39%, for the year ended December 31, 2005, compared to thecorresponding period of 2004.  Theincrease was primarily due to volumes from our wholesale propane marketingbusiness, a $30.7 million increase, introduced in February 2004, and our gasmarketing business, an $18.1 million increase. NGL product costs rose $23.2 million because of higher pricing, offsetby reduced volumes.

 

*Facility Expenses.*  Facility expenses decreased by approximately$3.4 million, or 14%, during the year ended December 31, 2005, compared tocorresponding period of 2004.  Thedecrease was the result of a $1.4 million favorable fuel reimbursement at ourKenova, Cobb and Boldman facilities, a reduction to inventory losses at theAppalachia Liquids Pipeline System (ALPS) of $0.7 million, a net reduction toSiloam fractionation fees and Kenova and Boldman processing fees of $1.6million, and a net decrease of costs in Michigan of $0.2 million, offset by anincrease to inventory losses at Siloam of $0.5 million.

 

*Selling, General and AdministrativeExpenses. *Selling, general andadministrative expenses decreased by $0.2 million, or 2%, during the year endedDecember 31, 2005, compared to the corresponding period of 2004 as a result ofa decrease in compensation expense attributed to the Participation Plan (see *Stock and Incentive Compensation Plans* onpage

 

32

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44) and the 1996 Stock Incentive Plan and1996 Non-employee Director Stock Option Plan, and an increase to allocations ofselling, general and administrative expenses to the Partnership.

 

***MarkWest EnergyPartners***

 

*Revenues. *Revenues for the year ended December 31, 2005,were higher by $197.8 million, or 66%, compared to 2004.  The increase was primarily due to highervolumes and natural gas prices in the Partnership’s Oklahoma operations, $80.3million, and Other Southwest operations, $37.2 million, as well as operatingEast Texas System for a full year, $64.3 million.  Revenues reflected nine months ofactivity during 2005 compared to two months of activity during 2004.  Revenue also increased in Western Oklahomaduring the year ended December 31, 2005 relative to the corresponding period of2004 due to increased well volumes contracted to the gathering system, highercrude oil prices enhancing condensate sales and higher liquids revenue thatresulted from ethane recovery during 2005 versus ethane rejection during 2004that contributed to incremental revenue of $42.0 million. In addition, OtherSouthwest revenues increased $21.3 million due to a 27% increase in natural gasvolumes, primarily on the Appleby and Edwards gathering systems.

 

*PurchasedProduct Costs.*  Purchased product costs were higher duringthe year ended December 31, 2005, by $155.3 million, or 73%, compared to2004.  The combination of an increase in purchased volumes and price contributed toincreases in Western Oklahoma and Other Southwest, primarily Appleby andEdwards, of $75.5 million and $37.1 million, respectively.  In addition, the Partnership’s July30, 2004, East Texas System acquisition had incremental purchased product costsof $35.3 million due, in part, to being operational for a full year, but alsohigher prices.

 

*FacilityExpenses. *Facility expenses increased approximately$18.1 million, or 60%, during the year ended December 31, 2005, relative to2004.  East Texas accounted for $7.2million of the increase, related to operating the facility for a full year, aswell as performing repairs and a global overhaul of our compressors.  Appalachia increased $5.9 million due, inpart, to repairs to the ALPS pipeline. Gulf Coast, acquired November 1, 2005, contributed $2.2 million to theincrease.  Oklahoma, $1.3 million, andOther Southwest, $1.3 million, increased due to repairs and an overhaul ofcompressors.

 

*Selling, General and AdministrativeExpenses. *Selling,general and administrative expenses, which are not allocated to segments by thePartnership, increased by $5.4 million, or 34%, during the year ended December31, 2005, compared to 2004 as a result of the increase in incentivecompensation expense of $1.9 million, and audit and Sarbanes-Oxley relatedcosts of $3.2 million.

 

*Depreciation. *Depreciation expense increased $4.0 million,or 26%, during the year ended December 31, 2005, compared to 2004 primarily dueto the Partnership’s 2004 East Texas acquisition, $3.3 million, and 2005 GulfCoast acquisition, $1.1 million.  Thesechanges were offset by a decrease in depreciation in Appalachia, due toaccelerated depreciation in 2004 for the old Cobb facility.

 

*Amortization ofIntangible Assets. *Amortization expense increased $6.0 millionduring the year ended December 31, 2005, compared to 2004 due primarily to theNovember 2005 Gulf Coast acquisition and amortization of the East Texas customercontracts.

 

***Other Income and Expenses***

 

*Lossfrom Unconsolidated Subsidiary*.  Lossfrom unconsolidated subsidiary increased $2.2 million during the year endedDecember 31, 2005, compared to 2004.  The Partnership acquired a 50%,non-operating interest in Starfish on March 31, 2005.  The path ofHurricane Rita, however, was along the Starfish pipeline corridor. Consequently, Starfish incurred significant losses in the fourth quarter of2005, of which the Partnership’s share was approximately $2.1 million.

 

*InterestIncome. *Interest incomeincreased by $0.4 million during the year ended December 31, 2005, compared to2004. The increase is primarily due to an increase in interest earned on cashequivalents.

 

*InterestExpense and Amortization of Deferred Financing Costs (a component of interestexpense). *Interestexpense increased by $13.2 million, or 143%, during the year ended December 31,2005, compared to 2004.  Amortization of deferred financing costsincreased by $1.7 million, or 32%, during the year ended December 31, 2005,compared to 2004.  The increase was principally attributable to MarkWestEnergy Partners’ additional outstanding debt from financing its Javelina andStarfish acquisitions.

 

*DividendIncome. *Dividend incomeincreased by approximately $0.1 million, or 51%, during the year ended December31, 2005, compared to 2004 as a result of the increase in investments in masterlimited partnerships.  We began receiving distributions on the masterlimited partnerships during the second quarter of 2004.

 

*Incometax (expense) benefit*. The Company’sresults of operations reflected a $1.8 million benefit for 2005 compared to a$0.1 million expense for 2004. The change was primarily due to the decrease inearnings from continuing operations, including non-controlling interest in netincome of consolidated subsidiary.

 

*Non-controllingInterest in Net Income of Consolidated Subsidiary. *Non-controllinginterest in net income of consolidated subsidiary decreased by $7.2 million asa result of the decrease in earnings of MarkWest Energy compared to 2004.

 

33

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***Year Ended December 31, 2004, Compared toYear Ended December 31, 2003***

 
| ** **                                           | ** ** | **MarkWest  Hydrocarbon  Standalone** | ** ** | **MarkWest Energy Partners** | ** ** | **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 and lease  obligations |       | 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:**                   |       |                                  |       |                         |       |                    |       |       |       |
| 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** | ** ** |
| Operating income (loss)                                                                                  |       | $                           | 19,460     |   | $ | (26,080 | ) |
| Interest income                                                                                          |       | 647                         |       | 106 |   |
| Interest expense                                                                                         |       | (9,383                      | )          | (4,347 | ) |
| Amortization of deferred financing cost (a  component of interest expense)                               |       | (5,281                      | )          | (2,104 | ) |
| Dividend income                                                                                          |       | 259                         |       | — |   |
| Other income (expense)                                                                                   |       | 788                         |       | (92 | ) |
| Income (loss) before non-controlling  interest in net income of consolidated subsidiary and income taxes |       | 6,490                       |       | (32,517 | ) |
| Income tax  (expense) benefit                                                                            |       | (78                         | )          | 13,085 |   |
| Non-controlling interest in net income of  consolidated subsidiary                                       |       | (7,315                      | )          | (2,988 | ) |
| Loss from continuing operations                                                                          |       | $                           | (903       | ) | $ | (22,420 | ) |

 

34

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***MarkWest Hydrocarbon Standalone***

 

*Revenues.*  Revenuesincreased $75.8 million, or 53%, over 2003 revenue primarily due to increasesin NGL product sale prices and a 4% increase in volumes in Appalachia, whichcombined to increase revenue by approximately $37.1 million.  In addition, revenue increased $33.2 milliondue to the commencement of a wholesale propane marketing business in 2004.  Revenue in 2003 was reduced by losses oncrude oil derivatives of $15.9 million. These increases were offset, in part, by a decrease in third party NGLsales of $10.1 million, as a result of the sale of the two terminals in 2003.

 

*Purchased Product Costs.*  Purchased product costs increased $43.3million, or 30%, in 2004 primarily due to costs from our wholesale propanemarketing business introduced in 2004, adding $32.6 million.   Our Appalachian natural gas liquids businessincurred an additional $20.1 million, as a result of a 4% increase in volumeand an increase in price of 27%.  Theseincreases were offset in part by a decrease in third party NGL product costs of$10.2 million as a result of the sale of the two terminals in 2003.

 

*Facility Expenses.*  Facility expenses decreased by approximately$1.3 million, or 5%, as a result of a decrease in costs associated with twoterminals in Appalachia, that were sold in 2003.

 

*Selling, General and Administrativeexpenses. *Selling,general and administrative expenses increased by $4.7 million, or 65%, as aresult of stock option compensation of $2.0 million, increased incentivecompensation and severance related expenses of $1.0 million and an increase inSarbanes-Oxley compliance expenses and audit fees of $0.9 million.  Inaddition, compensation expense resulting from the sale of the subordinatedPartnership units and interests in the general partner to certain of MarkWestHydrocarbon’s employees and directors from 2002 through 2004 increased selling,general and administrative expenses by $1.0 million.  These increases were partially offset by adecrease in selling, general and administrative expenses attributed todiscontinued operations that were sold in 2003.

 

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

 

***MarkWest EnergyPartners***

 

*Revenues. *2004 Revenues were higher than our 2003revenues primarily due to the Partnership’s 2003 and 2004 acquisitions, whichincreased its revenues by $168.6 million. The increase was also due to higher Appalachia NGL product sales pricesand volumes, which increased revenues by $9.5 million.  In addition, higher margins due to higher gasprices in the Southwest, along with increased Southwest processing margins froman increase in liquid prices, contributed $6.3 million.  These increases were partially offset by a reductionin the Partnership’s Michigan Pipeline throughput volumes, which decreasedrevenue by $0.5 million.

 

*PurchasedProduct Costs.*  Purchased product costs were higher in 2004by $140.7 million primarily due to the Partnership’s late 2003 and 2004 acquisitions,which increased its purchased product costs by $128.3 million.  The remainder of the increase is primarilyattributable to price and volume increases for our Appalachia NGL productsales.  Price increases contributed $7.8million and volume increases contributed an additional $4.6 million topurchased product costs.

 

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

 

*Selling,*G*eneral and Administrative Expenses.*  Selling, general and administrative expensesincreased by $7.5 million during the year ended December 31, 2004,compared to 2003 because MarkWest Hydrocarbon was contractually limited in theamount it could charge the Partnership to $4.9 million annually, fromMay 24, 2002, the date of the Partnership’s initial public offering,through May 23, 2003.  In addition,selling, general and administrative expenses have increased due to increasedadministrative costs of $2.1 million associated with the Partnership’sacquisitions, increased Sarbanes-Oxley compliance related expenses and auditfees 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.

 

35

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*Depreciation. *Depreciation expense increased during 2004primarily due to the Partnership’s 2003 and 2004 acquisitions, which increaseddepreciation by approximately $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 ofIntangible Assets. *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, thePartnership recorded a write-off of $0.1 million of costs associated with anisomerization unit taken out of service. During the fourth quarter of 2003, the Partnership’s general partner’sboard of directors approved a plan to replace the Partnership’s existing Cobbextraction facility with a new facility. Consequently, in accordance with Statement of FinancialAccounting Standards (“SFAS”)No. 144, *Accounting for the Impairmentor Disposal of Long Lived Assets,*the Partnership wrote down thecarrying value of the current Cobb facility by $1.1 million to its estimatedfair value.

 

***Other Income and Expenses***

 

*Interest Expense.*  Interestexpense increased $5.0 million, or 116%, during 2004 relative to 2003 primarilydue to increased debt levels resulting from the Partnership’s financing of its2003 and 2004 acquisitions.  Asignificant amount of the Partnership’s 2004 acquisitions were financed throughadditional borrowings under its credit facility and the issuance of its seniornotes.

 

*Amortization of Deferred FinancingCosts. *The increase in amortization of deferredfinancing costs in 2004 relative to 2003 primarily is attributable to the debtrefinancings completed in 2004 as well as an increase in deferred financingcost as a result of the issuance of the Partnership’s senior notes.  During 2004, we amortized approximately $5.2million of deferred financing costs related to debt issuance costs incurred tofinance the Partnership’s 2004 acquisitions, of which $1.5 million representedaccelerated amortization due to the refinancing of the Partnership’s creditfacility 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. *Dividend incomeincreased to $0.3 million during 2004 as a result of investments in marketablesecurities of Master Limited Partnerships. The Company did not have these investments in 2003.

 

*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 Income taxes. *The Company’s results of operations reflected a $0.1 million provisionfor 2004 compared to a $13.1 million benefit for 2003.  The change was due primarily to the $34.7million increase in earnings from continuing operations, includingnon-controlling interest in net income of consolidated subsidiary.

 

*Non-controlling Interest in Net Income of ConsolidatedSubsidiary. *Non-controlling interest in net income ofconsolidated subsidiary increased by $4.3 million, or 145%, 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.

 

**Liquidity and Capital Resources**

 

***MarkWest Hydrocarbon******Standalone***

 

Our primary source ofliquidity, to meet operating expenses and fund capital expenditures, is cashflow from operations, principally from the marketing of NGLs, and quarterlydistributions received from MarkWest Energy Partners.  Based on current volume,price and expense assumptions, we expect cash flow from operations anddistributions from the Partnership to fund our operations and capitalexpenditures in 2005.  Most of our future capital expenditures arediscretionary.  During 2005, we spent $0.8 million for capitalexpenditures, consisting principally of computer hardware and software.

 

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We own 89% of thegeneral partner of MarkWest Energy Partners, excluding interests held bycertain employees and directors, but deemed owned by the Company through theParticipation Plan.  The general partner of MarkWest Energy Partners ownsthe 2% general partner interest and all of the incentive distributionrights.  The incentive distribution rights entitle us to receive anincreasing percentage of cash distributed by the Partnership as certain targetdistribution levels are reached.  Specifically, they entitle us to receive13% of all cash distributed in a quarter after each unit has received $0.55 forthat quarter; 23% of all cash distributed after each unit has received $0.625for that quarter; and 48% of all cash distributed after each unit has received$0.75 for that quarter.  For the year ended December 31, 2005, we received$7.7 million in distributions from our limited units, and $4.4 million from ourgeneral partner interest, of which $4.2 million represented payments onincentive distribution rights.

 

Cash flows generatedfrom our NGL marketing and natural gas supply operations are subject tovolatility in energy prices, especially prices for NGLs and natural gas. Our cash flows are enhanced in periods when the prices received for NGLs arehigh relative to the price of natural gas we purchase to satisfy our “keep-whole”contractual arrangements in Appalachia.  Conversely, they are reduced inperiods when the prices received for NGLs are low relative to the price ofnatural gas we purchase to satisfy such contractual 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 forthe energy content of the NGLs removed through the re-delivery to the producersof an equivalent amount (on a Btu basis) of dry natural gas.  Generally,the value of the NGLs extracted is greater than the cost of replacing thoseBtus with dry gas, resulting in positive operating margins under thesecontracts.  Periodically, natural gas becomes more expensive, on a Btuequivalent basis, than NGL products, and the cost of keeping the producer “whole”can result in operating losses.  We entered into several new and amendedagreements in September 2004 with one of the largest Appalachia producers thatallow us to significantly reduce our exposure to commodity price risk forapproximately 25% of our keep-whole gas volumes.  Under these agreements,the Company is limited on the costs it would have to pay to the producer shouldnatural gas becomes more expensive than the NGL product sales price, therebymitigating the risk of incurring operating losses.  In connection withthese agreements, we paid $3.3 million of consideration to the producer, thatis being amortized as additional cost of the gas purchased over the term of thecontracts, October 1, 2004, through February 9, 2015.

 

*Debt*

 

In October 2004, theCompany entered into a $25.0 million senior credit facility with a term of oneyear.  The $25.0 million revolving facility has a variable interest ratebased on the base rate or the London Inter Bank Offering Rate (“LIBOR”), asdiscussed below.  In October, November, and December 2005, the Companyentered into the first, second and third amendment to the creditagreement.  The first amendment extended the term of the originalagreement to November 15, 2005.  The second amendment reduced the lendingamount from $25.0 million to $16.0 million, of which $6.0 million ofavailability is committed to a letter of credit, leaving $10.0 millionavailable for revolving loans.  The second amendment also extended theterm of the revolving credit to December 30, 2005.  The third amendmentextended the term of the revolving credit to January 31, 2006 and reduced thelending amount from $16.0 million to $13.5 million, of which $6.0 million ofavailability is committed to a letter of credit, leaving $7.5 million availablefor revolving loans. On January 31, 2006, the Company entered into the first amended andrestated credit agreement which reinstated the maximum lending limit of $25.0million for a one year term.

 

The creditfacility bears interest at a variable interest rate, plus basis points.  The variable interest rate is typically basedon LIBOR; however, in certain borrowing circumstances the rate would be basedon the higher of a) the Federal Funds Rate plus 0.5-1%, and b) a rate set bythe Facility’s administrative agent, based on the U.S. prime rate.  The basis points correspond to the ratio ofthe Revolver Facility Usage (as defined in the Company Credit Facility) to theBorrowing Base (as defined in the Company Credit Facility), ranging from 0.75%to 1.75% for Base Rate loans, and 1.75% to 2.75% for Eurodollar Rateloans.  The Company pays a quarterlycommitment fee on the unused portion of the credit facility at an annual rateof 50.0 basis points.

 

Under the provisionsof the credit facility, the Company is subject to a number of restrictions onits business, including restrictions on its ability to grant liens on assets;make or own certain investments; enter into any swap contracts other than inthe ordinary course of business; merge, consolidate or sell assets; incurindebtedness (other than subordinated indebtedness); make distributions onequity investments; declare or make, directly or indirectly, any restricteddistributions.

 

As of December 31,2005, the Company had outstanding borrowings of $7.5 million and no borrowingcapacity.

 

We spent $0.3 millionfor capital expenditures for the year ending December 31, 2005.  We havebudgeted $0.8 million for 2006, consisting principally of computer hardware andsoftware.  We believe that cash on hand, cash received from quarterlydistributions (including the incentive distribution rights) from MarkWestEnergy Partners, and projected cash generated from our marketing operationswill be sufficient to meet our working capital requirements and fund ourrequired

 

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capitalexpenditures, if any, for the foreseeable future.  Cash generated from ourmarketing operations will depend on our operating performance, which will beaffected by prevailing commodity prices and other factors, some of which arebeyond our control.

 

***MarkWest Energy Partners***

 

The Partnership’s primary source of liquidity, to meet operatingexpenses and fund capital expenditures (other than for certain acquisitions),are cash flows generated by its operations, and its access to equity and debtmarkets.  The equity and debt markets,public and private, retail and institutional, have been the Partnership’sprincipal source of capital used to finance a significant amount of its growth,including acquisitions.  During the firstquarter of 2005, the Partnership borrowed $40.0 million from its creditfacility to finance the Starfish acquisition. In the fourth quarter of 2005, the $392.8 million Javelina acquisitionand then-existing borrowings, were financed with an interim credit facilitythat was subsequently replaced by a new long-term credit facility, as describedbelow. During the year ended December 31, 2005, the Partnership spent $70.8million on capital expenditures, primarily for the construction of a newprocessing plant and gathering systems in East Texas to handle its futurecontractual commitments, and construction of the new replacement Cobbprocessing facility in Appalachia.

 

The Partnership borrowed approximately $432.8 million, primarily tofinance its acquisitions.  ThePartnership received approximately $100.0 million in proceeds from a privateplacement of common units, which was used to pay down its credit facility.

 

On December 29, 2005, MarkWest Energy Operating Company, L.L.C., awholly owned subsidiary of MarkWest Energy Partners L.P., entered into thefifth amended and restated credit agreement (“Partnership Credit Facility”),which provides for a maximum lending limit of $615.0 million for a five-year term. The credit facility includes a revolving facility of $250.0 million and a$365.0 million term loan, which can be repaid at any time withoutpenalty.  The credit facility is guaranteed by the Partnership and all ofthe Partnership’s subsidiaries and is collateralized by substantially all ofthe Partnership’s assets and those of its subsidiaries.  The borrowingsunder the credit facility bear interest at a variable interest rate, plus basispoints.  The variable interest rate is typically based on the London InterBank Offering Rate (“LIBOR”); however, in certain borrowing circumstances therate would be based on the higher of a) the Federal Funds Rate plus 0.5-1%, andb) a rate set by the Facility’s administrative agent, based on the U.S. primerate.  The basis points correspond to the ratio of the Partnership’sConsolidated Senior Debt (as defined in the Partnership Credit Facility) toConsolidated EBITDA (as defined in the Partnership Credit Facility), rangingfrom 0.50% to 1.50% for Base Rate loans, and 1.50% to 2.50% for Eurodollar Rateloans.  The basis points will increase by 0.50% during any period (not toexceed 270 days) where the Partnership makes an acquisition for a purchaseprice in excess of $50.0 million (“Acquisition Adjustment Period”). Borrowingsunder the Partnership Credit Facility were used to finance, in part, theJavelina acquisition discussed above.  OnDecember 31, 2005, the available borrowing capacity under the PartnershipCredit Facility was $74.8 million.

 

Under the provisions of the PartnershipCredit Facility, the Partnership is subject to a number of restrictions on itsbusiness, including restrictions on its ability to grant liens on assets; makeor own certain investments; enter into any swap contracts other than in the ordinarycourse of business; merge, consolidate or sell assets; incur indebtedness(other than subordinated indebtedness); make distributions on equityinvestments; and declare or make, directly or indirectly, any restrictedpayments.

 

At December 31, 2005, the Partnership and its subsidiary, MarkWestEnergy Finance Corporation, also have $225.0 million in senior notesoutstanding, at a fixed rate of 6.875%. The notes mature on November 2, 2014. The proceeds from these noteswere used to pay down our outstanding debt under our credit facility inOctober 2004.  Subject to compliancewith certain covenants, we may issue additional notes from time to time underthe indenture pursuant to Rule 144A and Regulation S under the SecuritiesAct of 1933.

 

The indenture governing the senior notes limits the activity of thePartnership and its restricted subsidiaries. The provisions of such indenture places limits on the ability of thePartnership and its restricted subsidiaries to incur additional indebtedness;declare or pay dividends or distributions or redeem, repurchase or retireequity interests or subordinated indebtedness; make investment; incur liens;create any 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.

 

The Partnership has agreed to file an exchange offer registration statement,or under certain circumstances, a shelf registration statement, pursuant to aregistration rights agreement relating to the 2004 senior notes.  The Partnership failed to

 

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complete the exchange offer inthe time provided for in the subscription agreements (April 26, 2005) and,as a consequence, is incurring an interest rate penalty of 0.5%, increasing0.25% every 90 days thereafter up to 1%, until such time as the exchange offeris completed.  The Partnership iscurrently being charged an interest rate penalty of 1%.  The registration statement was filed onJanuary 17, 2006, and the interest penalty ceased on March 7, 2006.

 

Cash generated from operations, borrowings under the Partnership’scredit facility and funds from its private and public equity offerings are itsprimary sources of liquidity. The timing of the Partnership’s efforts to raiseequity in the future, however, will be influenced by the Partnership’sinability to timely file its Annual Report on Form 10-K for the year endedDecember 31, 2004, and its quarterly report on Form 10-Q for thequarter ending March 31, 2005.  ThePartnership will no longer have the ability to incorporate by referenceinformation from its filings into a new registration statement untilJune 25, 2006, should they choose to raise capital through a publicoffering registered on Form S-3.  Ifthe Partnership raises additional capital through public debt or equity offerings,it is required to file a Form S-1, which is a long-form type ofregistration statement.  The requirementto file a Form S-1 registration statement will affect the Partnership’sability to access the capital markets on a timely basis and may increase thecosts of doing so.  The Partnershipbelieves, nonetheless, that funds from raising equity, together with cashgenerated from operations and borrowings under its credit facility, will besufficient to meet both its short-term and long-term working capitalrequirements and anticipated capital expenditures.  Funding of additional acquisitions willlikely require the issuance of additional common units, the expansion of thePartnership’s credit facility, or both.

 

The Partnership’s ability to pay distributions to its unitholders andto fund planned capital expenditures and make acquisitions will depend upon itsfuture operating performance.  That, inturn, will be affected by prevailing economic conditions in the Partnership’sindustry, as well as financial, business and other factors, some of which are beyondits control.

 

The Partnership has budgeted $58.7 million for capital expenditures in2006, exclusive of any acquisitions, consisting of $55.6 million for expansioncapital and $3.1 million for sustaining capital. Expansion capital includesexpenditures made to expand or increase the efficiency of the existingoperating capacity of its assets, or facilitate an increase in volumes withinits operations, whether through construction or acquisition.  Sustaining capital includes expenditures toreplace partially or fully depreciated assets in order to extend their usefullives.

 

**Cash Flow**

 

| ** **                                | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------|------------|----------------------------------|------------|
| ** **                                | ** ** | **2005**                         | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                | ** ** | **(in thousands)**               | ** ** |
| ** **                                | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net cash provided by operating activities |       | $                                | 16,874     |   | $ | 26,616 |   | $ | (6,411 | ) |
| Net cash used in investing activities     |       | (445,848                         | )          | (303,017 | ) | (36,887 | ) |
| Net cash provided by financing activities |       | 437,098                          |       | 247,101 |   | 78,956 |   |
|                                           |            |                                  |            |  |  |  |  |  |  |  |

 

Net cash provided byoperating activities decreased by $9.7 million during the year ended December31, 2005, compared to the corresponding period of 2004, primarily due to agreater net loss in 2005, offset by increases in depreciation expense andamortization of intangibles, arising from the Partnership’s acquisition ofJavelina in November 2005. Increases in inventory, customer margin deposits andprepaid fuel also contributed to the decline.

 

Net cash used ininvesting activities during the year ended December 31, 2005, consistedprimarily of the $356.9 million for the Javelina acquisition, $41.7 millioninvestment in Starfish, capital expenditures of $71.3 million for existingfacilities and $8.7 million for purchases of marketable securities, offset by$17.3 million from sales of marketable securities.  Net cash used ininvesting activities during the year ended December 31, 2004, primarily relatedto the $240.7 million East Texas System acquisition, $2.3 million Hobbsacquisition, capital expenditures of $12.7 million for existing facilities,$3.3 million for a contract to reduce exposure to commodity price risk and$11.5 million for investment in marketable securities.

 

**Net cash provided by financingactivities during the year ended December 31, 2005, consisted primarily ofproceeds from long-term debt in excess of repayments of $386.5 million,proceeds from MarkWest Energy Partners private placements of $92.9 million,payments of debt issuance costs of $11.8 million, distributions by MarkWestEnergy Partners of $26.1 million to unitholders other than MarkWest Hydrocarbonand the general partner, and cash dividends paid to shareholders of $4.3million.  Net cash provided by financing activities during the year endedDecember 31, 2004, consisted primarily of proceeds from long-term debt inexcess of repayments of $791.4 million, proceeds from MarkWest Energy Partners’public offerings and private placements of $183.7 million, payments of debtissuance costs of $15.6 million, distributions by MarkWest Energy Partners of$15.4 million to unitholders other than MarkWest Hydrocarbon and the generalpartner, proceeds from stock option exercises of $1.4 million, and cashdividends paid to shareholders of $5.8 million.**

 

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**Total Contractual Cash Obligations**

 

A summary ofour total contractual cash obligations as of December 31, 2005, is asfollows, in thousands:

 
| ** **                          | ** ** | **Payment Due by Period** | ** ** |
|-------------------------------------|------------|---------------------------|------------|
| **Type of obligation**              | ** ** | **Total  Obligation**     | ** ** | **Due in  2006** | ** ** | **Due in  2007-2008** | ** ** | **Due in  2009-2010** | ** ** | **Thereafter** | ** ** |
|                                |       |                      |       |   |   |   |   |   |   |   |   |
| Long-term  debt(1)                  |       |                      |       |   |   |   |   |   |   |   |   |
| MarkWest Energy Partners            |       | $                         | 604,000    |   | $ | 2,738 |   | $ | 7,300 |   | $ | 368,962 |   | $ | 225,000 |   |
| MarkWest Hydrocarbon Standalone     |       | 7,500                     |       | — |   | 7,500 |   | — |   | — |   |
| Operating  leases                   |       | 11,869                    |       | 4,755 |   | 4,936 |   | 1,975 |   | 203 |   |
| Purchase  obligations               |       | 2,163                     |       | 2,163 |   | — |   | — |   | — |   |
| Asset  retirement obligations       |       | 1,102                     |       | — |   | — |   | — |   | 1,102 |   |
| Total contractual  cash obligations |       | $                         | 626,634    |   | $ | 9,656 |   | $ | 19,736 |   | $ | 370,937 |   | $ | 226,305 |   |
|                                     |            |                           |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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(1) Excluding interest

 

# **Off-Balance Sheet Arrangements**

 

Otherthan facility and equipment leasing arrangements, we do not engage inoff-balance sheet financing activities.

 

**Matters Influencing Future Results**

 

We earn fees for transporting, fractionating and selling the NGLsrecovered from the Kenova and Boldman plants to Siloam via our Appalachianpipeline.  In November 2004, a leakand ensuing explosion and fire occurred on a leased section of thispipeline.  In early 2005, the Company andseveral of its affiliates were served with two lawsuits, Ricky J. Conn, *et al.* v. MarkWest Hydrocarbon, Inc. *et al*.(filed February 7, 2005),*. and* Charles C. Reid, *et al.* v. MarkWest Hydrocarbon, Inc. *et al.*, (filed February 8, 2005),  presently removed to and under thejurisdiction of the U.S. District Court for the Eastern District of Kentucky,Pikeville Division.  The Company wasserved with an additional lawsuit, Community Trust and Investment Co., *et al.* v. MarkWest Hydrocarbon, Inc. *et al.*, filed November 7, 2005 inFloyd County Circuit Court, Kentucky, that added five new claimants butessentially alleged the same facts and claims as the earlier two suits. Theseactions are for third-party claims of property and personal injury damagessustained as a consequence of an NGL pipeline leak and an ensuing explosion andfire that occurred on November 8, 2004. The pipeline was owned by an unrelated business entity and leased andoperated by the Partnership’s subsidiary, MarkWest Energy Appalachia, LLC.  It transports NGLs from the Maytown gasprocessing plant to the Partnership’s Siloam fractionator.  The fire from the leaked vapors resulted inproperty damage to five homes and injuries to some of the residents.  The pipeline owner, the U.S. Department ofTransportation, Office of Pipeline Safety (“OPS”), and the Company continue toinvestigate the incident.

 

The Company notified its general liability insurance carriers of theincident and of the filed Kentucky actions in a timely manner and iscoordinating the defense of these third-party lawsuits with the insurers.  At this time, the Company believes that ithas adequate general liability insurance coverage for third-party propertydamage and personal injury liability resulting from the incident.  To date, the Partnership has settled withseveral of the claimants for third-party property damage claims (damage toresidences and personal property), in addition to reaching settlement for someof the personal injury claims.  Thesesettlements have been paid for or reimbursed under the Partnership’s generalliability insurance.   As a result, theCompany has not provided for a loss contingency.

 

Pursuant to OPS regulation mandates and to a Corrective Action Orderissued by the OPS on November 18, 2004, pipeline and valve integrityevaluation, testing and repairs were conducted on the affected pipeline segmentbefore service could be resumed.  Basedon, among other things, the successful integrity testing of the affectedpipeline, OPS authorized a partial return to service of the affected pipelinein October 2005.  MarkWest is currentlypreparing its application for return to full service.

 

The Company has filed an independent action captioned MarkWestHydrocarbon, Inc., *et al*. v.Liberty Mutual Ins. Co., *et al*.  (District Court, Arapahoe County, Colorado,Case No. 05CV3953 filed August 12, 2005)), as removed to the U.S. DistrictCourt for the District of Colorado, Civil Action No. 1:05-CV-1948, on October7, 2005), against its All-Risks Property and Business Interruption insurancecarriers as a result of the insurance companies’ refusal to honor theirinsurance coverage obligation to pay the Company for certain expenses.  These include the Company’s internal expensesand costs incurred for damage to, and loss of use of the pipeline, equipment,products, the extra transportation costs incurred for transporting the liquidswhile the pipeline was out of service, the reduced volumes of liquids that couldbe processed, and the costs of complying with the OPS Corrective Action Order(hydrostatic testing, repair/replacement and other pipeline integrity assurancemeasures). These expenses and costs have been expensed as incurred and anypotential recovery from the All-Risks Property and Business Interruptioninsurance carriers will be treated as “other income” if and when they arereceived.  The Company has not providedfor a receivable for these claims because of the uncertainty as to whether andhow much the Company will ultimately recover under these policies. The Companyhas also asserted that the costs of pipeline testing,

 

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replacement and repair aresubject to an equitable sharing arrangement with the pipeline owner, pursuantto the terms of the pipeline lease agreement.

 

TheCompany has also been involved in a lawsuit captioned *Ross Bros. Construction v. MarkWest Hydrocarbon, Inc*.,(U.S. Court of Appeals for the 6th Circuit, Case No. 05-6251, appealed fromU.S. District Court Eastern District of Kentucky, Ashland Division, Civ. ActionNo. 01-CV-205). The underlying lawsuit involved the construction of the SiloamKentucky plant and a dispute as to the monetary value of additional work beyondthe contract’s lump sum price performed by the contractor. The lawsuit involveda claim of approximately $0.7 million in extra costs. The Company was grantedSummary Judgment on its defense asserting accord and satisfaction. In August2005, Plaintiffs filed an appeal of the Summary Judgment to the U.S. Court ofAppeals for the 6thCircuit. The Company believes that, while it is not able to predict the outcomeof this matter, based on the judge’s discussion on the grant of the summaryjudgment and denial of Ross Brothers’ motion for reconsideration, it isprobable that the Company will prevail in the appeal. As a result, the Companyhas not provided for a loss contingency.

 

TheCompany has also been involved in an arbitration proceeding captioned *Kevin Stowe and Scott Daves v. MarkWest Hydrocarbon,Inc*., American Arbitration Association arbitration, Case No. 77168 Y 0052 05 BEAH, Denver, Colorado, 2005. Claimants in this Arbitration hadfiled a proceeding against the Company seeking further payments out of adispute and settlement over interests in certain wells in Colorado. On February8, 2006, the Company was granted Summary Judgment and the Arbitration wasaccordingly dismissed.

 

# **Commodity Price Sensitivity**

 

Ourearnings and cash flow are dependent on sales volumes and our ability toachieve positive sales margins on the product we sell. The volumes of our salesand our margin on sales can be adversely affected by the prices of commodities,which are subject to significant fluctuation depending upon numerous factors beyondour control, including the supply of and demand for commodity products. Thesupply of and demand for our products can be affected by, among other things,production levels, industry-wide inventory levels, the availability of imports,the marketing of products by competitors, and the marketing of competitivefuels.

 

**Seasonality**

 

For the portion of our business that is affected by commodity prices,sales volumes also are affected by various other factors such as fluctuatingand seasonal demands for products, changes in transportation and travelpatterns and variations in weather patterns from year to year.  In general, we store a portion of the propanethat we produce in the summer as well as pre-purchase in the summer a portionof the natural gas that we are required to replace during the winter inaccordance with our Appalachian keep-whole processing agreements.

 

**Effects of Inflation**

 

Inflation inthe United States has been relatively low in recent years and did not have amaterial impact our results of operations for the years ended December 31,2005, 2004 or 2003.  Although the impactof inflation has been insignificant in recent years, it is still a factor inthe United States economy and may increase the cost to acquire or replaceproperty, plant and equipment.  It mayalso increase the costs of labor and supplies.

 

# **Critical Accounting Policies**

# ** **

The preparationof financial statements in conformity with accounting principles generallyaccepted in the United States of America requires management to make estimatesand assumptions that affect the reported amounts of assets and liabilities,disclosure of contingent assets and liabilities at the date of the financialstatements, and the reported amounts of revenues and expenses during thereporting period. Actual results could differ from those estimates.  Estimates are used in accounting for, amongother items, valuing identified intangible assets, determining the fair valueof derivative instruments, evaluating impairments of long lived assets,establishing estimated useful lives for long-lived assets, valuing assetretirement obligations, and in determining liabilities, if any, for legalcontingencies.

 

The policies and estimates discussed beloware considered by management to be critical to an understanding of the Company’sfinancial statements, because their application requires the most significantjudgments from management in estimating matters for financial reporting thatare inherently uncertain.  See Note 2 ofthe accompanying Notes to the Consolidated Financial Statements included inItem 8 of this Form 10-K for additional information on these policies andestimates, as well as a discussion of additional accounting policies andestimates.

 

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###### *Investmentin Starfish*

######  

On March 31, 2005, the Partnership acquired its non-controlling, 50%interest in Starfish Pipeline Company, LLC (“Starfish”) for $41.7 million,which is accounted for under the equity method. Differences between the Partnership’s investment and its proportionateshare of Starfish’s reported equity are amortized based upon the respectiveuseful lives of the assets to which the differences relate.  For the year ended December 31, 2005, thePartnership received dividends of $1.8 million, and accrued $1.5 million for acapital call.  The Partnership’s share ofStarfish’s loss in 2005 was $2.2 million.

 

The Partnership’s accounting policy requires it to evaluate operatinglosses, if any, and other factors that may have occurred, that may be indicativeof a decrease in value of the investment which is other than temporary, andwhich should be recognized even though the decrease in value is in excess ofwhat would otherwise be recognized by application of the equity method.  The evaluation allows the Partnership todetermine if an equity method investment should be impaired and that animpairment, if any, is fairly reflected in its financial statements

 

The Partnership believes the equity method is an appropriate means forit to recognize increases or decreases measured by GAAP in the economicresources underlying the investments. Regular evaluation of these investments is appropriate to evaluate anypotential need for impairment.  It usesthe following types of triggers to identify a loss in value of an investmentthat is other than a temporary decline. Examples of a loss in value may be identified by:

 

•                  Aninability to recover the carrying amount of the investment;

•                  Acurrent fair value of an investment that is less than its carrying amount; and

•                  Otheroperational criteria that cause us to believe the investment may be worth lessthan otherwise accounted for by using the equity method.

 

*Intangible Assets*

 

The Company’s intangible assets are comprisedof customer contracts and relationships acquired in business combinations,recorded under the purchase method of accounting at their estimated fair valuesat the date of acquisition.  Usingrelevant information and assumptions, management determines the fair value ofacquired identifiable intangible assets. Fair value is generally calculated as the present value of estimatedfuture cash flows using a risk-adjusted discount rate.  The key assumptions include contractrenewals, economic incentives to retain customers, historical volumes, currentand future capacity of the gathering system, pricing volatility, and thediscount rate.  Amortization ofintangibles with definite lives is calculated using the straight-line methodover the estimated useful life of the intangible asset.  The estimated economic life is determined byassessing the life of the assets to which the contracts / relationships relate,likelihood of renewals, competitive factors, regulatory or legal provisions,and maintenance and renewal costs.

 

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

###### * *

The Company evaluates its long-lived assets, including intangibles, forimpairment when events or changes in circumstances warrant such a review.  A long-lived asset group is consideredimpaired when the estimated undiscounted cash flows from such asset group isless than the asset group’s carrying value. In that event, a loss is recognized to the extent that the carryingvalue exceeds the fair value of the long-lived asset group.  Fair value is determined primarily usingestimated discounted cash flows. Management considers the volume of reserves behind the asset and futureNGL product and natural gas prices to estimate cash flows. The amount ofadditional reserves developed by future drilling activity depends, in part, onexpected 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.

 

For assets identified to be disposed of in the future, the carryingvalue of these assets is compared to the estimated fair value, less the cost tosell, to determine if impairment is required. Until the assets are disposed of,an estimate of the fair value is re-determined when related events orcircumstances change.

 

*Derivative Instruments*

 

SFAS No. 133, *Accountingfor Derivative Instruments and Hedging Activities,* established accountingand reporting standards requiring that derivative instruments (includingcertain derivative instruments embedded in other contracts) be recorded at fairvalue and included in the consolidated balance sheet as assets or liabilities.  The accounting for changes in the fair valueof a derivative instrument depends on the intended use of the derivative andthe resulting designation, which is established at the inception.  To the extent derivative instruments designatedas cash flow hedges are effective, changes in fair value are recognized inother comprehensive income until the underlying hedged item is recognized inearnings.  Effectiveness is

 

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evaluated by the derivative instrument’s ability to offset changes infair value or cash flows of the underlying hedged item.  Any change in the fair value resulting fromineffectiveness is recognized immediately in earnings.  Changes in the fair value of derivativeinstruments designated as fair value hedges, as well as the changes in the fairvalue of the underlying hedged item, are recognized currently in earnings.  Any differences between the changes in thefair values of the hedged item and the derivative instrument represent gains orlosses from ineffectiveness.  To theextent that the Company elects hedge accounting treatment for specificderivatives, the Company formally documents, designates and assesses theeffectiveness.  As of December 31, 2005,no transactions had been designated for hedge accounting treatment.  In general, the Company exempts thosecontracts that qualify as normal purchase and sale contacts from themark-to-market requirements of SFAS 133. All other derivative instruments are marked-to-market through revenue.

 

*Revenue Recognition*

 

The Company generates the majority of its revenues from natural gasgathering and processing, NGL fractionation, transportation and storage, andcrude oil gathering and transportation. While all of these services constitutemidstream energy operations, the Partnership provides its services pursuant tosix different types of arrangements.  Inmany cases, the Partnership provides services under contracts that contain acombination of more than one of the arrangements.  The following is a description of the Partnership’ssix 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 Partners delivers an agreed uponpercentage of the residue gas and NGLs to the producer and sells the volumes itkeeps to third 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.The Partnership 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 anddeemed line losses.  To the extent thePartnership’s gathering systems are operated more efficiently than specifiedper contract allowance, it is entitled to retain the difference for its ownaccount.

 

•      *Condensate sales*- During the gathering process, thermodynamic forces contribute to changes inoperating conditions of the natural gas flowing through the pipelineinfrastructure.  As a result, hydrocarbondew points are reached, causing condensation of hydrocarbons in thehigh-pressure pipelines.  Under thosearrangements, condensate collected in the system is retained by us and sold atmarket prices.

 

Under all six arrangements, revenue is recognized at the time theproduct is delivered and title is transferred. It is upon delivery and title transfer that the Company meets all fourrevenue recognition criteria, and it is at such time that the Companyrecognizes revenue.

 

The Company’s assessment of each of the four revenue recognitioncriteria as they relate to its revenue producing activities is as follows:

 

*Persuasive evidence of an arrangement exists.*ThePartnership’s customary practice is to enter into a written contract, executedby both the customer and the Partnership.

 

*Delivery.*Delivery is deemed to have occurred atthe time the product is delivered and title is transferred, or in the case offee-based arrangements, when the services are rendered.  To the extent weretain our equity liquids as inventory, delivery occurs when the inventory issubsequently sold and title is transferred to the third party purchaser.

 

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*Thefee is fixed or determinable.* ThePartnership negotiates the fee for its services at the outset of its fee-basedarrangements. In these arrangements, the fees are nonrefundable. The fees aregenerally due within ten days of delivery or services rendered.  For other arrangements, the amount of revenueis determinable when the sale of the applicable product has been completed upondelivery and transfer of tile. Proceeds from the sale of products are generallydue in ten days.

 

*Collectibility isprobable.*Collectibility is evaluated on a customer-by-customer basis. New and existingcustomers are subject to a credit review process, which evaluates the customers’financial position (e.g. cash position and credit rating) and their ability topay. If collectibility is not considered probable at the outset of anarrangement in accordance with the Partnership’s credit review process, revenueis recognized when the fee is collected.

 

Certain revenue from sales of customer gas toa third-party processor is recognized net, under EITF 99-19, *Reporting Revenue Gross as a Principal versus Net asan Agent,*as the Partnership earns a fixed amount and does not takeownership of the gas.

 

Gas volumes received may be different fromgas volumes delivered, resulting in gas imbalances.  The Partnership records a receivable orpayable for such imbalances based upon the contractual terms of the purchaseagreements.  Revenues for thetransportation of crude are based upon regulated tariff rates and the relatedtransportation volumes and are recognized when delivery of crude is made to thepurchaser or other common carrier pipeline. As described above, changes in the fair value of commodity derivativeinstruments are recognized currently in revenue.

 

***Stock andIncentive Compensation Plans***

 

The Company haselected to continue to measure compensation costs for unit-based employeecompensation plans as prescribed by Accounting Principles Board (“APB”) No. 25,*Accounting for Stock Issued to Employees,*aspermitted under SFAS No. 123, *Accounting forStock Based Compensation*, and SFAS No. 148, *Accounting for Stock-Based Compensation – Transitionand Disclosure.*

 

Stock options areissued under the Company’s 1996 Stock Incentive Plan and 1996 Non-employee DirectorStock Option Plan.  The plans allow for the exercise of stock optionsusing the cashless method, but only at the discretion of the Company. Under a cashless exercise, the Company withholds those shares that otherwisewould be issued upon the exercise of the option, the number of shares with afair market value equal to the option exercise price and remits the remainingshares to the employees.  Prior to April 2004, the Company did not allowparticipants to exercise their stock options using the cashless method. Accordingly, compensation expense was not recognized for stock options grantedunless the options were granted at an exercise price less than the quotedmarket price of the Company on the grant date.  In April 2004, the Companychanged its policy to allow participants to exercise their stock options usingthe cashless method.  Under APB No. 25, a fixed stock option plan thatpermits the use of a cashless exercise becomes variable if a pattern ofexercising the stock options using the cashless method is demonstrated. As a result, in April 2004, the Company was required to account for stockoptions issued under the plans as variable 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 is amortized into earnings over the periodof service as the options vest, adjusted quarterly for the change in the fairvalue of the unvested stock options awarded.  Increases or decreases inthe market value of the Company’s common stock between April 2004 and the endof each reporting period result in a change in the measure of compensation forvested awards, which is reflected currently in operations in selling, generaland administrative expenses.

 

The Company alsoissues restricted stock under the Company’s 1996 Stock Incentive Plan and 1996Non-employee Director Stock Option Plan.  In accordance with APB No. 25,the Company applies fixed accounting for the plans. As a result, since therestricted stock is granted for no consideration, compensation expense isrecognized on the date of grant equal to the market price of the Company’scommon stock.  The fair value of the stock awarded is amortized into earningsover the period of service.  The restricted stock vests over a statedperiod.  These charges are included inselling, general and administrative expenses.

 

The Company has alsoentered into arrangements with certain directors and employees of the Companyreferred to as the Participation Plan.  Periodically, the Company sellssubordinated partnership units of the Partnership, and interests in thePartnership’s general partner, to employees and directors of the Company undera purchase and sale agreement.  In accordance with the provisions of APBNo. 25, the Participation Plan is accounted for as a variable plan.  Since theemployees and directors are 100% vested (except for two non-executives who haverestricted general partnership interests) on the date they purchase thesubordinated units or general partner interests, compensation expense for thesubordinated units is measured as the difference in the market value of thesubordinated Partnership units and the amount paid by those

 

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individuals.  Compensationrelated to the general partner interest is calculated as the difference in theformula value and the amount paid by those individuals.  The formula value is the amount MarkWestHydrocarbon would have to pay the directors and employees to repurchase thegeneral partner interests and is based on the current market value of thePartnership’s common units and the current quarterly distribution paid.Increases or decreases in the market value of the subordinated units and theformula value of the general partner interests between the date they areacquired and the end of each reporting period result in a change in the measureof compensation, which is reflected currently in the statement of operations.

 

UnderTopic 1-B of the codification of the Staff Accounting Bulletins, Allocation ofExpenses And Related Disclosure in Financial Statements of Subsidiaries,Divisions or Lesser Business Components of Another Entity, compensation expenserelated to services provided by MarkWest Hydrocarbon’s employees and directorsrecognized under the Participation Plan should be allocated to thePartnership.  The allocation is based onthe percent of time that each employee devotes to the Company.  Compensation attributable to interests thatwere sold to individuals who serve on both the board of MarkWest Hydrocarbonand the Partnership’s board of directors is allocated equally.

 

The Partnership issues restricted units underthe MarkWest Energy Partners, L.P. Long-Term Incentive Plan.  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.  Inaccordance with APB 25, the Partnership applies variable accounting for theplan because a phantom unit is an award to employees entitling them toincreases in the market valueof the Partnership’s units subsequent to the date of grant without issuingunits to the employees, similar to a stock appreciation right. As a result, the Partnership is required to mark to market the awardsat the end of each reporting period.  Compensationexpense is measured for the phantom unit grants using the market price ofMarkWest Energy Partners’ common units on the date the units are granted. Thefair value 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.  Vesting isaccelerated for certain employees, if specified performance measures aremet.  The accelerated vesting criteriaprovisions are based on annualized distribution goals.  If the Partnership’s distributions are at orabove the goal for a certain number of consecutive quarters, vesting of theemployee’s phantom units is accelerated. The vesting of any phantom units, however, may not occur until at leastone year following the date of grant. The general partner of the Partnership may also elect to accelerate thevesting of outstanding awards, which results in an immediate charge tooperations for the unamortized portion of the award.

 

**Recent Accounting Pronouncements**

 

In December 2004, the FASB issued SFASNo. 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)liabilities that are based on the fair value of the enterprise’s equityinstruments or that may be settled by the issuance of such equityinstruments.  SFAS No. 123(R) requires anentity to recognize the grant-date fair-value of stock options and otherequity-based compensation 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 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 123(R) is effective for public companiesfor the first fiscal year beginning after December 31, 2005.  All public companies must use either themodified prospective or the modified retrospective transition method.  We have not yet evaluated the impact of the adoptionof this pronouncement, which must be adopted in the first quarter of calendaryear 2006.  On March 29, 2005, theSEC staff issued SAB No. 107, *Share-BasedPayment*, to express the views of the staff regarding the interactionbetween SFAS No. 123(R) and certain SEC rules and regulations and to providethe staff’s views regarding the valuation of share-based payment arrangementsfor public companies.  The Company willtake into consideration the additional guidance provided by SAB 107 inconnection with the implementation of SFAS No. 123(R).

 

In May 2005, the FASBissued SFAS No. 154, *Accounting for Changesand Error Corrections – a Replacement of APB Opinion No. 20 and FASB StatementNo. 3* (SFAS 154).  SFAS 154 requires retrospective applicationof voluntary changes in accounting principles, unless impracticable.  SFAS154 supersedes the guidance in APB Opinion No. 20 and SFAS No. 3, but does notchange any transition provisions of existing pronouncements.  Generally,elective accounting changes will no longer result in a cumulative effect of achange in accounting in the income statement, because the effects of anyelective changes will be reflected as prior period adjustments to all periodspresented.  SFAS 154 will be effective beginning in fiscal 2006 and willaffect any accounting changes that we elect to make thereafter.

# ** **

InFebruary 2006, the FASB issued SFAS No. 155, *Accounting for Certain Hybrid Financial Instruments—anamendment of FASB Statements No. 133 and 140* (“SFAS 155”). Thisstatement amends SFAS No. 133, *Accounting for DerivativeInstruments and Hedging Activities* (“SFAS 133”), and SFASNo. 140, *Accounting for Transfers andServicing*

 

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*ofFinancial Assets and Extinguishments of Liabilities*and resolves issues addressed in SFAS 133Implementation Issue No. D1, *Applicationof Statement 133 to Beneficial Interest in Securitized Financial Assets*.This Statement: (a) permits fair value remeasurement for any hybridfinancial instrument that contains an embedded derivative that otherwise wouldrequire bifurcation; (b) clarifies which interest-only strips andprincipal-only strips are not subject to the requirements of SFAS 133;(c) establishes a requirement to evaluate beneficial interests in securitizedfinancial assets to identify interests that are freestanding derivatives orthat are hybrid financial instruments that contain an embedded derivativerequiring bifurcation; (d) clarifies that concentrations of credit risk inthe form of subordination are not embedded derivatives; and,(e) eliminates restrictions on a qualifying special-purpose entity’sability to hold passive derivative financial instruments that pertain tobeneficial interests that are or contain a derivative financial instrument. 

 

The standard also requirespresentation within the financial statements that identifies those hybridfinancial instruments for which the fair value election has been applied andinformation on the income statement impact of the changes in fair value of thoseinstruments. The Company isrequired to apply SFAS 155 to all financial instruments acquired, issued orsubject to a remeasurement event beginning January 1, 2007, although earlyadoption is permitted as of the beginning of an entity’s fiscal year. Theprovisions of SFAS 155 are not expected to have an impact recorded at adoption.

 

# **ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK**

 

Market risk includesthe risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity price changes and, to a lesser extent,interest rate changes.

 

***Commodity Price Risk***

 

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

 

We may utilize acombination of fixed-price forward contracts, fixed-for-floating price swapsand options on the over-the-counter (“OTC”) market.  The Company may alsoenter into futures contracts traded on the New York Mercantile Exchange (“NYMEX”). Swaps and futures contracts allow us to manage volatility in our marginsbecause corresponding losses or gains on the financial instruments aregenerally offset by gains or losses in our physical positions.

 

We enter into OTCswaps with financial institutions and other energy companycounterparties.  We conduct a standard credit review on counterparties andhave agreements containing collateral requirements where deemednecessary.  We use standardized swap agreements that allow for offset ofpositive and negative exposures.  We may be subject to margin depositrequirements under OTC agreements (with non-bank counterparties) and NYMEXpositions.

 

The use of derivativeinstruments 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 enter into derivative instruments, we may beprevented from realizing the benefits of favorable price changes in thephysical market.  We are similarlyinsulated, however, against unfavorable changes in such prices.

 

***MarkWest Hydrocarbon Risk Management Activity***

 

Since year end and asof March 1, 2006, MarkWest Hydrocarbon has pre-purchased natural gas for shrinkrequirements in future months and has entered into forward financial NGL salesto manage frac spread risk.  Thefollowing table includes information on our specific derivative activities:

 
| **Commodity**             | ** ** | **Period**   | ** ** | **Quantity**    | ** ** | **Average Price** | ** ** |
|---------------------------|------------|--------------|------------|-----------------|------------|-------------------|------------|
| Natural Gas  (pre-bought) |       | Oct-Dec 2006 |       | 1,000,000 MMBtu |       | $                 | 7.02       |   |
| Propane                   |       | Oct-Dec 2006 |       | 6,415,200 gal   |       | $                 | 0.93       |   |
| Iso-Butane                |       | Oct-Dec 2006 |       | 668,252 gal     |       | $                 | 1.12       |   |
| Normal-Butane             |       | Oct-Dec 2006 |       | 2,004,752 gal   |       | $                 | 1.10       |   |
| Natural  Gasoline         |       | Oct-Dec 2006 |       | 1,336,500 gal   |       | $                 | 1.39       |   |

 

Hydrocarbon may enterinto additional physical and/or financial positions to manage its risks relatedto commodity price exposure.  Due totiming of gas purchases and liquid sales, direct exposure to either gas orliquids can be created because there is no longer an offsetting purchase orsale that remains exposed to market pricing. Through our marketing and derivatives activity, direct exposure mayoccur naturally or we may choose direct exposure to either gas or liquids whenwe favor that exposure over frac spread risk.

 

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***The Partnership’s Derivative Activity***

 

As part of an ongoingcomprehensive risk management plan, designed to manage risk and stabilizefuture cash flows, the Partnership has entered into the following derivativeinstruments that settle monthly through December 31, 2007:

 
| ** **                        | ** ** | ** **        | ** ** | ** ** | ** ** | ** ** | ** ** | **Fair Value at**      | ** ** |
|-----------------------------------|------------|-------------------|------------|------------|------------|------------|------------|------------------------|------------|
| **Costless Collars:**             | ** ** | **Period**        | ** ** | **Floor**  | ** ** | **Cap**    | ** ** | **December 31,  2005** | ** ** |
| Crude Oil —  500 Bbl/d       |       | 2006              |       | $          | 57.00      |       | $          | 67.00                  |       | $ | (187 | ) |
| Crude Oil —  250 Bbl/d       |       | 2006              |       | $          | 57.00      |       | $          | 67.00                  |       | (93 | ) |
| Crude Oil —  205 Bbl/d       |       | 2006              |       | $          | 57.00      |       | $          | 65.10                  |       | (126 | ) |
|                              |       |              |       |       |       |       |       |                   |       |
| Propane — 20,000 Gal/d       |       | 2006              |       | $          | 0.90       |       | $          | 0.99                   |       | (258 | ) |
| Propane — 10,000 Gal/d       |       | 2006              |       | $          | 0.97       |       | $          | 1.15                   |       | 162 |   |
| Propane — 12,750 Gal/d       |       | Jan - June 2006   |       | $          | 0.90       |       | $          | 1.01                   |       | (56 | ) |
|                              |       |              |       |       |       |       |       |                   |       |
| Ethane —  22,950 Gal/d       |       | 2006              |       | $          | 0.65       |       | $          | 0.80                   |       | 104 |   |
|                              |       |              |       |       |       |       |       |                   |       |
| Natural Gas  — 1,575 Mmbtu/d |       | Jan - Mar 2006    |       | $          | 9.00       |       | $          | 11.40                  |       | 62 |   |
| Natural Gas  — 1,575 Mmbtu/d |       | April - Oct 2006  |       | $          | 8.50       |       | $          | 10.05                  |       | (86 | ) |
| Natural Gas  — 1,575 Mmbtu/d |       | Nov - Mar 2007    |       | $          | 9.00       |       | $          | 12.50                  |       | (58 | ) |
| Natural Gas  — 645 Mmbtu/d   |       | Jan - Mar 2006    |       | $          | 8.86       |       | $          | 15.21                  |       | 14 |   |
| Natural Gas  — 645 Mmbtu/d   |       | April - June 2006 |       | $          | 6.71       |       | $          | 12.46                  |       | 19 |   |
|                                   |            |                   |            |            |            |            |            |                        |            |  |  |  |

 
| ** **                  | ** ** | ** ** | ** ** | ** **      | ** ** | **Fair Value at**     | ** ** |
|-----------------------------|------------|------------|------------|-----------------|------------|-----------------------|------------|
| **Swaps**                   | ** ** | ** ** | ** ** | **Fixed Price** | ** ** | **December 31, 2005** | ** ** |
| Crude Oil —  250 Bbl/d |       | 2006       |       | $               | 62.00      |                  | $          | (105 | ) |
| Crude Oil —  185 Bbl/d |       | 2006       |       | $               | 61.00      |                  | (143       | ) |
| Crude Oil —  250 Bbl/d |       | 2007       |       | $               | 65.30      |                  | 23         |   |
|                             |            |            |            |                 |            |                       |            |  |  |

 

Fair value is based onavailable market information for the particular derivative instrument, and incorporatesthe commodity, period, volume and pricing. Positive (negative) amounts represent unrealized gains (losses).

 

While we expect thesederivative instruments to provide economic stability against the impact ofchanging commodity prices on our physical positions, for accounting purposes,we will not designate these derivatives as cash flow hedges and will not applyhedge accounting.

 

As aresult of the Partnership’s decision not to designate these derivatives as cashflow hedges for accounting purposes, we are required to mark each contract tomarket with the resulting unrealized gain or loss recorded in revenue in theincome statement.  For the year endedDecember 31, 2005, unrealized losses of approximately $728,000 wererecorded.  The fair value of ourderivative contracts at December 31, 2005 of $728,000 was recorded as aderivative liability.  Changes in forwardprice curves can result in significant changes in the fair value of ourderivative contracts as reported; however, we expect the actual settlements tobe largely offset by changes in the settlement of our physical positions.

 

*Interest Rate Risk*

 

The Company’s primary interest rate risk exposure results from thePartnership’s $615.0 million long-term debt agreement entered into on December29, 2005.  The debt related to thisagreement bears interest at variable rates that are tied to either the U.S.prime rate or LIBOR at the time of borrowing. We may make use of interest rate swap agreements in the future, toadjust the ratio of fixed and floating rates in the Partnership’s debtportfolio.

 
| **Long-term Debt**              | ** ** | **Due**            | ** ** | **Outstanding at December 31, 2005** | ** **    |
|---------------------------------|------------|--------------------|------------|--------------------------------------|---------------|
| Variable  Rate ($25.0 million)  |       | January 30,  2007  |       | $                                    | 7.5 million   |   |
| Variable  Rate ($615.0 million) |       | December 31,  2010 |       | $                                    | 379.0 million |   |
| Fixed Rate ($225.0  million)    |       | November,  2014    |       | $                                    | 225.0 million |   |

 

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# **ITEM 8.  FINANCIALSTATEMENTS AND SUPPLEMENTARY DATA**

 

# **Index to Consolidated Financial Statements**

#  

| Report  of Deloitte & Touche LLP, Independent Registered Public Accounting Firm                                                      |   |
|------------------------------------------------------------------------------------------------------------------------------------------|--------|
|                                                                                                                                     |   |
| Report of KPMG LLP, Independent Registered Public  Accounting Firm                                                                       |   |
|                                                                                                                                     |   |
| Report  of PricewaterhouseCoopers, LLP Independent Registered Public Accounting Firm                                                     |   |
|                                                                                                                                     |   |
| Consolidated  Balance Sheets at December 31, 2005 and 2004                                                                          |   |
|                                                                                                                                     |   |
| Consolidated  Statements of Operations for each of the three years in the period ended  December 31, 2005                           |   |
|                                                                                                                                     |   |
| Consolidated  Statements of Comprehensive Income for each of the three years in the period  ended December 31, 2005                 |   |
|                                                                                                                                     |   |
| Consolidated  Statements of Changes in Stockholders’ Equity for each of the three years in  the period ended December 31, 2005 |   |
|                                                                                                                                     |   |
| Consolidated  Statements of Cash Flows for each of the three years in the period ended  December 31, 2005                           |   |
|                                                                                                                                     |   |
| Notes to Consolidated Financial Statements                                                                                               |   |

 

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**Report of IndependentRegistered Public Accounting Firm**

 

To the Board of Directors ofMarkWest Hydrocarbon, Inc. **Englewood, Colorado

 

We have audited the accompanying consolidated balance sheet of MarkWest Hydrocarbon, Inc. andsubsidiaries (the “Company”) as of December 31, 2005, and the relatedconsolidated statements of operations, comprehensive income, changes in stockholders'equity, and cash flows for the year then ended.   These financialstatements are the responsibility of the Company’s management.  Ourresponsibility is to express an opinion on the financial statements based onour audit.

 

We conducted our audit in accordance with the standards of the PublicCompany Accounting Oversight Board (United States).  Those standardsrequire that we plan and perform the audit to obtain reasonable assurance aboutwhether the financial statements are free of material misstatement.  Anaudit includes examining, on a test basis, evidence supporting the amounts anddisclosures in the financial statements.  An audit also includes assessingthe accounting principles used and significant estimates made by management, aswell as evaluating the overall financial statement presentation.  Webelieve that our audit provides a reasonable basis for our opinion.

 

In our opinion, such consolidated financial statements present fairly,in all material respects, the financial position of MarkWest Hydrocarbon, Inc. and subsidiaries as of December 31,2005, and the results of their operations and their cash flows for the yearthen ended in conformity with accounting principles generally accepted in theUnited States of America.

 

We have also audited, in accordance with the standards of the PublicCompany Accounting Oversight Board (United States), the effectiveness of theCompany’s internal control over financial reporting as of December 31, 2005,based on the criteria established in *InternalControl—Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission and our report dated March 20, 2006expressed an unqualified opinion on management’s assessment of theeffectiveness of the Company’s internal control over financial reporting and anadverse opinion on the effectiveness of the Company’s internal control overfinancial reporting.

 
| /s/ DELOITTE & TOUCHE LLP |   |
|-------------------------------|--------|
|                          |
| Denver, Colorado              |
| March 20, 2006                |

 

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** **

**Report of IndependentRegistered Public Accounting Firm**

 

The Board of Directors MarkWest Hydrocarbon, Inc.:

 

We have audited the accompanying consolidatedbalance sheet of MarkWest Hydrocarbon, Inc. and its subsidiaries (the Company)as of December 31, 2004, and the related consolidated statements ofoperations, comprehensive income, changes in stockholders’ equity, and cashflows for the year then ended. These consolidated financial statements are theresponsibility of the Company’s management. Our responsibility is to express anopinion on these consolidated financial statements based on our audit.

 

We conducted our audit in accordance with thestandards of the Public Company Accounting Oversight Board (UnitedStates).  Those standards require that weplan and perform the audit to obtain reasonable assurance about whether thefinancial statements are free of material misstatement.  An audit includes examining, on a test basis,evidence supporting the amounts and disclosures in the financial statements. Anaudit also includes assessing the accounting principles used and significantestimates made by management, as well as evaluating the overall financialstatement presentation.  We believe thatour audit provides a reasonable basis for our opinion.

 

In our opinion, the consolidated financialstatements referred to above present fairly, in all material respects, thefinancial position of MarkWest Hydrocarbon, Inc. and subsidiaries as ofDecember 31, 2004, and the results of their operations and their cash flowsfor the year then ended, in conformity with U.S. generally accepted accountingprinciples.

 
| /s/ KPMG LLP |   |
|--------------|--------|

 

Denver, Colorado

October 14, 2005

 

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# **REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

 

To the Board of Directors of MarkWestHydrocarbon, Inc.

 

In our opinion, the accompanying consolidated statements of operations,of comprehensive income, of changes in stockholders’ equity  and cash flows for the year ended December31, 2003 present fairly, in all material respects, the results of operationsand cash flows of MarkWest Hydrocarbon, Inc., a Delaware company, and itssubsidiaries (the Company) for the year ended December 31, 2003, inconformity with accounting principles generally accepted in the United Statesof America. These financial statements are the responsibility of the Company’smanagement. Our responsibility is to express an opinion on these financialstatements based on our audit. We conducted our audit of these statements inaccordance with the standards of the Public Company Accounting Oversight Board(United States). Those standards require that we plan and perform the audit toobtain reasonable assurance about whether the financial statements are free ofmaterial misstatement. An audit includes examining, on a test basis, evidencesupporting the amounts and disclosures in the financial statements, assessingthe accounting principles used and significant estimates made by management,and evaluating the overall financial statement presentation. We believe thatour audit provides a reasonable basis for our opinion.

 

As discussed in Note 10 to the consolidated financial statements, theCompany changed its method of accounting for asset retirement obligations inaccordance with Statement of Financial Accounting Standards No. 143 on January1, 2003.

 

 
| /s/ PricewaterhouseCoopers LLP                                                                                                                                                                                                                                                                                                                                                   |   |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|
|                                                                                                                                                                                                                                                                                                                                                                             |
| Denver, Colorado                                                                                                                                                                                                                                                                                                                                                                 |
| March 30, 2004, except as to the 2004 stock  dividend described in Note 16 (presented herein), the reclassifications  described in Note 2 and the restatements described in Note 23 to the  consolidated financial statements included in the Annual Report on Form 10-K  for the year ended December 31, 2004 (not presented herein), as to which the  date is October 17, 2005 |

 

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**MARKWESTHYDROCARBON, INC.**

**CONSOLIDATED BALANCESHEETS**

(in thousands, except share and per sharedata)

 
| ** **                                                                                                          | ** ** | **December 31,  2005** | ** ** | **December 31,  2004** | ** ** |
|---------------------------------------------------------------------------------------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| **ASSETS**                                                                                                          |       |                        |       |                        |       |
| Current assets:                                                                                                     |       |                        |       |                        |       |
| Cash and cash equivalents                                                                                           |       | $                           | 20,968     |                        | $          | 12,844 |   |
| Restricted cash                                                                                                     |       | —                      |       | 15,000                      |       |
| Marketable securities                                                                                               |       | 6,070                       |       | 14,815                      |       |
| Receivables, net of allowance for doubtful  accounts of $175 and $249, respectively                                 |       | 145,539                     |       | 64,856                      |       |
| Inventories                                                                                                         |       | 30,500                      |       | 11,292                      |       |
| Prepaid replacement natural gas                                                                                     |       | 10,567                      |       | 10,245                      |       |
| Deferred income taxes                                                                                               |       | —                      |       | 25                          |       |
| Other current assets                                                                                                |       | 16,314                      |       | 1,898                       |       |
| Total current  assets                                                                                               |       | 229,958                     |       | 130,975                     |       |
|                                                                                                                |       |                        |       |                        |       |
| Property, plant and equipment                                                                                       |       | 573,198                     |       | 342,636                     |       |
| Less: accumulated depreciation                                                                                      |       | (78,500                     | )          | (59,443                     | )          |
| Total property, plant and equipment, net                                                                            |       | 494,698                     |       | 283,193                     |       |
|                                                                                                                |       |                        |       |                        |       |
| Other assets:                                                                                                       |       |                        |       |                        |       |
| Investment in Starfish                                                                                              |       | 39,167                      |       | —                      |       |
| Intangible  assets, net                                                                                             |       | 346,496                     |       | 162,001                     |       |
| Deferred financing costs, net of  accumulated amortization of $4,424 and $5,541, respectively                       |       | 18,463                      |       | 13,849                      |       |
| Deferred contract cost, net of accumulated  amortization of $390 and $78, respectively                              |       | 2,860                       |       | 3,172                       |       |
| Investment in and advances to other equity  investee                                                                |       | 182                         |       | 177                         |       |
| Other long term assets                                                                                              |       | 326                         |       | —                      |       |
| Notes receivable from related parties                                                                               |       | 154                         |       | 207                         |       |
| Total other assets                                                                                                  |       | 407,648                     |       | 179,406                     |       |
| Total assets                                                                                                        |       | $                           | 1,132,304  |                        | $          | 593,574 |   |
|                                                                                                                |       |                        |       |                        |       |
| **LIABILITIES  AND STOCKHOLDERS’ EQUITY**                                                                      |       |                        |       |                        |       |
| Current liabilities:                                                                                                |       |                        |       |                        |       |
| Accounts payable (including related party  payables of $25 and $30, respectively)                                   |       | $                           | 119,105    |                        | $          | 45,103 |   |
| Accrued liabilities                                                                                                 |       | 45,869                      |       | 30,908                      |       |
| Fair value of derivative instruments                                                                                |       | 728                         |       | 1,057                       |       |
| Deferred income taxes                                                                                               |       | 362                         |       | —                      |       |
| Current  portion of long-term debt                                                                                  |       | 2,738                       |       | —                      |       |
| Total current liabilities                                                                                           |       | 168,802                     |       | 77,068                      |       |
|                                                                                                                |       |                        |       |                        |       |
| Deferred income taxes                                                                                               |       | 3,487                       |       | 6,258                       |       |
| Long-term debt                                                                                                      |       | 608,762                     |       | 225,000                     |       |
| Other long-term liabilities                                                                                         |       | 10,256                      |       | 7,487                       |       |
| Non-controlling interest in consolidated  subsidiary                                                                |       | 301,015                     |       | 228,000                     |       |
|                                                                                                                |       |                        |       |                        |       |
| Commitments and contingencies (Note 17)                                                                             |       |                        |       |                        |       |
|                                                                                                                |       |                        |       |                        |       |
| Stockholders’ equity:                                                                                          |       |                        |       |                        |       |
| Preferred stock, par value $0.01, 5,000,000  shares authorized, no shares outstanding                               |       | —                      |       | —                      |       |
| Common stock, par value $0.01, 20,000,000  shares authorized, 10,857,939 and 10,821,760 shares issued, respectively |       | 108                         |       | 108                         |       |
| Additional paid-in capital                                                                                          |       | 48,797                      |       | 51,455                      |       |
| Deferred compensation                                                                                               |       | (398                        | )          | —                      |       |
| Accumulated deficit                                                                                                 |       | (8,425                      | )          | (1,623                      | )          |
| Accumulated other comprehensive income, net  of tax                                                                 |       | 357                         |       | 246                         |       |
| Treasury stock, 55,619 and 63,586 shares,  respectively                                                             |       | (457                        | )          | (425                        | )          |
| Total stockholders’ equity                                                                                     |       | 39,982                      |       | 49,761                      |       |
| Total liabilities and stockholders’ equity                                                                     |       | $                           | 1,132,304  |                        | $          | 593,574 |   |

 

The accompanying notes are an integralpart of these consolidated financial statements.

 

52

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**MARKWESTHYDROCARBON, INC.**

**CONSOLIDATED STATEMENTSOF OPERATIONS**

(in thousands, except per share data)

 
| ** **                                                                                                                           | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                                                           | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
|                                                                                                                                 |       |                                       |       |   |   |   |   |
| Revenues                                                                                                                             |       | $                                          | 714,177    |   | $ | 460,113 |   | $ | 209,268 |   |
|                                                                                                                                 |       |                                       |       |   |   |   |   |
| Operating expenses:                                                                                                                  |       |                                       |       |   |   |   |   |
| Purchased product costs                                                                                                              |       | 583,084                                    |       | 363,261 |   | 187,544 |   |
| Facility expenses                                                                                                                    |       | 45,577                                     |       | 28,580 |   | 20,957 |   |
| Selling, general and administrative  expenses                                                                                        |       | 33,350                                     |       | 28,132 |   | 15,865 |   |
| Depreciation and depletion                                                                                                           |       | 20,829                                     |       | 16,895 |   | 8,795 |   |
| Amortization of intangible assets                                                                                                    |       | 9,656                                      |       | 3,640 |   | — |   |
| Accretion of asset retirement obligation                                                                                             |       | 160                                        |       | 15 |   | — |   |
| Impairments                                                                                                                          |       | —                                     |       | 130 |   | 2,187 |   |
| Total operating expenses                                                                                                             |       | 692,656                                    |       | 440,653 |   | 235,348 |   |
|                                                                                                                                 |       |                                       |       |   |   |   |   |
| Income (loss) from operations                                                                                                        |       | 21,521                                     |       | 19,460 |   | (26,080 | ) |
|                                                                                                                                 |       |                                       |       |   |   |   |   |
| Other income and (expense):                                                                                                          |       |                                       |       |   |   |   |   |
| Loss from unconsolidated subsidiary                                                                                                  |       | (2,153                                     | )          | — |   | — |   |
| Interest income                                                                                                                      |       | 1,060                                      |       | 647 |   | 106 |   |
| Interest expense                                                                                                                     |       | (22,622                                    | )          | (9,383 | ) | (4,347 | ) |
| Amortization of deferred financing costs (a  component of interest expense)                                                          |       | (6,979                                     | )          | (5,281 | ) | (2,104 | ) |
| Dividend income                                                                                                                      |       | 392                                        |       | 259 |   | — |   |
| Miscellaneous income (expense)                                                                                                       |       | 266                                        |       | 788 |   | (92 | ) |
| Income (loss) from continuing operations  before non-controlling interest in net income of consolidated subsidiary and income  taxes |       | (8,515                                     | )          | 6,490 |   | (32,517 | ) |
|                                                                                                                                 |       |                                       |       |   |   |   |   |
| Income tax  (expense) benefit                                                                                                        |       |                                       |       |   |   |   |   |
| Current                                                                                                                              |       | (554)                                      |       | (20 | )  | 13,680 |   |
| Deferred                                                                                                                             |       | 2,358                                      |       | (58 | )  | (595 | ) |
| Income tax (expense) benefit                                                                                                         |       | 1,804                                      |       | (78 | )  | 13,085 |   |
|                                                                                                                                 |       |                                       |       |   |   |   |   |
| Non-controlling interest in net income of  consolidated subsidiary                                                                   |       | (91                                        | )          | (7,315 | ) | (2,988 | ) |
|                                                                                                                                 |       |                                       |       |   |   |   |   |
| Loss from continuing operations                                                                                                      |       | (6,802                                     | )          | (903 | ) | (22,420 | ) |
|                                                                                                                                 |       |                                       |       |   |   |   |   |
| Discontinued operations (Note 18):                                                                                                   |       |                                       |       |   |   |   |   |
| Income from discontinued exploration and  production operations (less applicable income taxes of $962 in 2003)                       |       | —                                     |       | — |   | 1,095 |   |
| Gain from disposal of discontinued  exploration and production operations (less applicable income taxes of  $6,322)                  |       | —                                     |       | — |   | 10,348 |   |
| Income from discontinued operations                                                                                                  |       | —                                     |       | — |   | 11,443 |   |
|                                                                                                                                 |       |                                       |       |   |   |   |   |
| Loss before cumulative effect of accounting  change                                                                                  |       | (6,802                                     | )          | (903 | ) | (10,977 | ) |
|                                                                                                                                 |       |                                       |       |   |   |   |   |
| Cumulative effect of change in accounting  for asset retirement obligations, net of income taxes                                     |       | —                                     |       | — |   | (29 | ) |
|                                                                                                                                 |       |                                       |       |   |   |   |   |
| Net loss                                                                                                                             |       | $                                          | (6,802     | ) | $ | (903 | ) | $ | (11,006 | ) |
|                                                                                                                                 |       |                                       |       |   |   |   |   |
| Loss from continuing operations per share  (Note 2):                                                                                 |       |                                       |       |   |   |   |   |
| Basic                                                                                                                                |       | $                                          | (0.63      | ) | $ | (0.08 | ) | $ | (2.17 | ) |
| Diluted                                                                                                                              |       | $                                          | (0.63      | ) | $ | (0.08 | ) | $ | (2.17 | ) |
|                                                                                                                                 |       |                                       |       |   |   |   |   |
| Net loss per share (Note 2):                                                                                                         |       |                                       |       |   |   |   |   |
| Basic                                                                                                                                |       | $                                          | (0.63      | ) | $ | (0.08 | ) | $ | (1.07 | ) |
| Diluted                                                                                                                              |       | $                                          | (0.63      | ) | $ | (0.08 | ) | $ | (1.07 | ) |
|                                                                                                                                 |       |                                       |       |   |   |   |   |
| Weighted average number of outstanding  shares of common stock (Note 2):                                                             |       |                                       |       |   |   |   |   |
| Basic                                                                                                                                |       | 10,785                                     |       | 10,686 |   | 10,328 |   |
| Diluted                                                                                                                              |       | 10,785                                     |       | 10,686 |   | 10,328 |   |

 

The accompanying notes are an integralpart of these consolidated financial statements.

 

53

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# **MARKWEST HYDROCARBON, INC.**

**CONSOLIDATED STATEMENTSOF COMPREHENSIVE INCOME (LOSS)**

**(in thousands)**

 
| ** **                                                                                                                                          | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                                                                          | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
|                                                                                                                                                |       |                                       |       |   |   |   |   |
| Net loss                                                                                                                                            |       | $                                          | (6,802     | ) | $ | (903 | ) | $ | (11,006 | ) |
|                                                                                                                                                |       |                                       |       |   |   |   |   |
| Other comprehensive income (loss):                                                                                                                  |       |                                       |       |   |   |   |   |
| Unrealized gains (losses) on marketable  securities, net of income tax benefit of $92 and income tax provision of $291,  respectively               |       | (153                                       | )          | 526 |   | — |   |
| Unrealized gains (losses) on commodity  derivative instruments accounted for as hedges, net of income taxes of $158,  $825 and $4,134, respectively |       | 264                                        |       | 1,513 |   | 6,390 |   |
| Foreign currency translation, net of income  taxes                                                                                                  |       | —                                     |       | — |   | 675 |   |
| Total other comprehensive income                                                                                                                    |       | 111                                        |       | 2,039 |   | 7,065 |   |
|                                                                                                                                                |       |                                       |       |   |   |   |   |
| Comprehensive income (loss)                                                                                                                         |       | $                                          | (6,691     | ) | $ | 1,136 |   | $ | (3,941 | ) |

 

The accompanying notes are an integralpart of these consolidated financial statements.

 

54

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**MARKWESTHYDROCARBON, INC.**

**CONSOLIDATED STATEMENTSOF CHANGES IN**

**STOCKHOLDERS’ EQUITY**

**(in thousands)**

 
| ** **                                               | ** ** | **Shares of  Common  Stock** | ** ** | **Shares of  Treasury  Stock** | ** ** | **Common  Stock** | ** ** | **Additional  Paid-In  Capital** | ** ** | **Deferred  Compensation** | ** ** | **Accumulated  Earnings  (Deficit)** | ** ** | **Accumulated  Other  Comprehensive  Income (Loss)** | ** ** | **Treasury  Stock** | ** ** | **Total  Stockholders’  Equity** | ** ** |
|----------------------------------------------------------|------------|-----------------------------------|------------|-------------------------------------|------------|-------------------|------------|----------------------------------|------------|----------------------------|------------|--------------------------------------|------------|-----------------------------------------------------------|------------|---------------------|------------|---------------------------------------|------------|
|                                                     |       |                              |       |                                |       |              |       |                             |       |                       |       |                                 |       |                                                      |       |                |       |                                  |       |
| Balance,  December 31, 2002                         |       | 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                                                 |       | —                            |       | —                              |       | —            |       | —                           |       | —                     |       | (11,006                              | )          | —                                                    |       | —              |       | (11,006                               | )          |
| Other  comprehensive income                              |       | —                            |       | —                              |       | —            |       | —                           |       | —                     |       | —                               |       | 7,065                                                     |       | —              |       | 7,065                                 |       |
| Balance,  December 31, 2003                         |       | 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                                |       |
| Stock option  exercises                                  |       | 15                                |       | —                              |       | —            |       | 77                               |       | —                     |       | —                               |       | —                                                    |       | —              |       | 77                                    |       |
| Issuance of  restricted stock                            |       | —                            |       | 3                                   |       | —            |       | (57                              | )          | —                     |       | —                               |       | —                                                    |       | 57                  |       | —                                |       |
| Grant of  restricted stock                               |       | —                            |       | —                              |       | —            |       | 482                              |       | (482                       | )          | —                               |       | —                                                    |       | —              |       | —                                |       |
| Amortization of  deferred stock-based compensation       |       | —                            |       | —                              |       | —            |       | —                           |       | 84                         |       | —                               |       | —                                                    |       | —              |       | 84                                    |       |
| Stock options  converted to restricted stock             |       | —                            |       | —                              |       | —            |       | 66                               |       | —                     |       | —                               |       | —                                                    |       | —              |       | 66                                    |       |
| Cashless stock  options                                  |       | 21                                |       | —                              |       | —            |       | 965                              |       | —                     |       | —                               |       | —                                                    |       | —              |       | 965                                   |       |
| Treasury stock  acquired                                 |       | —                            |       | (7                                  | )          | —            |       | —                           |       | —                     |       | —                               |       | —                                                    |       | (161                | )          | (161                                  | )          |
| Contribution of  treasury shares to  401(k) benefit plan |       | —                            |       | 12                                  |       | —            |       | 124                              |       | —                     |       | —                               |       | —                                                    |       | 72                  |       | 196                                   |       |
| Net loss                                                 |       | —                            |       | —                              |       | —            |       | —                           |       | —                     |       | (6,802                               | )          | —                                                    |       | —              |       | (6,802                                | )          |
| Dividends                                                |       | —                            |       | —                              |       | —            |       | (4,315                           | )          | —                     |       | —                               |       | —                                                    |       | —              |       | (4,315                                | )          |
| Other  comprehensive income                              |       | —                            |       | —                              |       | —            |       | —                           |       | —                     |       | —                               |       | 111                                                       |       | —              |       | 111                                   |       |
| Balance, December  31, 2005                              |       |                              | 10,858     |                                | (56        | )                 | $          | 108                              |       | $                          | 48,797     |                                 | $          | (398                                                      | )          | $                   | (8,425     | )                                     | $          | 357 |   | $ | (457 | ) | $ | 39,982 |   |
|                                                          |            |                                   |            |                                     |            |                   |            |                                  |            |                            |            |                                      |            |                                                           |            |                     |            |                                       |            |  |  |  |  |  |  |  |  |

# ** **

# **The accompanying notes are an integralpart of these consolidated financial statements.**

#  

55

----

 

**MARKWESTHYDROCARBON, INC**.

**CONSOLIDATED STATEMENTS OF CASH FLOWS**

**(in thousands)**

 
| ** **                                                                                            | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                            | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                                                            | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Cash flows from operating activities:**                                                             |       |                                       |       |   |   |   |   |
| Net loss                                                                                              |       | $                                          | (6,802     | ) | $ | (903 | ) | $ | (11,006 | ) |
| Adjustments to reconcile net loss to net  cash provided by operating activities:                      |       |                                       |       |   |   |   |   |
| Cumulative effect of change in accounting  principle                                                  |       | —                                     |       | — |   | 29 |   |
| Depreciation and depletion                                                                            |       | 20,829                                     |       | 16,895 |   | 24,489 |   |
| Amortization of intangible assets                                                                     |       | 9,656                                      |       | 3,640 |   | — |   |
| Amortization of deferred financing costs                                                              |       | 6,979                                      |       | 5,281 |   | 2,104 |   |
| Amortization of gas contract                                                                          |       | 312                                        |       | 78 |   | — |   |
| Accretion of asset retirement obligation                                                              |       | 160                                        |       | 15 |   | — |   |
| Impairments                                                                                           |       | —                                     |       | 130 |   | 2,187 |   |
| Non-controlling interest in net income of  consolidated subsidiary                                    |       | 91                                         |       | 7,315 |   | 2,988 |   |
| Equity in loss of investees                                                                           |       | 2,153                                      |       | 73 |   | — |   |
| Distribution from Starfish                                                                            |       | 1,849                                      |       | — |   | — |   |
| Unrealized losses/(gains) on derivative  instruments                                                  |       | —                                     |       | 762 |   | (3,188 | ) |
| Deferred income taxes                                                                                 |       | (2,358                                     | )          | 39 |   | (2,139 | ) |
| Stock option compensation expense                                                                     |       | 965                                        |       | 1,994 |   | — |   |
| Restricted stock compensation expense                                                                 |       | 150                                        |       | — |   | — |   |
| Restricted unit compensation expense                                                                  |       | 1,076                                      |       | 1,065 |   | 1,357 |   |
| Participation Plan compensation expense                                                               |       | 3,244                                      |       | 3,711 |   | 1,303 |   |
| Contribution of treasury shares to 401(k)  benefit plan                                               |       | 196                                        |       | 192 |   | 208 |   |
| 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 from sale of property, plant and  equipment                                                      |       | (407                                       | )          | (63 | ) | — |   |
| Gain from sale of marketable securities                                                               |       | (56                                        | )          | (37 | ) | — |   |
| Reclassification of Enron hedges to  purchased product costs                                          |       | —                                     |       | — |   | (153 | ) |
| Other                                                                                                 |       | —                                     |       | (1 | ) | — |   |
|                                                                                                  |       |                                       |       |   |   |   |   |
| Changes in operating assets and  liabilities, net of working capital acquired in acquisitions:        |       |                                       |       |   |   |   |   |
| Increase in receivables                                                                               |       | (1,372                                     | )          | (34,946 | ) | (390 | ) |
| Increase in inventories                                                                               |       | (17,420                                    | )          | (5,744 | ) | (1,201 | ) |
| Increase in prepaid replacement natural gas  and other assets                                         |       | (322                                       | )          | (4,305 | ) | (7,380 | ) |
| Increase in other current assets                                                                      |       | (14,742                                    | )          | (1,395 | ) | — |   |
| Decrease in notes receivables from officers                                                           |       | 53                                         |       | 10 |   | — |   |
| Decrease in other assets                                                                              |       | —                                     |       | 28 |   | — |   |
| Increase in accounts payable and accrued  liabilities                                                 |       | 12,640                                     |       | 32,299 |   | 8,210 |   |
| Increase (decrease) in other long-term  liabilities                                                   |       | —                                     |       | 483 |   | (7,190 | ) |
| Net cash provided by (used in) operating  activities                                                  |       | 16,874                                     |       | 26,616 |   | (6,411 | ) |
|                                                                                                  |       |                                       |       |   |   |   |   |
| **Cash flows from investing activities:**                                                             |       |                                       |       |   |   |   |   |
| Decrease (increase) in restricted  marketable securities                                              |       | —                                     |       | 2,500 |   | (2,500 | ) |
| Decrease (increase) in restricted cash                                                                |       | 15,000                                     |       | (15,000 | ) | — |   |
| Purchase of marketable securities                                                                     |       | (8,725                                     | )          | (15,053 | ) | — |   |
| Proceeds from sale of marketable securities                                                           |       | 17,275                                     |       | 1,092 |   | — |   |
| Javelina acquisition, net of cash acquired                                                            |       | (356,917                                   | )          | — |   | — |   |
| 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                                                                                  |       | (71,343                                    | )          | (30,654 | ) | (31,007 | ) |
| 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                                                  |       | 550                                        |       | 216 |   | 2,517 |   |
| Payment on long-term gas purchase contracts                                                           |       | —                                     |       | (3,250 | ) | — |   |
| Investment in equity affiliate                                                                        |       | (41,688                                    | )          | — |   | (250 | ) |
| Net cash used in investing activities                                                                 |       | (445,848                                   | )          | (303,017 | ) | (36,887 | ) |
|                                                                                                  |       |                                       |       |   |   |   |   |
| **Cash flows from financing activities:**                                                             |       |                                       |       |   |   |   |   |
| Payments for deferred offering costs                                                                  |       | —                                     |       | — |   | (389 | ) |
| Proceeds from long-term debt                                                                          |       | 910,500                                    |       | 220,100 |   | 452,778 |   |
| Repayments of long-term debt                                                                          |       | (524,000                                   | )          | (346,300 | ) | (373,925 | ) |
| Proceeds from private placement of senior  notes                                                      |       | —                                     |       | 225,000 |   | — |   |
| Proceeds from secondary public offerings,  net                                                        |       | —                                     |       | 139,630 |   | — |   |
| Payments for debt issuance costs                                                                      |       | (11,809                                    | )          | (15,643 | ) | (4,070 | ) |
| Proceeds from MarkWest Energy’s private  placements, net                                         |       | 92,887                                     |       | 44,139 |   | 9,774 |   |
| Distributions to MarkWest Energy  unitholders                                                         |       | (26,081                                    | )          | (15,350 | ) | (7,214 | ) |
| Payment of dividends                                                                                  |       | (4,315                                     | )          | (5,828 | ) | — |   |
| Exercise of stock options                                                                             |       | 77                                         |       | 1,392 |   | 1,899 |   |
| Purchase of treasury shares                                                                           |       | (161                                       | )          | (39 | ) | (390 | ) |
| Proceeds from sale of MarkWest Energy units                                                           |       | —                                     |       | — |   | 493 |   |
| Net cash provided by financing activities                                                             |       | 437,098                                    |       | 247,101 |   | 78,956 |   |
|                                                                                                  |       |                                       |       |   |   |   |   |
| Effect of exchange rate on changes on cash                                                            |       | —                                     |       | — |   | 76 |   |
|                                                                                                  |       |                                       |       |   |   |   |   |
| Net increase (decrease) in cash and cash  equivalents                                                 |       | 8,124                                      |       | (29,300 | ) | 35,734 |   |
| Cash and cash equivalents at beginning of  year                                                       |       | 12,844                                     |       | 42,144 |   | 6,410 |   |
| Cash and cash equivalents at end of year                                                              |       | $                                          | 20,968     |   | $ | 12,844 |   | $ | 42,144 |   |
|                                                                                                  |       |                                       |       |   |   |   |   |
| **Supplemental disclosures of cash flow  information:**                                               |       |                                       |       |   |   |   |   |
| Cash paid (received) during the year for:                                                             |       |                                       |       |   |   |   |   |
| Interest, net of amounts capitalized                                                                  |       | $                                          | 22,225     |   | $ | 6,532 |   | $ | 3,868 |   |
| Income taxes                                                                                          |       | 549                                        |       | — |   | (114 | ) |
|                                                                                                  |       |                                       |       |   |   |   |   |
| **Supplemental disclosures of non-cash  investing and financing activities:**                         |       |                                       |       |   |   |   |   |
| Construction projects in process obligation                                                           |       | $                                          | 1,545      |   | $ | 4,037 |   | — |   |
| Property, plant and equipment asset  retirement obligation                                            |       | 561                                        |       | 377 |   | 3,994 |   |
| Deferred offering costs                                                                               |       | —                                     |       | — |   | 606 |   |
| Accrued amounts due to Javelina sellers and  Starfish                                                 |       | 6,888                                      |       | — |   | — |   |
| Accrued private placement proceeds                                                                    |       | 5,000                                      |       | — |   | — |   |

 

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

 

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**MARKWEST HYDROCARBON, INC.**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**1.****             ****Organization**

 

MarkWest Hydrocarbon, Inc. (“MarkWestHydrocarbon”) manages MarkWest Energy Partners, L.P. (“MarkWest Energy Partners”or the “Partnership”), a publicly traded master limited partnership, engaged inthe gathering, processing and transmission of natural gas; the transportation,fractionation and storage of natural gas liquids (“NGLs”); and the gatheringand transportation of crude oil.   The Company also markets naturalgas and NGLs. MarkWest Hydrocarbon and MarkWest Energy Partners provideservices primarily in Appalachia, Michigan, East Texas, Western Oklahoma andother areas of the southwest.  Through eight acquisitions completed during2003, 2004 and 2005, the Company expanded its natural gas-gathering, processingand transmission geographic coverage to the southwest United States.  In addition, one of the Company’s acquisitionshas allowed it to enter into the Michigan crude oil transportationbusiness.  The Company’s principalexecutive office is located in Englewood, Colorado.

 

**2.****             ****Summary****of Significant AccountingPolicies**

 

*Basisof Presentation*

 

Theaccompanying consolidated financial statements include the accounts of MarkWestHydrocarbon, Inc., MarkWest Energy Partners, L.P. and all of its majority-ownedsubsidiaries (collectively “the Company”) and have been prepared in accordancewith accounting principles generally accepted in the United States of America (“GAAP”).   The Company’s consolidated financialstatements include the accounts of all majority-owned subsidiaries.  Equity investments in which the Companyexercises significant influence, but does not control and is not the primarybeneficiary, are accounted for using the equity method.  Intercompany balances and transactionshave been eliminated.

 

*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-controllinginterest in net income of consolidated subsidiary in the consolidated statementof operations represents those partners’ share of the net income of thePartnership.**

 

###### *Use ofEstimates*

###### * *

The preparation of financial statements inconformity with GAAP requires management to make estimates and assumptions thataffect the reported amounts of assets and liabilities, disclosure of contingentassets and liabilities at the date of the financial statements, and thereported amounts of revenues and expenses during the reporting period. Actualresults could differ from those estimates. Estimates are used in accounting for, among other items, valuingidentified intangible assets, determining the fair value of derivative instruments,evaluating impairments of long lived assets, establishing estimated usefullives for long-lived assets, valuing asset retirement obligations, and indetermining liabilities, if any, for legal contingencies.

 

*Cash and Cash Equivalents*

 

The Company considers investments in highlyliquid financial instruments purchased with an original maturity of 90 days orless to be cash equivalents.  Suchinvestments include money market accounts.

 

*Restricted Cash*

 

Under the Company’s credit facility, it can berequired to keep a minimum available cash and/or marketable securities reserveof $15.0 million, which is to be reduced to zero in the event the Companyrestructures a keep-whole contract with one of its significant customers.

 

*Inventories*

 

Inventories are valued at the lower of weighted average cost ormarket.  Inventories consisting primarilyof crude oil and unprocessed natural gas are valued based on the cost of theraw material.  Processed natural gasinventories include material, labor and overhead.  Shipping and handling costs are included inoperating expenses.

 

*Prepaid Replacement NaturalGas*

 

Prepaid replacement natural gas consists ofnatural gas purchased in advance of its actual use valued using the weightedaverage cost method.

 

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###### *Property,Plant and Equipment*

###### * *

Property, plant and equipment are recorded at cost.  Expenditures that extend the useful lives ofassets are capitalized.  Repairs,maintenance and renewals that do not extend the useful lives of the assets areexpensed as incurred.  Interest costs forthe construction or development of long-term assets are capitalized andamortized over the related asset’s estimated useful life.  Leasehold improvements are depreciated overthe shorter of the useful life or lease term. Depreciation is provided principally on the straight-line method overthe following estimated useful lives:

 

| **Asset Class**                 | ** ** | **Range of  Estimated  Useful Lives** | ** ** |
|--------------------------------------|------------|-------------------------------------------------|------------|
| Buildings                            |       | 20 – 25 years                              |       |
| Gas gathering facilities             |       | 20 – 25 years                              |       |
| Gas processing plants                |       | 20 – 25 years                              |       |
| Fractionation and storage facilities |       | 20 – 25 years                              |       |
| Natural gas pipelines                |       | 20 – 25 years                              |       |
| Crude oil pipelines                  |       | 20 – 25 years                              |       |
| NGL transportation facilities        |       | 20 – 25 years                              |       |
| Equipment and other                  |       | 3 – 10 years                               |       |

 

The Company recognizes the fairvalue of a liability for an asset retirement obligation in the period in whichthe liability is incurred, with an offsetting increase in the carrying amountof the related long-lived asset.  Overtime, the liability is accreted to its future value, and the capitalized costis depreciated over the useful life of the related asset.  Upon settlement of the liability, an entityeither settles the obligation for its recorded amount or incurs a gain or loss.  The Company adopted FIN 47, *Accounting for Conditional Asset RetirementObligations*, on January 1, 2005. FIN 47 clarified the accounting for conditional asset retirementobligations under SFAS 143, *Accounting forAsset Retirement Obligations*. A conditional asset retirement obligation is an unconditional legal obligationto perform an activity in which the timing and / or method of settlement areconditional on a future event that may or may not be within the control of theentity.  FIN 47 requires an entity torecognize a liability for a conditional asset retirement obligation if theamount can be reasonably estimated. Adopting FIN 47 had an immaterial impact on the Company**.**

 

###### *Investmentin Starfish*

######  

On March 31, 2005, the Partnership acquired its non-controlling, 50%interest in Starfish Pipeline Company, LLC (“Starfish”) for $41.7 million,which is accounted for under the equity method. Differences between the Partnership’s investment and its proportionateshare of Starfish’s reported equity are amortized based upon the respectiveuseful lives of the assets to which the differences relate.  For the year ended December 31, 2005, thePartnership received dividends of $1.8 million, and accrued $1.5 million for acapital call.  The Partnership’s share ofStarfish’s loss in 2005 was $2.2 million.

 

The Partnership’s accounting policy requires it to evaluate operatinglosses, if any, and other factors that may have occurred, that may beindicative of a decrease in value of the investment which is other thantemporary, and which should be recognized even though the decrease in value isin excess of what would otherwise be recognized by application of the equitymethod.  The evaluation allows thePartnership to determine if an equity method investment should be impaired andthat an impairment, if any, is fairly reflected in its financial statements

 

The Partnership believes the equity method is an appropriate means forit to recognize increases or decreases measured by GAAP in the economicresources underlying the investments. Regular evaluation of these investments is appropriate to evaluate anypotential need for impairment.  It usesthe following types of triggers to identify a loss in value of an investmentthat is other than a temporary decline. Examples of a loss in value may be identified by:

 

•                  Aninability to recover the carrying amount of the investment;

•                  Acurrent fair value of an investment that is less than its carrying amount; and

•                  Otheroperational criteria that cause us to believe the investment may be worth lessthan otherwise accounted for by using the equity method.

 

*Intangible Assets*

 

The Company’s intangible assets are comprisedof customer contracts and relationships acquired in business combinations,recorded under the purchase method of accounting at their estimated fair valuesat the date of acquisition.  Usingrelevant information and assumptions, management determines the fair value ofacquired identifiable intangible assets. Fair value is generally calculated as the present value of estimatedfuture cash flows using a risk-adjusted discount rate.  The key assumptions include contract renewals,economic incentives to retain customers, historical volumes, current and futurecapacity of the gathering system, pricing volatility, and the discount rate.  Amortization of intangibles with definitelives is calculated using the straight-line method over the estimated usefullife of the intangible asset.  Theestimated economic life is determined by assessing the life of the assets towhich the contracts / relationships relate, likelihood of renewals, competitivefactors, regulatory or legal provisions, and maintenance and renewal costs.

 

###### *Impairment ofLong-Lived Assets*

###### * *

The Company evaluates its long-lived assets,including intangibles, for impairment when events or changes in circumstanceswarrant such a review.  A long-livedasset group is considered impaired when the estimated undiscounted cash flowsfrom such asset group is less than the asset group’s carrying value.  In that event, a loss is recognized to theextent that the carrying value exceeds the fair value of the long-lived assetgroup.  Fair value is determinedprimarily using estimated discounted cash flows.  Management considers the volume of reservesbehind the asset and future NGL product and natural gas prices to estimate cashflows. The amount of additional reserves developed by future drilling activitydepends, in part, on expected natural gas prices.  Projections of reserves, drilling activityand future commodity prices are inherently subjective and contingent upon anumber of variable factors, many of which are difficult to forecast.  Any significant variance in any of theseassumptions or factors could materially affect future cash flows, which couldresult in the impairment of an asset.

 

For assets identified to be disposed of inthe future, the carrying value of these assets is compared to the estimatedfair value, less the cost to sell, to determine if impairment is required.Until the assets are disposed of, an estimate of the fair value isre-determined when related events or circumstances change.

 

*Deferred FinancingCosts*

 

Deferred financing costs,included in Other assets, are amortized over the estimated lives of the relatedobligations

 

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or, in certaincircumstances, accelerated if the obligation is refinanced.

 

*Deferred Contract Costs*

 

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.  Amortization related to these contracts forthe years ended December 31, 2005 and 2004 was $0.4 million and $0.1 million,respectively.

 

*Deferred income*

 

Deferred income represents prepayments receivedunder fixed fee contracts to deliver NGLs at a future date.  Deferredincome is recognized as revenue upon delivery of the product.

 

*DerivativeInstruments*

 

SFAS No. 133, *Accounting for DerivativeInstruments and Hedging Activities,* established accounting andreporting standards requiring that derivative instruments (including certainderivative instruments embedded in other contracts) be recorded at fair valueand included in the consolidated balance sheet as assets or liabilities.  The accounting for changes in the fair valueof a derivative instrument depends on the intended use of the derivative andthe resulting designation, which is established at the inception.  To the extent derivative instrumentsdesignated as cash flow hedges are effective, changes in fair value arerecognized in other comprehensive income until the underlying hedged item isrecognized in earnings.  Effectiveness isevaluated by the derivative instrument’s ability to offset changes in fairvalue or cash flows of the underlying hedged item.  Any change in the fair value resulting fromineffectiveness is recognized immediately in earnings.  Changes in the fair value of derivativeinstruments designated as fair value hedges, as well as the changes in the fairvalue of the underlying hedged item, are recognized currently in earnings.  Any differences between the changes in thefair values of the hedged item and the derivative instrument represent gains orlosses from ineffectiveness.  To theextent that the Company elects hedge accounting treatment for specificderivatives, the Company formally documents, designates and assesses theeffectiveness.  As of December 31, 2005,no transactions had been designated for hedge accounting treatment.  In general, the Company exempts thosecontracts that qualify as normal purchase and sale contacts from themark-to-market requirements of SFAS 133. All other derivative instruments are marked-to-market through revenue.

 

*Treasury Stock*

 

Treasury stock purchases are accounted for underthe cost method, whereby the entire cost of the acquired stock is recorded astreasury stock.  Treasury stock reissuedis relieved on a weighted average cost basis.

 

###### *Fair Value ofFinancial Instruments*

###### * *

Management believes the carrying amount of financial instruments, includingcash, accounts receivable, accounts payable, accrued expenses, and otherfinancial instruments approximates fair value because of the short-termmaturity of these instruments. Management believes the carrying value of MarkWest Hydrocarbon’s CreditFacility and the Partnership’s Credit Facility (Note 11) approximates fairvalue due to their variable interest rates. The estimated fair value of the Partnership’s Senior Notes (Note 11) wasapproximately $207.0 million and $225.0 million at December 31, 2005 and 2004,respectively, based on quoted market prices. Derivative instruments not designated as hedges (Note 12) are recordedat fair value, based on available market information.

 

*Revenue Recognition*

 

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 

 

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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 anddeemed line losses.  To the extent thePartnership’s gathering systems are operated more efficiently than specifiedper contract allowance, it is entitled to retain the difference for its ownaccount.

 

•      *Condensate sales* - During the gathering process, thermodynamicforces contribute to changes in operating conditions of the natural gas flowingthrough the pipeline infrastructure.  Asa result, hydrocarbon dew points are reached, causing condensation of hydrocarbonsin the high-pressure pipelines.  Underthose arrangements, condensate collected in the system is retained by us and soldat market prices.

 

Under all six arrangements, revenue isrecognized at the time the product is delivered and title is transferred.  It is upon delivery and title transfer thatthe Partnership meets all four revenue recognition criteria, and it is at suchtime that the Partnership recognizes revenue.

 

The Partnership’s assessment of each of thefour revenue recognition criteria as they relate to its revenue producingactivities is as follows:

 

*Persuasive evidenceof an arrangement exists.*The Partnership’s customary practice is to enter into a writtencontract, executed by both the customer and the Partnership.

 

*Delivery.*Delivery isdeemed to have occurred at the time the product is delivered and title istransferred, or in the case of fee-based arrangements, when the services arerendered.  To the extent we retain our equity liquids as inventory,delivery occurs when the inventory is subsequently sold and title istransferred to the third party purchaser.

 

*The fee is fixed or determinable.*The Partnership negotiates the fee for its services at the outset of itsfee-based arrangements. In these arrangements, the fees are nonrefundable. Thefees are generally due within ten days of delivery or services rendered.  For other arrangements, the amount of revenueis determinable when the sale of the applicable product has been completed upondelivery and transfer of tile. Proceeds from the sale of products are generallydue in ten days.

 

*Collectibility is probable.* Collectibility is evaluated on a customer-by-customerbasis. New and existing customers are subject to a credit review process, whichevaluates the customers’ financial position (e.g. cash position and creditrating) and their ability to pay. If collectibility is not considered probableat the outset of an arrangement in accordance with the Partnership’s creditreview process, revenue is recognized when the fee is collected.

 

Certain revenue from sales of customer gas to a third-party processoris recognized net, under EITF 99-19, *ReportingRevenue Gross as a Principal versus Net as an Agent,*as thePartnership earns a fixed amount and does not take ownership of the gas.

 

Gas volumes received may be different from gas volumes delivered,resulting in gas imbalances.  ThePartnership records a receivable or payable for such imbalances based upon thecontractual terms of the purchase agreements. The Partnership had an imbalance payable of $2.6 million and $0.1million and an imbalance receivable of $2.7 million and $1.4 million atDecember 31, 2005 and 2004, respectively. Revenues for the transportation of crude are based upon regulated tariffrates and the related transportation volumes and are recognized when deliveryof crude is made to the purchaser or other common carrier pipeline.  As described above, changes in the fair valueof commodity derivative instruments are recognized currently in revenue.

 

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***Stock and Incentive Compensation Plans***

** **

The Company has elected to continue to measurecompensation costs for equity-based employee compensation plans as prescribedby Accounting Principles Board (“APB”) No. 25, *Accountingfor Stock Issued to Employees,*as permitted under SFAS No. 123, *Accounting for Stock Based Compensation*,and SFAS No. 148, *Accounting for Stock-BasedCompensation — Transition and Disclosure.*

 

Stock options are issued under the Company’s1996 Stock Incentive Plan and 1996 Non-employee Director Stock OptionPlan.  The plans allow for the exercise of stock options using thecashless method, but only at the discretion of the Company.  Under acashless exercise, the Company withholds those 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 theemployees.  Prior to April 2004, the Company did not allow participants toexercise their stock options using the cashless method.  Accordingly,compensation expense was not recognized for stock options granted unless the optionswere granted at an exercise price less than the quoted market price of theCompany on the grant date.  In April 2004, the Company changed its policyto allow participants to exercise their stock options using the cashlessmethod.  Under APB No. 25, a fixed stock option plan that permits the useof a cashless exercise becomes variable if a pattern of exercising the stockoptions using the cashless method is demonstrated.  As a result, in April2004, the Company was required to account for stock options issued under theplans as variable awards.  Compensation expense for stock options issuedas variable awards is measured as the difference in the market value of theCompany’s common stock and the exercise price of the stock options.  Thedifference is amortized into earnings over the period of service as the optionsvest, adjusted quarterly for the change in the fair value of the unvested stockoptions awarded.  Increases or decreases in the market value of theCompany’s common stock between April 2004 and the end of each reporting periodresult in a change in the measure of compensation for vested awards, which isreflected currently in operations in selling, general and administrativeexpenses.

 

The Company also issues restricted stock underthe Company’s 1996 Stock Incentive Plan and 1996 Non-employee Director StockOption Plan.  In accordance with APB No. 25, the Company applies fixedaccounting for the plans. As a result, since the restricted stock is grantedfor no consideration, compensation expense is recognized on the date of grantequal to the market price of the Company’s common stock.  The fair valueof the stock awarded is amortized into earnings over the period ofservice.  The restricted stock vests over a stated period.  These charges are included in selling,general and administrative expenses.

 

The Company has also entered into arrangementswith certain directors and employees of the Company referred to as theParticipation Plan.  Periodically, the Company sells subordinatedpartnership units of the Partnership, and interests in the Partnership’sgeneral partner, to employees and directors of the Company under a purchase andsale agreement.  In accordance with the provisions of APB No. 25, theParticipation Plan is accounted for as a variable plan.  Since theemployees and directors are 100% vested (except for two non-executives who haverestricted general partnership interests) on the date they purchase thesubordinated units or general partner interests, compensation expense for thesubordinated units is measured as the difference in the market value of thesubordinated Partnership units and the amount paid by those individuals.  Compensation related to the general partnerinterest is calculated as the difference in the formula value and the amountpaid by those individuals.  The formulavalue is the amount MarkWest Hydrocarbon would have to pay the directors andemployees to repurchase the general partner interests and is based on thecurrent market value of the Partnership’s common units and the currentquarterly distribution paid. Increases or decreases in the market value of thesubordinated units and the formula value of the general partner interestsbetween the date they are acquired and the end of each reporting period resultin a change in the measure of compensation, which is reflected currently inoperations.

 

Under Topic 1-B of the codification of theStaff Accounting Bulletins, Allocation of Expenses And Related Disclosure inFinancial Statements of Subsidiaries, Divisions or Lesser Business Componentsof Another Entity, compensation expense related to services provided byMarkWest Hydrocarbon’s employees and directors recognized under theParticipation Plan should be allocated to the Partnership.  The allocation is based on the percent oftime that each employee devotes to the Company. Compensation attributable to interests that were sold to individuals whoserve on both the board of MarkWest Hydrocarbon and the Partnership’s board ofdirectors is allocated equally.

 

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 25, the Partnershipapplies variable accounting for the plan because a phantom unit is an award toemployees entitling them to increases in themarket value of the Partnership’s units subsequent to the date of grant withoutissuing units to the employees, similar to a stock appreciation right. As a result, the Partnership is required to mark to market the awardsat the end of each reporting period.  Compensationexpense is measured for the phantom unit grants using the market price of 

 

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MarkWest Energy Partners’ common units on the date the units aregranted. The fair value of the units awarded is amortized into earnings overthe period of service, adjusted quarterly for the change in the fair value ofthe unvested units granted.  The phantomunits vest over a stated period.  Vestingis accelerated for certain employees, if specified performance measures aremet.  The accelerated vesting criteriaprovisions are based on annualized distribution goals.  If the Partnership’s distributions are at orabove the goal for a certain number of consecutive quarters, vesting of theemployee’s phantom units is accelerated. The vesting of any phantom units, however, may not occur until at leastone year following the date of grant. The general partner of the Partnership may also elect to accelerate thevesting of outstanding awards, which results in an immediate charge tooperations for the unamortized portion of the award.

 

Had compensation cost for the Company’sstock-based and unit-based compensation plans been determined based on the fairvalue at the grant dates under those plans consistent with the methodprescribed by SFAS No. 123, *Accounting for Stock-BasedCompensation,*the Company’s net income and earnings per share wouldhave been reduced to the pro forma amounts listed below (in thousands, exceptper share data):

 
| ** **                                                                                                                                   | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                                                                   | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                                                                                                   | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net loss, as reported                                                                                                                        |       | $                                          | (6,802     | ) | $ | (903 | ) | $ | (11,006 | ) |
| Add: compensation expense included in  reported net loss                                                                                     |       | 6,341                                      |       | 6,770 |   | 2,701 |   |
| Deduct: total stock-based employee  compensation expense determined under fair value based method for all awards,  net of related tax effect |       | (5,215                                     | )          | (4,681 | ) | (2,927 | ) |
| Pro forma net income (loss)                                                                                                                  |       | $                                          | (5,676     | ) | $ | 1,186 |   | $ | (11,232 | ) |
|                                                                                                                                         |       |                                       |       |   |   |   |   |
| Net loss per share:                                                                                                                          |       |                                       |       |   |   |   |   |
| Basic, as reported                                                                                                                           |       | $                                          | (0.63      | ) | $ | (0.08 | ) | $ | (1.07 | ) |
| Basic, pro forma                                                                                                                             |       | $                                          | (0.53      | ) | $ | 0.11 |   | $ | (1.09 | ) |
| Diluted, as reported                                                                                                                         |       | $                                          | (0.63      | ) | $ | (0.08 | ) | $ | (1.07 | ) |
| Diluted, pro forma                                                                                                                           |       | $                                          | (0.53      | ) | $ | 0.11 |   | $ | (1.09 | ) |

 

*Income Taxes*

 

Deferred income taxes are recognized for theestimated future tax consequences attributable to differences between thefinancial statement carrying amounts of existing assets and liabilities andtheir respective tax bases using enacted tax rates.  A valuation allowance is provided fordeferred tax assets if it is more likely than not these items will expirebefore the Company is able to realize their benefit.

 

*Comprehensive Income*

 

Comprehensive income includes net income (loss)and other comprehensive income (loss), which includes unrealized gains andlosses on commodity or interest rate derivative financial instruments,accounted for as hedges, and unrealized gains or losses on marketablesecurities, accounted for as available for sale.

 

*Earnings (Loss) Per Share*

 

Basic earnings (loss) per share is computed onthe basis of the weighted average number of shares of common stock outstandingduring the period.  Diluted earnings pershare is computed on the basis of the weighted average number of shares ofcommon stock plus the effect of dilutive potential common shares outstandingduring the period using the treasury stock method. Dilutive potential commonshares include outstanding stock options and stock awards.  All shareinformation has been adjusted to give retroactive effect to stock dividendspaid, see Note 16.

 

The following are the number of shares used tocompute the basic and diluted earnings per share (in thousands):

 
| ** **                                          | ** ** | **Year ended December 31,** | ** ** |
|-----------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                          | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
|                                                |       |                                       |       |   |   |   |   |
| Basic earnings per share:                           |       |                                       |       |   |   |   |   |
| Weighted average shares outstanding                 |       | 10,785                                     |       | 10,686 |   | 10,328 |   |
| Dilutive earnings per share:                        |       |                                       |       |   |   |   |   |
| Weighed average shares outstanding                  |       | 10,785                                     |       | 10,686 |   | 10,328 |   |
| Dilutive effect of exercise of options  outstanding |       | 116                                        |       | 54 |   | 19 |   |
| Dilutive shares                                     |       | 10,901                                     |       | 10,740 |   | 10,347 |   |

 

62

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## ***Foreign Currency Translation***

##  

On December 2, 2003, the Company sold allof its Canadian subsidiaries and, consequently, no longer has assets,liabilities or operations that require foreign currency translation. Prior thereto, assets and liabilities of the Company’s Canadian subsidiary,which used the Canadian dollar as its functional currency, were translated intoUnited States dollars at the foreign currency exchange rate in effect at theapplicable reporting date, and the statements of operations data weretranslated at the average rates in effect during the applicable period. The resulting cumulative translation adjustment was recorded as a separatecomponent of other comprehensive income.

 

*Recent AccountingPronouncements*

 

In December 2004, the FASB issued SFASNo. 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)liabilities that are based on the fair value of the enterprise’s equityinstruments or that may be settled by the issuance of such equityinstruments.  SFAS No. 123(R) requires anentity to recognize the grant-date fair-value of stock options and otherequity-based compensation 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 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 123(R) is effective for public companiesfor the first fiscal year beginning after December 31, 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, which must be adopted in the first quarter ofcalendar year 2006.  On March 29,2005, the SEC staff issued SAB No. 107, *Share-BasedPayment*, to express the views of the staff regarding the interactionbetween SFAS No. 123(R) and certain SEC rules and regulations and to providethe staff’s views regarding the valuation of share-based payment arrangementsfor public companies.  The Company willtake into consideration the additional guidance provided by SAB 107 inconnection with the implementation of SFAS No. 123(R).

 

In May 2005, the FASB issued SFAS No. 154, *Accounting for Changes and Error Corrections – aReplacement of APB Opinion No. 20 and FASB Statement No. 3*(SFAS154).  SFAS 154 requires retrospective application of voluntary changes inaccounting principles, unless impracticable.  SFAS 154 supersedes theguidance in APB Opinion No. 20 and SFAS No. 3, but does not change anytransition provisions of existing pronouncements.  Generally, electiveaccounting changes will no longer result in a cumulative effect of a change inaccounting in the income statement, because the effects of any elective changeswill be reflected as prior period adjustments to all periods presented. SFAS 154 will be effective beginning in fiscal 2006 and will affect anyaccounting changes that we elect to make thereafter.

 

In February 2006, theFASB issued SFAS No. 155, *Accountingfor Certain Hybrid Financial Instruments—an amendment of FASB StatementsNo. 133 and 140* (“SFAS 155”). This statement amends SFASNo. 133, *Accounting for Derivative Instruments andHedging Activities* (“SFAS 133”), and SFAS No. 140, *Accounting for Transfers and Servicing of FinancialAssets and Extinguishments of Liabilities*and resolves issuesaddressed in SFAS 133 Implementation Issue No. D1, *Application of Statement 133 to Beneficial Interestin Securitized Financial Assets.* This Statement: (a) permitsfair value remeasurement for any hybrid financial instrument that contains anembedded derivative that otherwise would require bifurcation;(b) clarifies which interest-only strips and principal-only strips are notsubject to the requirements of SFAS 133; (c) establishes a requirement toevaluate beneficial interests in securitized financial assets to identifyinterests that are freestanding derivatives or that are hybrid financialinstruments that contain an embedded derivative requiring bifurcation;(d) clarifies that concentrations of credit risk in the form ofsubordination are not embedded derivatives; and, (e) eliminates restrictionson a qualifying special-purpose entity’s ability to hold passive derivativefinancial instruments that pertain to beneficial interests that are or containa derivative financial instrument. The standard also requires presentationwithin the financial statements that identifies those hybrid financialinstruments for which the fair value election has been applied and informationon the income statement impact of the changes in fair value of thoseinstruments. The Companyisrequired to apply SFAS 155 to all financial instruments acquired, issued orsubject to a remeasurement event beginning January 1, 2007, although earlyadoption is permitted as of the beginning of an entity’s fiscal year. Theprovisions of SFAS 155 are not expected to have an impact recorded at adoption.

 

63

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***3.*****             ****Acquisitions by MarkWest Energy Partners**

 

*Javelina Acquisition*

 

On November 1, 2005, for consideration of$357.0 million, plus $41.3 million for net working capital, the Partnershipacquired equity interests in Javelina Company, Javelina Pipeline Company andJavelina Land Company, L.L.C., which were 40%, 40% and 20%, respectively, ownedby subsidiaries of El Paso Corporation, Kerr-McGee Corporation, and ValeroEnergy Corporation.  The Corpus Christi,Texas, gas-processing facility treats and processes off-gas from six localrefineries.  The facility was constructedin 1989 to recover up to 28,000 barrels per day of NGLs.  The facility currently processesapproximately 125 to 130 MMcf/d of inlet gas, but it is expected to process upto its capacity of 142 MMcf/d as refinery output continues to grow.  The Partnership and the seller are still negotiatingthe final value of the acquired working capital, so the purchase price maychange upon settlement.

 

*Starfish JointVenture*

 

On March 31,2005, the Partnership completed the acquisition of a 50% non-operatingmembership interest in Starfish Pipeline Company, LLC, (“Starfish”) from anaffiliate of Enterprise Products Partners L.P. for $41.7 million.  During the first quarter of 2005, thePartnership borrowed $40.0 million from its credit facility to finance theacquisition.  Starfish is a joint venturewith Enbridge Offshore Pipelines LLC, which the Partnership accounts for usingthe equity method.  Starfish owns theFERC-regulated Stingray natural gas pipeline, and the unregulated Tritonnatural gas-gathering system and West Cameron dehydration facility.  All are located in the Gulf of Mexico andsouthwestern Louisiana.

 

*East Texas SystemAcquisition*

 

OnJuly 30, 2004, the Partnership completed the East Texas System acquisitionof American Central Eastern Texas’ Carthage gathering system and gas-processingassets, located in East Texas, for approximately $240.7 million.  The Partnership’s consolidated financialstatements include the results of operations of the Carthage gathering systemfrom July 30, 2004.  The acquiredassets consist of processing plants, gathering systems, a processing facilitycurrently under construction and an NGL pipeline.

 

In conjunction with the closing of theacquisition, the Partnership completed a private offering of 1,304,438 commonunits, at $34.50 per unit, representing approximately $45.0 million in proceedsafter transaction costs of approximately $0.9 million and including acontribution from the general partner of $0.9 million to maintain its ownershipinterest.  In addition, the Partnershipamended and restated the credit facility, increasing the maximum lending limitfrom $140.0 million to $315.0 million. The credit facility included a $265.0 million revolving facility and a$50.0 million term loan facility.  ThePartnership used the proceeds from the private offering and borrowings of$195.7 million under the credit facility to finance the East Texas Systemacquisition.

 

###### *Hobbs LateralAcquisition*

###### * *

*On April 1,2004, the Partnership acquired the Hobbs Lateral pipeline for approximately$2.3 million.  The Hobbs Lateralconsisted of a four-mile pipeline, with a capacity of 160 million cubic feet ofnatural gas per day, connecting the Northern Natural Gas interstate pipeline toSouthwestern Public Service’s Cunningham and Maddox power-generating stationsin Hobbs, New Mexico.  The Hobbs Lateralis a New Mexico intrastate pipeline regulated by the Federal Energy Regulatory Commission.*

 

###### *Michigan CrudePipeline*

###### * *

On December 18, 2003, the Partnershipcompleted the acquisition of Shell Pipeline Company, LP’s and EquilonEnterprises, LLC’s Michigan Crude Gathering Pipeline, for approximately $21.3million. The results of operations of the system have been included in thePartnership’s consolidated financial statements since December 18, 2003.The $21.3 million purchase price was financed through borrowings under thePartnership’s line of credit.

 

The system is a common carrier Michiganpipeline and gathers light crude oil from wells.  The system extends from production facilitiesnear 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 a third-party Lakehead Pipeline, which then transports thecrude oil to refineries in Sarnia, Ontario, Canada.

 

###### *WesternOklahoma Acquisition*

###### * *

On December 1, 2003, thePartnership completed the acquisition of American Central Western Oklahoma GasCompany, L.L.C. for approximately $38.0 million, financed through borrowingsunder the credit facility.  Results ofoperations of the acquired assets have been included in the Partnership’sconsolidated financial statements since that date.

 

64

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The assets acquired include theFoss Lake gathering and processing system located in the Western Oklahomacounties of Roger Mills and Custer.  Theacquired gathering system was comprised of approximately 167 miles of pipeline,connected to approximately 270 wells, and 11,000 horsepower of compressionfacilities.  The assets also included theArapaho gas processing plant.

 

###### *LubbockPipeline Acquisition*

###### * *

Effective September 2, 2003, thePartnership, through its wholly owned subsidiary, MarkWest Pinnacle L.P.,completed the acquisition of a 68-mile intrastate gas transmission pipelinenear Lubbock, Texas, from a subsidiary of ConocoPhillips for approximately$12.2 million. The transaction was financed through borrowings under thecredit facility. The results of operations of the Lubbock Pipeline have beenincluded in the Partnership’s consolidated financial statements since thatdate.

 

###### *PinnacleAcquisition*

###### * *

On March 28, 2003, the Partnership completed the acquisition ofPinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG TransmissionCompany, Inc., PNG Utility Company and Bright Star Gathering, Inc.(collectively, “Pinnacle”).  The assetsacquired were comprised of three lateral natural gas pipelines and twentygathering systems. Pinnacle’s results of operations have been included in thePartnership’s consolidated financial statements since that date.  The purchase price of $39.9 million wasfinanced through borrowing under the Partnership’s line of credit.

 

The following table summarizes the costs and allocations of the aboveacquisitions (in thousands):

 
| ** **                           | ** ** | **Pinnacle** | ** ** | **Lubbock  Pipeline** | ** ** | **Western  Oklahoma** | ** ** | **Michigan  Crude  Pipeline** | ** ** | **Hobbs  Lateral** | ** ** | **East Texas** | ** ** | **Javelina** | ** ** |
|--------------------------------------|------------|--------------|------------|-----------------------|------------|-----------------------|------------|-------------------------------|------------|--------------------|------------|---------------------|------------|--------------|------------|
| **Acquisition  Costs:**              |       |         |       |                  |       |                  |       |                          |       |               |       |                |       |         |       |
| Cash consideration                   |       | $            | 39,471     |                  | $          | 12,200                |       | $                             | 37,850     |               | $          | 21,155              |       | $            | 2,300      |   | $ | 240,269 |   | $ | 396,336 |   |
| Direct acquisition costs             |       | 450          |       | —                |       | 101                   |       | 128                           |       | —             |       | 457                 |       | 2,009        |       |
| **Totals:**                          |       | $            | 39,921     |                  | $          | 12,200                |       | $                             | 37,951     |               | $          | 21,283              |       | $            | 2,300      |   | $ | 240,726 |   | $ | 398,345 |   |
|                                 |       |         |       |                  |       |                  |       |                          |       |               |       |                |       |         |       |
| **Allocation of acquisition costs:** |       |         |       |                  |       |                  |       |                          |       |               |       |                |       |         |       |
| Current Assets                       |       | $            | 10,643     |                  | $          | —                |       | $                             | —     |               | $          | —              |       | $            | —     |   | $ | 65 |   | $ | 111,679 |   |
| Customer contracts and relationships |       | —       |       | —                |       | —                |       | —                        |       | —             |       | 165,379             |       | 194,150      |       |
| Property, plant and equipment        |       | 38,223       |       | 12,200                |       | 37,951                |       | 21,283                        |       | 2,300              |       | 76,012              |       | 162,859      |       |
| Liabilities assumed                  |       | (8,945       | )          | —                |       | —                |       | —                        |       | —             |       | (730                | )          | (70,343      | )          |
| **Totals:**                          |       | $            | 39,921     |                  | $          | 12,200                |       | $                             | 37,951     |               | $          | 21,283              |       | $            | 2,300      |   | $ | 240,726 |   | $ | 398,345 |   |
|                                      |            |              |            |                       |            |                       |            |                               |            |                    |            |                     |            |              |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

*Pro Forma Results of Operations (Unaudited)*

 

The following table reflects theunaudited pro forma consolidated results of operations for the years endedDecember 31, 2005, 2004 and 2003, as though the Starfish and Gulf Coastacquisitions had occurred on January 1, 2004, and the East Texas System,Michigan Crude Pipeline, Western Oklahoma, Lubbock and Pinnacle acquisitionshad occurred on January 1, 2003. The unaudited pro forma results have beenprepared for comparative purposes only and may not be indicative of futureresults.

 

65

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| ** **                                                      | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                      | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
|                                                            |       |                                       |       | **(in thousands, except per unit amounts)** |   |
|                                                            |       |                                       |       |   |   |   |   |
| Revenue                                                         |       | $                                          | 970,041    |   | $ | 766,692 |   | $ | 301,537 |   |
| Net income (loss) from continuing  operations                   |       | $                                          | (16,362    | ) | $ | 53,909 |   | $ | (28,085 | ) |
|                                                            |       |                                       |       |   |   |   |   |
| Net income (loss) from continuing operations  per share:        |       |                                       |       |   |   |   |   |
| Basic                                                           |       | $                                          | (1.52      | ) | $ | 0.38 |   | $ | (2.72 | ) |
| Diluted                                                         |       | $                                          | (1.52      | ) | $ | 0.38 |   | $ | (2.72 | ) |
|                                                            |       |                                       |       |   |   |   |   |
| Weighted average number of outstanding  shares of common stock: |       |                                       |       |   |   |   |   |
| Basic                                                           |       | 10,785                                     |       | 10,686 |   | 10,328 |   |
| Diluted                                                         |       | 10,785                                     |       | 10,740 |   | 10,328 |   |

 

**4. Marketable Securities**

 

Marketable securities are classified asavailable-for-sale and stated at market based on the closing price of thesecurities at the balance sheet date.  Accordingly, unrealized gains arereflected in other comprehensive income, net of applicable income taxes. For losses that are other than temporary, the cost basis of the securities iswritten down to fair value, and the amount of the write down is reflected inthe statement of operations.  The Companyutilizes a first-in first-out cost basis to compute realized gains andlosses.  Realized gains and losses, dividends, interest income, and theamortization of discounts and premiums are reflected in the statement ofoperations.

 

The following are the components of marketablesecurities (in thousands):

 
| ** **                                                          | ** ** | **Cost Basis** | ** ** | **Unrealized  gains** | ** ** | **Unrealized  losses** | ** ** | **Recorded  Basis** | ** ** |
|---------------------------------------------------------------------|------------|---------------------|------------|-----------------------|------------|------------------------|------------|---------------------|------------|
| **December 31, 2005**                                               |       |                |       |                  |       |                   |       |                |       |
| **Equity securities:**                                              |       |                |       |                  |       |                   |       |                |       |
| Master limited partnership units                                    |       | $                   | 5,497      |                  | $          | 714                    |       | $                   | (142       | ) | $ | 6,070 |   |
|                                                                |       |                |       |                  |       |                   |       |                |       |
| **December 31, 2004**                                               |       |                |       |                  |       |                   |       |                |       |
| **Equity securities:**                                              |       |                |       |                  |       |                   |       |                |       |
| Master limited partnership units                                    |       | $                   | 5,248      |                  | $          | 872                    |       | $                   | (19        | ) | $ | 6,101 |   |
| **Fixed maturities:**                                               |       |                |       |                  |       |                   |       |                |       |
| Mortgage backed securities (due after one  year through five years) |       | 8,750               |       | 10                    |       | (46                    | )          | 8,714               |       |
| Total marketable securities, classified as  current                 |       | $                   | 13,998     |                  | $          | 882                    |       | $                   | (65        | ) | $ | 14,815 |   |

 

Net unrealized gains on marketable securities of$0.4 million, net of the related tax effect of $0.2 million, are reflected as acomponent of other comprehensive loss at December 31, 2005.

 

At December 31, 2004, unrealized gains of$0.9 million relate primarily to investments in equity securities of domesticenergy partnerships.  Unrealized losses of $0.1 million relate primarilyto master limited partnership units and mortgage backed securities and areprimarily attributable to changes in interest rates.  Net unrealized gainson marketable securities of $0.8 million, net of the related tax effect of $0.3million, are reflected as a component of other comprehensive income at December31, 2004.

 

66

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**5.****              SignificantCustomers and Concentration of CreditRisk**

 

 For the year ended December 31, 2005 sales toone customer from MarkWest Hydrocarbon Standalone (see note 21 for discussionof segments) accounted for 10% of its revenues. MarkWest Hydrocarbon had a $1.7million receivable from this customer as of December 31, 2005.

 

MarkWest Energy Partners’ business isconcentrated within the Appalachian Basin, Southwest United States and Michigangeographic areas.  Changes and eventswithin these regions have the potential to impact the Partnership.  For the years ended December 31, 2005, 2004and 2003, sales to one customer other than MarkWest Hydrocarbon of thePartnership accounted for 14%, 20%, and 20% of Partnership revenues,respectively. The Partnership had $5.5 million and $3.6 million, respectively,receivable from this customer as of December 31, 2005 and 2004.

 

**6. Receivables and Other Current Assets**

 

Receivables consist of the following (in thousands):

 
| ** **        | ** ** | **December 31,** | ** ** |
|-------------------|------------|-----------------------|------------|
| ** **        | ** ** | **2005**              | ** ** | **2004** | ** ** |
| Trade, net        |       | $                     | 135,008    |   | $ | 56,057 |   |
| Related party     |       | —                |       | 44 |   |
| Other             |       | 10,531                |       | 8,755 |   |
| Total receivables |       | $                     | 145,539    |   | $ | 64,856 |   |

 

Other current assets consist of the following (inthousands):

 
| ** **                 | ** ** | **December 31,** | ** ** |
|----------------------------|------------|-----------------------|------------|
| ** **                 | ** ** | **2005**              | ** ** | **2004** | ** ** |
| Customer margin deposits   |       | $                     | 6,598      |   | $ | 245 |   |
| Prepaid fuel               |       | 8,696                 |       | 1,174 |   |
| Prepaid other              |       | 1,020                 |       | 479 |   |
| Total other current assets |       | $                     | 16,314     |   | $ | 1,898 |   |

 

***7. Properties, Plant and Equipment***

 

Property, plant and equipment consist of:

 
| ** **                            | ** ** | **December 31,** | ** ** |
|---------------------------------------|------------|-----------------------|------------|
| ** **                            | ** ** | **2005**              | ** ** | **2004** | ** ** |
| Gas gathering facilities              |       | $                     | 212,042    |   | $ | 160,763 |   |
| Gas processing plants                 |       | 213,943               |       | 56,239 |   |
| Fractionation and storage facilities  |       | 22,882                |       | 22,112 |   |
| Natural gas pipelines                 |       | 42,246                |       | 38,167 |   |
| Crude oil pipelines                   |       | 19,070                |       | 18,499 |   |
| NGL transportation facilities         |       | 4,433                 |       | 4,381 |   |
| Furniture, office equipment and other |       | 2,864                 |       | 4,113 |   |
| Land, building and other equipment    |       | 13,823                |       | 9,418 |   |
| Construction in-progress              |       | 41,895                |       | 28,944 |   |
|                                  |       | 573,198               |       | 342,636 |   |
| Accumulated depreciation              |       | (78,500               | )          | (59,443 | ) |
|                                  |       | $                     | 494,698    |   | $ | 283,193 |   |

 

The Companycapitalizes interest on major projects during construction.  For the years ended December 31, 2005,and 2004, the Company capitalized interest of $2.1 million and $0.8 million,respectively.  The Company did notcapitalize interest for the year ended December 31, 2003, as there were nomajor construction projects.

 

67

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###### *CobbProcessing Plant*

###### * *

During 2003, MarkWest Energy Partners enteredinto an agreement with MarkWest Hydrocarbon for the construction of a new Cobbprocessing plant.  Initially, thePartnership expected the construction costs of the new plant and the costs todecommission and dismantle the old plant to be approximately $2.1 million.  In the third quarter of 2004, this estimatewas revised to $3.6 million to construct the new plant and $0.5 million todecommission and dismantle the old plant. Construction was completed in the secondquarter of 2005 at a cost of $3.6 million. Upon the completion of the new plant, the Partnership ceased operatingthe old Cobb processing plant.

 

As of December 31, 2003, and inaccordance with SFAS No. 144, MarkWest Energy Partners determined that thecarrying value of the old processing plant of $1.4 million exceeded itsestimated fair value of $0.3 million. Consequently, the Partnership has reflected an impairment of $1.1million in the statement of operations for the year ended December 31,2003.

 

**8.****             ****Intangible Assets**

 

The Company’s intangible assets atDecember 31, 2005 and 2004, are comprised of customer contracts andrelationships, as follows (in thousands):

 
| ** **      | ** ** | **December 31, 2005** | ** ** | **December 31, 2004** | ** ** | ** ** | ** ** |
|-----------------|------------|---------------------------------|------------|---------------------------------|------------|------------|------------|
| **Description** | ** ** | **Gross**                       | ** ** | **Accumulated  Amortization**   | ** ** | **Net**    | ** ** | **Gross** | ** ** | **Accumulated  Amortization** | ** ** | **Net** | ** ** | **Useful Life** | ** ** |
| East Texas      |       | $                               | 165,379    |                            | $          | 11,740     |       | $ | 153,639 |   | $ | 165,379 |   | $ | 3,446 |   | $ | 161,933 |   | 20 years |   |
| Javelina        |       | 194,150                         |       | 1,293                           |       | 192,857    |       | — |   | — |   | — |   | 25 years |   |
| Other           |       | 288                             |       | 288                             |       | —     |       | 288 |   | 220 |   | 68 |   | 1 year |   |
| **Total:**      |       | $                               | 359,817    |                            | $          | 13,321     |       | $ | 346,496 |   | $ | 165,667 |   | $ | 3,666 |   | $ | 162,001 |   |   |   |

 

Amortizationexpense related to the intangible assets was $9.7 million, $3.6 million and$0.0 million for the years ended December 31, 2005, 2004 and 2003.

 

Estimatedfuture amortization expense related to the intangible assets atDecember 31, 2005, is as follows (in thousands):

 

| **Year ending December 31:** | ** ** | ** ** | ** ** |
|---------------------------------------------|------------|------------|------------|
| 2006                                        |       | $          | 16,035     |   |
| 2007                                        |       | 16,035     |       |
| 2008                                        |       | 16,035     |       |
| 2009                                        |       | 16,035     |       |
| 2010                                        |       | 16,035     |       |
| Thereafter                                  |       | 266,321    |       |
| Total                                       |       | $          | 346,496    |   |

 

***9.*****             ****Accrued Liabilities**

 

Accrued liabilities consist of the following (in thousands):

 
| ** **                                                 | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                 | ** ** | **2005**              | ** ** | **2004** | ** ** |
| Product and operations                                     |       | $                     | 17,987     |   | $ | 14,407 |   |
| Customer obligations                                       |       | 3,380                 |       | 1,911 |   |
| Professional services                                      |       | 2,054                 |       | 518 |   |
| Taxes                                                      |       | 3,014                 |       | 1,901 |   |
| Interest                                                   |       | 3,273                 |       | 2,876 |   |
| Javelina working capital adjustment                        |       | 5,402                 |       | — |   |
| Starfish contribution                                      |       | 1,486                 |       | — |   |
| Construction in progress                                   |       | 2,652                 |       | 2,602 |   |
| Deferred income                                            |       | 1,937                 |       | 3,518 |   |
| Bonus and profit sharing, severance and  vacation accruals |       | 3,349                 |       | 2,028 |   |
| Phantom unit compensation expense accrual                  |       | 958                   |       | 327 |   |
| Other                                                      |       | 377                   |       | 820 |   |
| Total accrued  liabilities                                 |       | $                     | 45,869     |   | $ | 30,908 |   |

 

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**10.****      ****Asset RetirementObligation**

 

**TheCompany adopted SFAS 143, *Accounting for AssetRetirement Obligations,* on January 1, 2003. Under SFAS 143, thefair value of a liability for an asset retirement obligation is recognized inthe period in which the liability is incurred, with an offsetting increase inthe carrying amount of the related long-lived asset. Over time, the liabilityis accreted to its future value, and the capitalized cost is depreciated overthe useful life of the related asset. Upon settlement of the liability, anentity either settles the obligation for its recorded amount or incurs a gainor loss.**

 

The Company’sassets subject to asset retirement obligations are primarily certaingas-gathering pipelines and processing facilities, a crude oil pipeline andother related pipeline assets.  TheCompany also has land leases that require the Company to return the land to itsoriginal condition upon the termination of the lease.   In connection with the adoption of SFAS 143,the Company reviewed current laws and regulations governing obligations forasset retirements and leases, as well as the Company’s leases and otheragreements.

 

The following is a reconciliation of thechanges in the asset retirement obligation from January 1, 2003, toDecember 31, 2005 (in thousands):

 

| Asset retirement obligation as of  January 1, 2003   |   | $      | 3,367  |   |
|-----------------------------------------------------------|--------|--------|--------|--------|
| Liabilities accrued during the period                     |   | 1,197  |   |
| Liabilities settled                                       |   | (4,188 | )      |
| Accretion expense                                         |   | 128    |   |
| Asset retirement obligation as of  December 31, 2003 |   | 504    |   |
| Liabilities accrued during the period                     |   | 377    |   |
| Liabilities settled                                       |   | (4     | )      |
| Accretion expense                                         |   | 15     |   |
| Asset retirement obligation as of  December 31, 2004 |   | 892    |   |
| Liabilities accrued during the period                     |   | 554    |   |
| Liabilities settled                                       |   | (504   | )      |
| Accretion expense                                         |   | 160    |   |
| Asset retirement obligation as of  December 31, 2005 |   | $      | 1,102  |   |

 

MarkWest Hydrocarbon’s assets subject to assetretirement obligations, exclusive of assets owned by MarkWest Energy, wereprimarily oil and gas wells. The Company discontinued its exploration andproduction business and sold off substantially all of its assets as of December 31,2003.

 

At January 1 and December 31, 2005and 2004, there were no assets legally restricted for purposes of settlingasset retirement obligations.

 

***11.*****      ****Debt**

 

Debt as of December 31, 2005 and 2004, issummarized below (in thousands):

 
| ** **                                                                    | ** ** | **December 31,**   | ** ** |
|-------------------------------------------------------------------------------|------------|-------------------------|------------|
| ** **                                                                    | ** ** | **2005**                | ** ** | **2004** | ** ** |
| ** **                                                                    | ** ** | **(in thousands)** | ** ** |
|                                                                          |       |                    |       |   |   |
| **MarkWest Hydrocarbon Credit Facility**                                      |       |                    |       |   |   |
| Revolver facility, 8.75% interest at  December 31, 2005, due January 30, 2007 |       | $                       | 7,500      |   | $ | — |   |
|                                                                          |       |                    |       |   |   |
| **Partnership Credit Facility**                                               |       |                    |       |   |   |
| Term loan, 8.75% interest at December 31,  2005, due December 2010            |       | 365,000                 |       | — |   |
| Revolver facility, 8.75% interest at  December 31, 2005, due December 2010    |       | 14,000                  |       | — |   |
|                                                                          |       |                    |       |   |   |
| **Partnership Senior Notes**                                                  |       |                    |       |   |   |
| Senior Notes, 6.875% interest, due November  2014                             |       | 225,000                 |       | 225,000 |   |
| Total debt                                                                    |       | 611,500                 |       | 225,000 |   |
| Less: obligations due in one year                                             |       | (2,738                  | )          | — |   |
| Long-term portion                                                             |       | $                       | 608,762    |   | $ | 225,000 |   |

 

69

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*MarkWest Hydrocarbon Credit Facility*

 

InOctober 2004, the Company entered into a $25.0 million senior creditfacility with a term of one year.  The $25.0 million revolving facilityhad a variable interest rate based on the base rate, which is equal to thehigher of a) the Federal Funds Rate plus 1⁄2 of 1%, and b) the rate of interestin effect for such day as publicly announced from time to time by theAdministrative Agent as its prime rate, plus the applicable rate, which isbased on a utilization percentage.  In October, November, and December 2005,the Company entered into the first, second and third amendment to the creditagreement.  The first amendment extended the term of the originalagreement to November 15, 2005.  The second amendment reduced the lendingamount from $25.0 million to $16.0 million, of which $6.0 million ofavailability is committed to a letter of credit, leaving $10.0 millionavailable for revolving loans.  The second amendment also extended theterm of the revolving credit to December 30, 2005.  The thirdamendment extended the term of the revolving credit to January 31, 2006and reduced the lending amount from $16.0 million to $13.5 million, of which$6.0 million of availability is committed to a letter of credit, leaving $7.5million available for revolving loans.  If the revolving credit isconverted into a term loan, the term will be extended to December 29,2006.

 

On January 31, 2006, the Company entered into the first amendedand restated credit agreement, which provides a maximum lending limit of $25.0million for a one year term.

 

The credit facility bears interest at avariable interest rate, plus basis points.  The variable interest rate istypically based on the London Inter Bank Offering Rate (“LIBOR”); however, incertain borrowing circumstances the rate would be based on the higher of a) theFederal Funds Rate plus 0.5-1%, and b) a rate set by the Facility’sadministrative agent, based on the U.S. prime rate.  The basis points correspond to the ratio ofthe Revolver Facility Usage (asdefined in the Company Credit Facility) to the Borrowing Base (as defined inthe Company Credit Facility),ranging from 0.75% to 1.75% for Base Rate loans, and 1.75% to 2.75% forEurodollar Rate loans.  The Company paysa quarterly commitment fee on the unused portion of the credit facility at anannual rate of 50.0 basis points.

 

Underthe provisions of the Company Credit Facility, the Company is subject to anumber of restrictions on its business, including restrictions on its abilityto grant liens on assets; make or own certain investments; enter into any swapcontracts other than in the ordinary course of business; merge, consolidate orsell assets; incur indebtedness (other than subordinated indebtedness); makedistributions on equity investments; declare or make, directly or indirectly,any restricted distributions.

 

Thecredit facility also contains covenants requiring the Company to maintain:

 

•                  aratio of not more than 3.50 to 1.00 of total consolidated debt to consolidatedEBITDA for any fiscal quarter-end;

•                  aminimum net worth of a) $34.0 million plus, b)50% of consolidated net income(if positive) earned on or after October 1, 2005 plus, c) 100% of netproceeds of all equity issued by the Company subsequent to January 31,2006; and

•                  aminimum available cash and marketable securities reserve of $13.0 million,which is to be reduced to zero in the event the Company restructures akeep-whole contract with one of its significant customers.

 

***MarkWest Energy Partners***

 

*Partnership CreditFacility*

 

On December 29, 2005, MarkWest EnergyOperating Company, L.L.C., a wholly owned subsidiary of MarkWest EnergyPartners L.P., entered into the fifth amended and restated credit agreement (“PartnershipCredit Facility”), which provides for a maximum lending limit of $615.0 millionfor a five-year term.  The credit facility includes a revolving facilityof $250.0 million and a $365.0 million term loan.  The credit facility isguaranteed by the Partnership and all of the

 

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Partnership’s subsidiaries and is collateralized by substantially allof the Partnership’s assets and those of its subsidiaries.  The borrowingsunder the credit facility bear interest at a variable interest rate, plus basispoints.  The variable interest rate is typically based on the London InterBank Offering Rate (“LIBOR”); however, in certain borrowing circumstances therate would be based on the higher of a) the Federal Funds Rate plus 0.5-1%, andb) a rate set by the Facility’s administrative agent, based on the U.S. primerate.  The basis points vary based on the ratio of the Partnership’sConsolidated Debt (as defined in the Partnership Credit Facility) toConsolidated EBITDA (as defined in the Partnership Credit Facility), rangingfrom 0.50% to 1.50% for Base Rate loans, and 1.50% to 2.50% for Eurodollar Rateloans.  The basis points will increase by 0.50% during any period (not toexceed 270 days) where the Partnership makes an acquisition for a purchaseprice in excess of $50.0 million (“Acquisition Adjustment Period”). The 8.75%rate at December 31, 2005, was converted to 6.65%, a LIBOR-based rate, on January 5,2006.

 

Under the provisionsof the Partnership Credit Facility, the Partnership is subject to a number ofrestrictions on its business, including restrictions on its ability to grantliens on assets; make or own certain investments; enter into any swap contractsother than in the ordinary course of business; merge, consolidate or sellassets; incur indebtedness (other than subordinated indebtedness); makedistributions on equity investments; and declare or make, directly orindirectly, any restricted payments.

 

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

 

•                  a ratio of not less than 2.00 to 1.00 of consolidated EBITDAto consolidated interest expense for any fiscal quarter-end increasing to 3.00to 1.00 upon the first to occur of September 30, 2006 or the first fiscalquarter-end following the Partnership raising at least $175.0 million inaggregate proceeds from equity offerings;

•                  a ratio of not more than 6.50 to 1.00 of total consolidateddebt to consolidated EBITDA for any fiscal quarter-end decreasing to 5.25 to1.00 upon the first to occur of September 30, 2006 or the first fiscalquarter-end following the Partnership raising at least $175.0 million inaggregate proceeds from equity offerings;

•                  a ratio of not more than 4.75 to 1.00 of consolidated seniordebt to consolidated EBITDA for any fiscal quarter-end decreasing to 3.75 to1.00 upon the first to occur of September 30, 2006 or the first fiscalquarter-end following the Partnership raising at least $175.0 million inaggregate proceeds from equity offerings and

•                  Both the total debt and senior debt ratios containadjustment clauses during any Acquisition Adjustment Period.

 

These covenants areused to calculate the available borrowing capacity on a quarterly basis. The Partnership incurs a commitment fee on the unused portion of the creditfacility at a rate between 30.0 and 50.0 basis points based upon the ratio ofConsolidated Senior Debt (as defined in the Partnership Credit Facility) toConsolidated EBITDA (as defined in the Partnership Credit Facility).  Theterm loan portion of the facility is paid in quarterly installments on the lastbusiness day of March, June, September and December, with the remainingbalance payable on December 29, 2010.  The revolver portion of thefacility matures on December 29, 2010.  The Partnership’s CreditFacility also contains provisions requiring prepayments from certain Net CashProceeds (as defined in the Partnership Credit Facility) received from certaintriggering sales that have not been reinvested within one hundred eighty days,Equity Offerings (as defined in the Partnership Credit Facility) and loanproceeds in excess of $15.0 million from a Senior Debt Offering.  Inaddition, commencing with the fiscal year ending December 31, 2006, andannually thereafter, the Partnership is required to make a mandatory prepaymentequal to fifty percent of Excess Cash Flow within ninety days of each fiscalyear end.  Excess Cash Flow means quarterly, the amount, not less thanzero, equal to consolidated cash flow from operations for such quarter, minusthe sum of (i) capital expenditures for such quarter, (ii) principaland interest payments on indebtedness actually made during such quarter and (iii) thePartnership’s distributions made during such quarter.

 

The JavelinaAcquisition (see Note 3) was funded through the fourth amended and restatedcredit agreement, which provided for a maximum lending limit of $500.0 millionfor a term of one year, comprised of a revolving facility of $100.0 million anda $400.0 million term loan.  The fourthamended and restated credit agreement had terms similar to the new creditfacility. In the fourth quarter of 2005, the Partnership completed two privateplacement offerings to repay a portion of the funds borrowed (see Note 16).

 

In October 2004 the Operating Company,coincident with the issuance of the Senior Notes, discussed below, entered intothe third amended and restated credit agreement (“Old Credit Facility”), whichprovided for a maximum lending limit of $200.0 million for a term of fiveyears.  The Old Credit Facility includeda revolving facility of $200.0 million. The borrowings under the Old Credit Facility carried interest at avariable interest rate based on one of two indices that include either (i) LIBORplus an applicable 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 adjusted

 

71

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quarterly based on the ratio of funded debt to EBITDA (as defined inthe credit agreement).  For the yearsended December 31, 2005, 2004 and 2003, the weighted average interest rateon the Old Credit Facility was 7.02%, 4.48% and 4.69%, respectively.

 

*Senior Notes*

 

In October 2004 the Partnership and itssubsidiary, MarkWest Energy Finance Corporation, issued $225.0 million insenior notes at a fixed rate of 6.875%, payable semi-annually in arrears on May 1and November 1, commencing on May 1, 2005.  The notes mature on November 2,2014.  The Partnership may redeem some orall of the notes at any time on or after November 1, 2009, at certainredemption prices together with accrued and unpaid interest to the date of redemption. The Partnership may redeem all ofthe notes at any time prior to November 1, 2009, at a make-wholeredemption price.  In addition, prior to November 1,2007, the Partnership may redeem up to 35% of the aggregate principal amount ofthe notes with the proceeds of certain equity offerings at a stated redemptionprice.  The Partnership must offer torepurchase the notes at a specified price if it a) sells certain assets anddoes not reinvest the proceeds or repay senior indebtedness, or b) thePartnership experiences specific kinds of changes in control.  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 ofits 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 additional indebtedness; declare orpay dividends or distributions or redeem, repurchase or retire equity interestsor subordinated indebtedness; make investments; incur liens; create anyconsensual 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. Subject to compliance with certain covenants, the Partnership may issueadditional notes from time to time under the indenture pursuant to Rule 144Aand Regulation S under the Securities Act of 1933.

 

The Partnership has agreed to file anexchange offer registration statement or, under certain circumstances, a shelfregistration statement, pursuant to a registration rights agreement relating tothe 2004 senior notes.  The Partnershipfailed to complete the exchange offer in the time provided for in thesubscription agreements (April 26, 2005) and, as a consequence, isincurring an interest rate penalty of 0.5% annually, increasing 0.25% every 90days thereafter up to 1%, until such time as the exchange offer iscompleted.  As of December 31, 2005,the Partnership was being charged an interest rate penalty of 1%.  The registration statement was filed on January 17,2006, and the interest penalty ceased on March 7, 2006.

 

The aggregate amount of minimum principalpayments required on long-term debt in each of the years indicated are asfollows as of December 31, (in thousands):

 

| 2006                 |   | $       | 2,738   |   |
|----------------------|--------|---------|---------|--------|
| 2007                 |   | 11,150  |    |
| 2008                 |   | 3,650   |    |
| 2009                 |   | 3,650   |    |
| 2010                 |   | 365,312 |    |
| 2011 and  thereafter |   | 225,000 |    |
|                 |   | $       | 611,500 |   |

 

**12. Derivative Financial Instruments**

 

*Commodity Instruments*

 

*MarkWest Hydrocarbon*

 

72

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*MarkWest Hydrocarbon may enter into physical and/or financial positionsto manage its risks related to commodity price exposure.  Due to timing of gas purchases and liquidsales, direct exposure to either gas or liquids can be created because there isno longer an offsetting purchase or sale that remains exposed to marketpricing.  Through our marketing andderivatives activity, direct exposure may occur naturally or we may choosedirect exposure to either gas or liquids when we favor that exposure over fracspread risk.*

 

Asof December 31, 2004, the Company had NGL swap agreements relating to11,928,000 NGL gallons with a weighted average fixed price of $0.85 per gallon.These swaps settled in the first quarter of 2005. The NGL swaps were notdesigned as hedges. As a result, changes in the fair value of the NGL swapswere reflected currently in earnings.

 

*MarkWest Energy Partners*

 

Asof December 31, 2004, the Company had NGL swap agreements relating to11,928,000 NGL gallons with a weighted average fixed price of $0.85 per gallon.These swaps settled in the first quarter of 2005. The NGL swaps were notdesigned as hedges. As a result, changes in the fair value of the NGL swapswere reflected currently in earnings.

 

*The Partnership’s primary risk management objective is to reducevolatility in its cash flows arising from changes in commodity prices relatedto future sales of natural gas, NGL’s and crude.  Swaps and futures contracts may allow the Partnershipto reduce volatility in its margins, because losses or gains on the derivativeinstruments are generally offset by corresponding gains or losses in thePartnership’s physical positions.  Acommittee, including members of senior management of the general partner of thePartnership, oversees all of the Partnership’s hedging activity.*

 

The Partnership may utilize a combination of fixed-price forwardcontracts, fixed-for-floating price swaps and options available in theover-the-counter (“OTC”) market, and futures contracts traded on the New YorkMercantile Exchange (“NYMEX”).  ThePartnership enters into OTC swaps with financial institutions and other energycompany counterparties.  The Partnershipconducts a standard credit review on counterparties and has agreementscontaining collateral requirements, where deemed necessary.  The Partnership uses standardized swapagreements that allow for offset of positive and negative exposures.  The Partnership may be subject to margindeposit requirements under some of its agreements.

 

The use of derivative instruments may expose us to the risk offinancial 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) our OTC counterparties fail to purchase or deliver the contractedquantities of natural gas, NGLs or crude oil or otherwise fail toperform.  To the extent that the Partnership engages in hedgingactivities, it may be prevented from realizing the benefits of favorable pricechanges in the physical market; however, it is similarly insulated againstunfavorable changes in such prices.

 

As part of an ongoing comprehensive risk management plan designed tomanage risk and stabilize future cash flows, the Partnership has entered intothe following derivative instruments that settle monthly through December 31,2007.

 

| **Costless Collars:**             | ** ** | **Period**                   | ** ** | **Floor** | ** ** | **Cap** | ** ** |
|-----------------------------------|------------|------------------------------|------------|-----------|------------|---------|------------|
| Crude Oil —  500 Bbl/d       |       | 2006                         |       | $         | 57.00      |    | $          | 67.00 |   |
| Crude Oil —  250 Bbl/d       |       | 2006                         |       | $         | 57.00      |    | $          | 67.00 |   |
| Crude Oil —  205 Bbl/d       |       | 2006                         |       | $         | 57.00      |    | $          | 65.10 |   |
|                              |       |                         |       |      |       |    |       |
| Propane — 20,000 Gal/d       |       | 2006                         |       | $         | 0.90       |    | $          | 0.99 |   |
| Propane — 10,000 Gal/d       |       | 2006                         |       | $         | 0.97       |    | $          | 1.15 |   |
| Propane — 12,750 Gal/d       |       | Jan – June 2006    |       | $         | 0.90       |    | $          | 1.01 |   |
|                              |       |                         |       |      |       |    |       |
| Ethane —  22,950 Gal/d       |       | 2006                         |       | $         | 0.65       |    | $          | 0.80 |   |
|                              |       |                         |       |      |       |    |       |
| Natural Gas  — 1,575 Mmbtu/d |       | Jan - Mar  2006              |       | $         | 9.00       |    | $          | 11.40 |   |
| Natural Gas  — 1,575 Mmbtu/d |       | April -  Oct 2006       |       | $         | 8.50       |    | $          | 10.05 |   |
| Natural Gas  — 1,575 Mmbtu/d |       | Nov - Mar  2007              |       | $         | 9.00       |    | $          | 12.50 |   |
| Natural Gas  — 645 Mmbtu/d   |       | Jan - Mar  2006              |       | $         | 8.86       |    | $          | 15.21 |   |
| Natural Gas  — 645 Mmbtu/d   |       | April -  June 2006 |       | $         | 6.71       |    | $          | 12.46 |   |

 

| **Swaps**                   | ** ** | **Period** | ** ** | **Fixed Price** |   |
|-----------------------------|------------|------------|------------|-----------------|--------|
| Crude Oil —  250 Bbl/d |       | 2006       |       | $               | 62.00  |   |
| Crude Oil —  185 Bbl/d |       | 2006       |       | $               | 61.00  |   |
| Crude Oil —  250 Bbl/d |       | 2007       |       | $               | 65.30  |   |

 

Asof December 31, 2004, the Partnership had natural gas swap agreementsrelating to 182,500 MMBtu, of forecasted natural gas sales with a fixed priceof $4.26 per MMBtu. These swaps settled in the first quarter of 2005. In 2003,the Partnership hedged its natural gas price risk in Other Southwest byentering into fixed-for-floating price swaps that settled monthly throughDecember 2005.

 

 

73

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The impact of commodityderivative instruments on the Partnership’s results of operations and financialposition are summarized below (in thousands):

 
| ** **                                               | ** ** | **Year ended December 31,** | ** ** |
|----------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                               | ** ** | **2005**                         | ** ** | **2004** | ** ** | **2003** | ** ** |
| Realized  gains (losses) – revenue                  |       | $                                | (2,541     | ) | $ | (3,661 | ) | $ | (19,501 | ) |
| Unrealized  gains (losses) – revenue                |       | (657                             | )          | (84 | ) | 2,400 |   |
| Other  comprehensive income – changes in fair value |       | (1,279                           | )          | (1,826 | ) | (12,842 | ) |
| Other  comprehensive income – settlement            |       | 1,593                            |       | 3,661 |   | 19,501 |   |
|                                                          |            |                                  |            |  |  |  |  |  |  |  |

 
| ** **                                     | ** ** | **December 31,** | ** ** |
|------------------------------------------------|------------|-----------------------|------------|
| ** **                                     | ** ** | **2005**              | ** ** | **2004** | ** ** |
| Unrealized  losses – current liability    |       | $                     | (728       | ) | $ | (1,057 | ) |
| Accumulated  other comprehensive income (loss) |       | —                |       | 314 |   |
|                                                |            |                       |            |  |  |  |  |

 

*Interest rate swap*

 

TheCompany reclassified $0.3 million and $0.2 million from other comprehensiveincome, net of $0.1 million and $0.1 million of deferred taxes, in 2004 and2003, respectively, related to a discontinued interest rate hedge.

 

## **13.   Income Taxes**

 

The components of the provision (benefit) forincome taxes from continuing operations are as follows (in thousands):

 

| ** **                              | ** ** | **December 31,** | ** ** |
|-----------------------------------------|------------|-----------------------|------------|
| ** **                              | ** ** | **2005**              | ** ** | **2004** | ** ** | **2003** | ** ** |
|                                    |       |                  |       |   |   |   |   |
| Current  income tax expense (benefit):  |       |                  |       |   |   |   |   |
| Federal                                 |       | $                     | 502        |   | $ | 20 |   | $ | (12,258 | ) |
| State                                   |       | 52                    |       | — |   | (1,422 | ) |
| Total  current                          |       | 554                   |       | 20 |   | (13,680 | ) |
|                                    |       |                  |       |   |   |   |   |
| Deferred  income tax expense (benefit): |       |                  |       |   |   |   |   |
| Federal                                 |       | (2,839                | )          | (286 | ) | 554 |   |
| State                                   |       | 481                   |       | 344 |   | 41 |   |
| Total  deferred                         |       | (2,358                | )          | 58 |   | 595 |   |
|                                    |       |                  |       |   |   |   |   |
| Provision  (benefit) for income taxes   |       | $                     | (1,804     | ) | $ | 78 |   | $ | (13,085 | ) |

 

Areconciliation of the actual provision (benefit) for income taxes fromcontinuing operations and the amount computed by applying the federal statutoryrate of 34% to the income (loss) before income taxes is as follows (inthousands):

 
| ** **                                        | ** ** | **December 31,** | ** ** |
|---------------------------------------------------|------------|-----------------------|------------|
| ** **                                        | ** ** | **2005**              | ** ** | **2004** | ** ** | **2003** | ** ** |
|                                              |       |                  |       |   |   |   |   |
| Federal  income tax at statutory rate (1)         |       | $                     | (2,926     | ) | $ | (280 | ) | $ | (12,072 | ) |
| State income  taxes, net of federal benefit       |       | (294                  | )          | 7 |   | (834 | ) |
| Permanent  items                                  |       | 16                    |       | — |   | — |   |
| 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                    |       | 1,053                 |       | 1,121 |   | — |   |
| Change in  estimate of blended state rate         |       | 117                   |       | 117 |   | — |   |
| Impact of  state amended tax returns              |       | —                |       | 177 |   | — |   |
| Alternative  minimum tax credit                   |       | —                |       | (373 | ) | — |   |
| Other                                             |       | 230                   |       | 41 |   | (179 | ) |
|                                              |       |                  |       |   |   |   |   |
| Provision  (benefit) for income taxes             |       | $                     | (1,804     | ) | $ | 78 |   | $ | (13,085 | ) |

 

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(1) The calculation of federal income taxat statutory rate has been adjusted for the non-controlling interest in netincome of consolidated subsidiary.

 

Thedeferred tax assets and liabilities resulting from temporary book-taxdifferences are comprised of the following (in thousands):

 
| ** **                               | ** ** | **December 31,** | ** ** |
|------------------------------------------|------------|-----------------------|------------|
| ** **                               | ** ** | **2005**              | ** ** | **2004** | ** ** |
| **Current  deferred tax assets**         |       |                  |       |   |   |
| Accruals and  Reserves                   |       | $                     | 157        |   | $ | 261 |   |
| Deferred  Income                         |       | —                |       | 80 |   |
| Derivative  Instruments                  |       | —                |       | 202 |   |
| Stock  Compensation                      |       | 32                    |       | — |   |
| Other                                    |       | 7                     |       | — |   |
| Current  deferred tax assets             |       | 196                   |       | 543 |   |
|                                     |       |                  |       |   |   |
| **Current  deferred tax liabilities**    |       |                  |       |   |   |
| Investment  in Third Party Partnerships  |       | 343                   |       | 171 |   |
| Marketable  Securities                   |       | 215                   |       | 302 |   |
| Other                                    |       | —                |       | 45 |   |
| Current  deferred tax liabilities        |       | 558                   |       | 518 |   |
|                                     |       |                  |       |   |   |
| **Current  Subtotal**                    |       | (362                  | )          | 25 |   |
|                                     |       |                  |       |   |   |
| **Long-term  deferred tax assets**       |       |                  |       |   |   |
| Accruals and  Reserves                   |       | —                |       | 21 |   |
| Participation Plan Compensation          |       | 1,626                 |       | 1,418 |   |
| Property,  Plant, and Equipment          |       | 135                   |       | 1,630 |   |
| Stock  Compensation                      |       | 84                    |       | — |   |
| Tax Credit  Carryforward                 |       | 2,920                 |       | 2,995 |   |
| Federal Net  Operating Loss Carryforward |       | 6,145                 |       | — |   |
| State Net  Operating Loss Carryforward   |       | 2,278                 |       | 1,121 |   |
| Other                                    |       | —                |       | (7 | ) |
| Long-term  deferred tax assets           |       | 13,188                |       | 7,178 |   |
| Valuation  Allowance                     |       | (2,278                | )          | (1,121 | ) |
| Net  long-term deferred tax assets       |       | 10,910                |       | 6,057 |   |
|                                     |       |                  |       |   |   |
| **Long-term  deferred tax liabilities**  |       |                  |       |   |   |
| Investment  in Consolidated Subsidiary   |       | 14,397                |       | 12,315 |   |
| Long-term  deferred tax liabilities      |       | 14,397                |       | 12,315 |   |
|                                     |       |                  |       |   |   |
| **Long-term  Subtotal**                  |       | (3,487                | )          | (6,258 | ) |
|                                     |       |                  |       |   |   |
| **Net  deferred tax liability**          |       | $                     | (3,849     | ) | $ | (6,233 | ) |

 

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At December 31,2005, the Company had federal net operating loss carryforwards of $18.1 millionthat expire in 2026 and state net operating loss carryforwards of $51.5 millionthat expire between 2013 and 2026.  TheCompany expects that future taxable income will likely be apportioned to statesother than those in which the net operating loss was generated.  As a result, the Company believes it is morelikely than not that the state net operating losses will not be realized andhas provided a 100% valuation allowance against this long-term deferred taxasset.  The Company had federalalternative minimum tax credit carryforwards of $2.9 million that have noexpiration date and can be applied as a credit to reduce regular federal incometax.

 

**14.**       **Stock and Incentive Compensation Plans**

 

At December 31, 2005, the Company hasfour stock-based compensation plans, one of which is through its consolidatedsubsidiary, MarkWest Energy. These plans are described below.

 

*Stock Options*

 

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, 2005, there were 176,078options available for grant under this plan.

 

Under the 1996 Non-employee Director Stock Option Plan, the Company maygrant options to its non-employee directors for up to 30,000 shares of commonstock. There are no options available for grant at December 31, 2005.  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.

 

Theplans allow for the exercise of stock options using the cashless method, butonly at the discretion of the Company.  In April 2004, theCompany changed its policy to allow participants to exercise their stockoptions using the cashless method and, as a result recognized $1.6 million ofcompensation expense.  During the threemonths ended March 31, 2004, two officers resigned from the Company. Because 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.  Consequently, the Company recognized $0.4 million ofexpense. Due to the modification to the stock options for these officers, theoutstanding stock options are accounted for as a variable award.

 

Thefollowing summarizes the impact of the Company’s stock option plans (inthousands):

 
| ** **                   | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Options  exercised, cashless |       | 33       |       | 126      |       | —   |       |
| Shares  issued, cashless     |       | 21       |       | 45       |       | —   |       |
| Options  exercised, cash     |       | 15       |       | 155      |       | 261      |       |
| Shares  issued, cash         |       | 15       |       | 175      |       | 294      |       |
| Compensation  expense        |       | $        | 1.0        |     | $          | 2.0      |       | $ | — |   |
|                              |            |          |            |          |            |          |            |  |  |  |

 

Shares issued for cash are greater than the number of options exerciseddue to stock splits in 2004 and 2003.

 

TheCompany did not grant any stock options in 2005.  The fair value of each option granted in 2004and 2003 was estimated using the Black-Scholes option-pricing model.  The following assumptions were used tocompute the weighted average fair value of options granted:

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

 

Asummary of the status of the Company’s stock option plans as of December 31,2005, 2004 and 2003, and changes during the years then ended are presentedbelow.  Stock option information in the following table has not beenadjusted to give retroactive effect to stock dividends paid.  See note 16.

 

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| ** **                                                      | ** ** | **2005**   | ** ** | **2004**                      | ** ** | **2003**   | ** ** |
|-----------------------------------------------------------------|------------|------------|------------|-------------------------------|------------|------------|------------|
| ** **                                                      | ** ** | **Shares** | ** ** | **Weighted-  Average  Price** | ** ** | **Shares** | ** ** | **Weighted-  Average  Price** | ** ** | **Shares** | ** ** | **Weighted-  Average  Price** | ** ** |
| Outstanding at  beginning of year                               |       | 171,688    |       | $                             | 8.43       |       | 440,080    |   | $ | 8.35 |   | 728,315 |   | $ | 9.06 |   |
| Granted                                                         |       | —     |       | —                        |       | 33,500     |       | 12.62 |   | 45,750 |   | 8.44 |   |
| Effect of stock  dividends                                      |       | —     |       |                          |       | 15,072     |       |   |   | 83,042 |   |   |   |
| Exercised                                                       |       | (48,170    | )          | 7.62                          |       | (280,776   | )          | 8.37 |   | (261,141 | ) | 8.11 |   |
| Cancelled                                                       |       | (9,511     | )          | 14.37                         |       | (36,188    | )          | 11.67 |   | (155,886 | ) | 8.78 |   |
| Outstanding at end  of year                                     |       | 114,007    |       | 8.28                          |       | 171,688    |       | 8.35 |   | 440,080 |   | 8.35 |   |
|                                                            |       |       |       |                          |       |       |       |   |   |   |   |   |   |
| Options exercisable                                             |       | 75,414     |       |                          |       | 92,362     |       |   |   | 342,043 |   |   |   |
| Weighted-average  fair value of options granted during the year |       |       |       | $                             | —     |       |       |   | $ | 2.46 |   |   |   | $ | 2.41 |   |

 

The following tablesummarizes information about fixed stock options outstanding at December 31,2005:

 

| ** **                   | ** ** | **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               |       | 22,740                   |       | 6.8                                                  |       | $ | 4.76 |   | 12,151 |   | $ | 4.79 |   |
| $6.00 to $8.00               |       | 17,956                   |       | 4.6                                                  |       | 6.78 |   | 17,956 |   | 6.79 |   |
| $8.00 to $10.00              |       | 61,211                   |       | 6.5                                                  |       | 9.30 |   | 36,415 |   | 9.16 |   |
| $10.00 to $12.00             |       | 8,800                    |       | 2.4                                                  |       | 11.29 |   | 7,975 |   | 11.26 |   |
| $12.00 to $14.00             |       | 2,200                    |       | 8.7                                                  |       | 13.25 |   | 550 |   | 13.25 |   |
| $14.00 to $16.00             |       | 1,100                    |       | 8.8                                                  |       | 14.27 |   | 367 |   | 14.27 |   |
| $4.41 to $14.27              |       | 114,007                  |       | 6.0                                                  |       |   | 8.28 |   | 75,414 |   |   | 8.17 |   |

 

*Restricted Stock*

 

TheCompany also issues restricted stock under the Company’s 1996 Stock IncentivePlan and 1996 Non-employee Director Stock Option Plan.  Restricted stockis granted for no consideration, and vests over a stated period.  No shares were granted prior to 2005.  The following summarizes the impact of theCompany’s restricted stock plans (in thousands, except for per share data):

 
| ** **                         | ** ** | ** ** | ** ** | ** ** | ** ** | **2005** | ** ** |
|------------------------------------|------------|------------|------------|------------|------------|----------|------------|
|                               |       |       |       |       |       |     |       |
| Balance,  beginning of period      |       |       |       |       |       | —   |       |
| Granted                            |       |       |       |       |       | 22,673   |       |
| Vested                             |       |       |       |       |       | —   |       |
| Forfeited                          |       |       |       |       |       | —   |       |
| Balance, end  of period            |       |       |       |       |       | 22,673   |       |
|                               |       |       |       |       |       |     |       |
| Fair value,  end of year           |       |       |       |       |       | $        | 482        |   |
|                               |       |       |       |       |       |     |       |
| Compensation  expense for the year |       |       |       |       |       | $        | 84         |   |

 

*Participation Plan*

 

MarkWest Hydrocarbon also has a ParticipationPlan for certain of its employees and directors.  Under the Participation Plan, MarkWestHydrocarbon sells subordinated partnership units of the Partnership andinterest in the Partnership’s general partner to certain employees anddirectors of MarkWest Hydrocarbon under a purchase-and-sale agreement.  The interest in the Partnership’s generalpartner is sold with certain put-and-call provisions that allow the individualsto require MarkWest Hydrocarbon to buy back, or require the individuals 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

 

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issued and if the issuance of additional membership interests, on a proforma basis, decreases the distributions to all the 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, or (ii) dies, or (iii) retiresas a director, officer or employee of the general partner, of MarkWestHydrocarbon 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.  MarkWest Hydrocarbon has 12months following 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.  The subordinatedunits are sold without any restrictions on transfer.  The Partnership has established an impliedrepurchase obligation, however, through its pattern of buying back thesubordinated units each time an employee or director has left MarkWestHydrocarbon.   The subordinated unitsconverted into common units on August 15, 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 current quarterly distributionspaid.  The increases or decreases in themarket value of the subordinated units and the formula value of the generalpartner interests 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 2005, 2004 and 2003were 0, 1,500 and 12,500, respectively. MarkWest Hydrocarbon reacquired 0, 2,867 and 867 subordinated units in2005, 2004 and 2003, respectively.

 

###### *MarkWest Energy Partners, L.P. Long-TermIncentive Plan*

 

The Partnership’s general partner has adoptedthe MarkWest Energy Partners, L.P. Long-Term Incentive Plan for employees anddirectors of the general partner and employees of its affiliates who performservices for us. The long-term incentive plan consists of two components,restricted units and unit options. The long-term incentive plan currentlypermits the grant of awards covering an aggregate of 500,000 common units,comprised of 200,000 restricted units and 300,000 unit options. TheCompensation Committee of the general partner’s board of directors administersthe plan.

 

The general partner’s board of directors, atits discretion, may terminate or amend the long-term incentive plan at any timewith respect to any units for which a grant has not yet been made. The generalpartner’s board of directors also has the right to alter or amend the long-termincentive plan, including increasing the number of units that may be granted,subject to unitholder approval, as required by the exchange upon which thecommon units are listed at that time. No change in any outstanding grant,however, 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 equal to thevalue of a common unit. These restricted units are entitled, during the vestingperiod, to receive distribution equivalents, which represent cash equal to theamount of distributions made on common units. Prior to September 2004, the vesting period was four years, with25% of the grant vesting at the end of each of the second and third years and50% vesting at the end of the fourth year. As of September 1, 2004, thevesting period for subsequent grants was changed to three years, with 33% ofthe grant vesting at 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. The CompensationCommittee also determines the vesting period. The restricted units will vest upon a change of control of thePartnership, the general partner of the Partnership or MarkWest Hydrocarbon.

 

If a grantee’s employment or membership onthe board of directors terminates for any reason, the grantee’s unvestedrestricted units are automatically forfeited unless, and to the extent thatCompensation Committee provides otherwise. Common units used for settlement maybe acquired by the general partner in the open market, already owned by thegeneral partner, acquired by the general partner directly from the Partnershipor any other person, or any combination of the foregoing. The general partnerwill be entitled 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.

 

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*The following is a summary of the Long-TermIncentive Plan restricted units issued under the Partnership’s Long-TermIncentive Plan:*

 
| ** **                         | ** ** | **2005**                               | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------------------|------------|----------------------------------------|------------|----------|------------|----------|------------|
| ** **                         | ** ** | **(in thousands, except share  data)** | ** ** |
|                               |       |                                   |       |     |       |     |       |
| Balance,  beginning of period      |       | 29,500                                 |       | 34,496   |       | 50,230   |       |
| Granted                            |       | 20,139                                 |       | 27,900   |       | 11,756   |       |
| Vested                             |       | (9,100                                 | )          | (27,453  | )          | (23,758  | )          |
| Forfeited                          |       | (1,675                                 | )          | (5,443   | )          | (3,732   | )          |
| Balance, end  of period            |       | 38,864                                 |       | 29,500   |       | 34,496   |       |
|                               |       |                                   |       |     |       |     |       |
| Fair value,  end of year           |       | $                                      | 1,873      |     | $          | 1,434    |       | $ | 1,383 |   |
|                               |       |                                   |       |     |       |     |       |
| Compensation  expense for the year |       | $                                      | 1,076      |     | $          | 1,065    |       | $ | 1,398 |   |

 

Of the total number of restricted units thatvested in 2005, the Partnership did not redeem any restricted units for cash,and issued 8,850 common units and acquired 250 common units in the openmarket.  The Partnership recorded $1.1million in compensation expense in 2005, of which $0.4 million related to theaccelerated vesting of restricted units.

 

In 2004, of the total number of restrictedunits vested, 155 restricted units, at the Partnership’s option, were redeemedfor cash and 27,298 common units were issued for vested restricted units.  The Partnership recorded compensation expenseof $1.1 million in 2004, of which $0.5 million related to the acceleratedvesting of restricted units, resulting from specified distribution targetsbeing achieved.

 

In October 2003, the board of directorsof the general partner approved the accelerated vesting of 23,758 restrictedunit grants due to the achievement of cash distribution goals, effective December 1,2003.  Accordingly, the Partnershiprecorded a charge in the amount of $1.0 million.

 

*Unit Options**.** *TheLong-Term Incentive Plan currently permits the granting of options for commonunits. The Compensation Committee may make grants under the plan to employeesand directors containing such terms as the committee shall determine. Unitoptions will have an exercise price that, at the discretion of the committee,may be less than, equal to or more than the fair market value of the units onthe date of grant. Unit options granted are exercisable over a perioddetermined by the Compensation Committee. In addition, the unit options areexercisable upon a change in control of us, the general partner, MarkWestHydrocarbon or upon the achievement of specified financial objectives.

 

Upon exercise of a unit option, the generalpartner will acquire common units in the open market or directly from us or anyother person, or use common units already owned by the general partner, or anycombination of the foregoing. The general partner will be entitled toreimbursement by us for the difference between the cost incurred by the generalpartner in acquiring these common units and the proceeds received by thegeneral partner from an optionee at the time of exercise. Thus, the cost of theunit options will be borne by us. If the Partnership issues new common unitsupon exercise of the unit options, the general partner will pay us the proceedsit received from the optionee upon exercise of the unit option.

 

As of December 31, 2005, the Partnershiphad not granted common unit options to employees or directors of the generalpartner, or employees of its affiliates or members of senior management.

 

**15.****      ****Employee Benefit Plan**

 

TheCompany made contributions of $0.2 million, $0.5 million and $0.4 million to a401(k) savings and profit-sharing plan for the years ended December 31,2005, 2004 and 2003, respectively. The Company contributed approximately 12,000,15,000 and 32,000 common shares to a 401(k) savings and profit-sharing plan forthe years ended December 31, 2005, 2004 and 2003, respectively, with anaggregate fair value of $0.2 million, $0.2 million and $0.2 million,respectively.  The plan is discretionary, with annual contributionsdetermined by the Company’s Board of Directors.

 

**16.****       Stockholder’s Equity**

 

*Cash Dividends - Quarterly*

 

TheCompany paid quarterly cash dividends for the years ended December 31,2005 and 2004 as follows:

 

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| **Quarter Ended**        | ** ** | **Dividend** | ** ** | **Record Date** | ** **             | **Payment Date** | ** **             |
|--------------------------|------------|--------------|------------|-----------------|------------------------|------------------|------------------------|
|                     |       |         |       |            |                   |             |                   |
| December 31,  2005  |       | $            | 0.125      |            | February 15, 2006 |             | February 22, 2006 |   |
| September 30,  2005 |       | $            | 0.125      |            | November 15, 2005 |             | November 22, 2005 |   |
| June 30,  2005      |       | $            | 0.100      |            | August 15, 2005   |             | August 22, 2005   |   |
| March 31,  2005     |       | $            | 0.100      |            | May 16, 2005      |             | May 23, 2005      |   |
|                     |       |         |       |            |                   |             |                   |
| December 31,  2004  |       | $            | 0.075      |            | February 9, 2005  |             | February 21, 2005 |   |
| September 30,  2004 |       | $            | 0.050      |            | 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 year ended December 31,2003.

 

*Cash Dividends – Special*

 

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

 

*Stock Dividends*

 

OnOctober 28, 2004, the Company’s Board of Directors declared a stockdividend of one share of MarkWest Hydrocarbon’s common stock for each tenshares owned by stockholders.  The stock dividend of 976,974 shares waspaid on November 19, 2004 to the stockholders of record as of the close ofbusiness on November 9, 2004.

 

OnJuly 10, 2003, the Company’s Board of Directors declared a stock dividendof one share of MarkWest Hydrocarbon’s common stock for each ten shares held byits stockholders.  The stock dividend of 852,248 shares was paid on August 11,2003 to the stockholders of record as of the close of business on July 31,2003.

 

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

 

*PublicOfferings and Private Placements by MarkWest Energy Partners*

 

*Private Placement – December 28,2005*

 

The Partnership sold 574,714 common units tocertain accredited investors at $43.50 per common unit, for gross proceeds of$25.0 million.  $20 million of theproceeds were received in December 2005. The remaining $5 million was accrued at December 31, 2005, andreceived in January 2006.  Offeringcosts of $0.1 million reduced the aggregate gross proceeds of $25.0 million to $24.9million of net proceeds.

 

*Private Placement – November 11,2005*

 

The Partnership sold 1,644,065 common unitsto certain accredited investors at $44.21 per common unit, for gross proceedsof $72.7 million.  Offering costs of $0.1million reduced the aggregate gross proceeds of $72.7 million to $72.6 millionof net proceeds.

 

*Public Offering – September 21,2004*

 

The Partnership priced its offering of2,157,395 common units at $43.41 per unit. The Partnership sold 2,000,000 units, for gross proceeds of $86.8million. The remaining 157,395 were sold by certain unitholders, who retainedthe proceeds.  In connection with the over-allotmentprovisions of the underwriting agreement, the Partnership issued an additional323,609 common units, for gross proceeds of $14.1 million.  Underwriters’ fees of $4.8 million, andprofessional fees and other offering costs of $0.4 million, reduced the grossproceeds of $100.9 million to $95.7 million of net proceeds.

 

*Private Placement – July 30,2004*

 

The Partnership sold 1,304,438 common unitsto certain accredited investors at $34.50 per common unit, for gross

 

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proceeds of $45.0 million. Offering costs of $0.9 million reduced the aggregate gross proceeds of$45.0 million to $44.1 million of net proceeds.

 

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

######  

The Partnership priced its offering of1,148,000 common units at $39.90 per unit. The Partnership sold 1,100,444 units, for gross proceeds of $43.9million. The remaining 47,556 were sold by certain unitholders, who retainedthe proceeds.  In connection with the over-allotmentprovisions of the underwriting agreement, the Partnership issued an additional72,500 common units, for gross proceeds of $2.9 million.  Underwriters’ fees of $2.5 million, andprofessional fees and other offering costs of $1.3 million, reduced the grossproceeds of $46.8 million to $43.0 million of net proceeds.

 

*Private Placement – June 27 andJuly 10, 2003*

 

The Partnership sold 375,000 common units tocertain accredited investors in two installments at a price of $26.23 per unit.On June 27, 2003, the first installment of 300,031 units raised proceedsof approximately $7.9 million. On July 10, 2003, the second installment of74,969 units raised proceeds of approximately $1.9 million. Transaction costsfor both installments were less than $0.1 million.

 

**17.****       Commitments andContingencies**

 

*Legal*

 

MarkWest Hydrocarbon, in the ordinary courseof business, is subject to a variety of risks and disputes normallyincident to its business, a defendant in various lawsuits and a party tovarious other legal proceedings.  We maintain insurance policies with insurersin amounts and with coverage and deductibles as we believe are reasonable andprudent. However, we cannot assure either that the insurance companies willpromptly honor their policy obligations or that the coverage or levels ofinsurance will be adequate to protect us from all material expenses related topotential future claims for property loss or business interruption to thePartnership or for third party claims of personal and property damage, or thatthe coverages or levels of insurance it presently has will be available in thefuture at economical prices.

 

The Company and several of its affiliates,including the Partnership, were served in early 2005 with two lawsuits, RickyJ. Conn, *et al.* v. MarkWestHydrocarbon, Inc. *et al. and*Charles C. Reid, *et al.* v.MarkWest Hydrocarbon, Inc. *et al.*,presently under the jurisdiction of the U.S. District Court for the EasternDistrict of Kentucky, Pikeville Division. In early November 2005, the Company, the Partnership and itsaffiliates were served with an additional lawsuit, Community Trust andInvestment Co., *et al.* v.MarkWest Hydrocarbon, Inc. *et al.*,filed in Floyd County Circuit Court, Kentucky, that added five new claimantsbut essentially alleged the same facts and claims as the earlier two suits.These actions are for third-party claims of property and personal injurydamages sustained as a consequence of an NGL pipeline leak and an ensuingexplosion and fire that occurred on November 8, 2004.  The pipeline was owned by an unrelated businessentity and leased and operated by the Partnership’s subsidiary, MarkWest EnergyAppalachia, LLC.  It transports NGLs fromthe Maytown gas processing plant to the Partnership’s Siloam fractionator.  The fire from the leaked vapors resulted inproperty damage to five homes and injuries to some of the residents.  The pipeline owner, the U.S. Department ofTransportation, Office of Pipeline Safety (“OPS”), and the Partnership continueto investigate the incident.

 

The Company has timely notified its generalliability insurance carriers of the incident and of the filed Kentucky actionsin a timely manner and is coordinating the defense of these third-partylawsuits with the insurers.  At thistime, the Partnership believes that it has adequate general liability insurancecoverage for third-party property damage and personal injury liabilityresulting from the incident.  To date,the Partnership has settled with several of the claimants for third-partyproperty damage claims (damage to residences and personal property), inaddition to reaching settlement for some of the personal injury claims.  These settlements have been paid for orreimbursed under the Partnership’s general liability insurance.   As a result, the Partnership has notprovided for a loss contingency.

 

Pursuant to OPS regulation mandates and to aCorrective Action Order issued by the OPS immediately after the incident,pipeline and valve integrity evaluation, testing and repairs were conducted onthe affected pipeline segment before service could be resumed.  Partial return to service of the affectedpipeline began in October 2005. The Company has filed an independentaction against its All-Risks Property and Business Interruption insurancecarriers as a result of the companies’ refusal to honor their insurancecoverage obligation to pay the Company for certain expenses.  These include the Partnership’s internalexpenses and costs incurred for damage to, and loss of use of, the pipeline,equipment, products, the extra transportation costs incurred for transportingthe liquids while the pipeline was out of service, the reduced volumes of

 

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liquids that could be processed, and the costs of complying with theOPS Corrective Action Order (hydrostatic testing, repair/replacement and otherpipeline integrity assurance measures). These expenses and costs have beenexpensed as incurred and any potential recovery from the All-Risks Property andBusiness Interruption insurance carriers will be treated as “other income” ifand when they are received.  The Companyhas not provided for a receivable for these claims because of the uncertaintyas to whether and how much the Company will ultimately recover under thesepolicies. The Company has also asserted that the cost of pipeline testing,replacement and repair are subject to an equitable sharing arrangement with itsowner, pursuant to the terms of the pipeline lease agreement.

 

The Company has also been involved in a lawsuitcaptioned *Ross Bros. Construction v. MarkWestHydrocarbon, Inc.*, (U.S. Court of Appeals for the 6th Circuit,Case No. 05-6251, appealed from U.S. District Court Eastern District ofKentucky, Ashland Division, Civ. Action No. 01-CV-205). The underlying 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. The lawsuit involved a claim of approximately $0.7million in extra costs. The Company was granted Summary Judgment on its defenseasserting accord and satisfaction. In August 2005, Plaintiffs filed anappeal of the Summary Judgment to the U.S. Court of Appeals for the 6th Circuit. The Company believes that,while it is not able to predict the outcome of this matter, based on the judge’sdiscussion on the grant of the summary judgment and denial of Ross Brothers’motion for reconsideration, it is probable that the Company will prevail in theappeal. As a result, the Company has not provided for a loss contingency.

 

The Company has also been involved in an arbitrationproceeding captioned *Kevin Stowe andScott Daves v. MarkWest Hydrocarbon, Inc.*, AmericanArbitration Association arbitration, Case No. 77 168 Y 0052 05 BEAH,Denver, Colorado, 2005. Claimants in this Arbitration had filed a proceedingagainst the Company seeking further payments out of a dispute and settlementover interests in certain wells in Colorado.  On February 8, 2006, the Company wasgranted Summary Judgment and the Arbitration was accordingly dismissed.

 

In the ordinary course of business, thePartnership is a party to various other legal actions. In the opinion ofmanagement, none of these actions, either individually or in the aggregate,will have a material adverse effect on the Partnership’s financial condition,liquidity or results of operations.

 

*Lease Obligations*

 

*The Company has various non-cancelable operating lease agreements forequipment expiring at various times through fiscal 2015. Annual rent expenseunder these operating leases was $7.0 million, $5.2 million and $2.2 millionfor the years ended December 31, 2005, 2004, and 2003, respectively. Theminimum future lease payments under these operating leases as of December 31,2005, are as follows (in thousands):*

 

| **Year ending December 31,** | ** ** | ** ** | ** ** |
|-----------------------------------|------------|------------|------------|
| 2006                              |       | $          | 4,755      |   |
| 2007                              |       | 3,005      |       |
| 2008                              |       | 1,931      |       |
| 2009                              |       | 1,516      |       |
| 2010                              |       | 459        |       |
| 2011 and  thereafter              |       | 203        |       |
| Total                             |       | $          | 11,869     |   |

 

**18.****      ****Discontinued Operations**

 

During2003 the Company discontinued its exploration and production business. Through a series of dispositions noted below, the Company sold offsubstantially all of its U.S. and Canadian oil and gas properties. Thedispositions were as follows:

 

*Sales of San Juan Basin Properties*

 

Duringthe second and third quarters of 2003 the Company completed the sales of itsSan Juan Basin (U.S.) oil and gas properties to certain third parties for netproceeds aggregating approximately $55.3 million. The Company recognized anaggregate net pretax gain of $23.3 million on these sales for the year ended December 31,2003.  The proceeds from the sales were used for working capital andgeneral corporate purposes.

 

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*Sales of Canadian Properties*

 

DuringDecember 2003, the Company completed the sales of all of its Canadian oiland gas properties to certain third parties for net proceeds aggregatingapproximately $49.1 million. The Company recognized an aggregate pretax loss of$4.8 million on these sales for the year ended December 31, 2003. Theproceeds from the sales were primarily used to pay off the Company’s remainingoutstanding debt, exclusive of MarkWest Energy’s debt.

 

*Sale of Eastern Michigan Properties*

 

DuringDecember 2003, the Company completed the sale of certain oil and gasproperties and related assets located in Eastern Michigan for net proceeds ofless than $0.1 million. The Company recognized a pretax loss of $1.8 million.

 

***19.*****      ****Related****Party Transactions**

 

Throughthe Company’s wholly owned subsidiary, Matrex, LLC, the Company held interestsin a few exploration and production assets in which MAK-J Energy Partners Ltd.(“MAK-J”) also owns interests.  These interests were sold on October 7,2005.  The general partner of MAK-J is acorporation owned and controlled by the Company’s former President and ChiefExecutive Officer and current Chairman of the Board of Directors.

 

TheCompany has receivables due from MAK-J, representing its share of operating andcapital costs generated in the normal course of business, of  less than $0.1 million as of December 31,2004.  There were no outstanding relatedparty receivables as of December 31, 2005. The Company also has payablesto MAK-J, representing its share of revenues generated in the normal course ofbusiness, of less than $0.1 million as of both December 31, 2005 and December 31,2004.

 

***20.*****      ****Subsequent Events**

 

On January 31, 2006, MarkWestHydrocarbon entered into the first amended and restated credit agreement, whichprovides a maximum lending limit of $25.0 million for a one year term.

 

On January 17, 2006, the Partnershipfiled a Form S-4 exchange offer registration statement related to theSenior Notes (see Note 11).  Theregistration became effective February 3, 2006.  The interest rate penalty (1% at December 31,2005) on the Senior Notes ceased on March 7, 2006.

 

## **21.**       SegmentInformation

 

MarkWest Hydrocarbon’s operations are classified into tworeportable segments. For further information regarding our two businesssegments, see “Management’s Discussion and Analysis ofFinancial Condition and Results of Operations” included in Item 7 of this Form 10-Kand  “FinancialStatements and Supplementary Data,” included in Item 8 of this Form 10-K:

 

**1.**               *MarkWest Energy Partners* — ThePartnership is engaged in the gathering, processing and transmission of naturalgas; the transportation, fractionation and storage of natural gas liquids; andthe gathering and transportation of crude oil.

 

**2.**               *MarkWest Hydrocarbon Standalone* — 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. MarkWest Hydrocarbon Standaloneoperates MarkWest Energy Partners, a publicly traded limited partnership.

 

During2003, the Company discontinued its exploration and production business segment.

 

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TheCompany evaluates the performance of its segments and allocates resources tothem based on operating income.  There were no intersegment revenues priorto May 24, 2002.  The Company conducts its continuing operations inthe United States.

 

Thetable below presents information about operating income for the reportedsegments for the three years ended December 31, 2005, 2004 and 2003. Operatingincome for each segment includes total revenues minus purchased product costs,facility expenses, 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 the segments based ondirect expenses incurred by the segments or allocated based on****the percent of timethat employees devote to the segment in accordance with the Partnership’sservices agreement with the Company.****

 
| **Year Ended December 31, 2005:**               | ** ** | **MarkWest  Hydrocarbon  Standalone** | ** ** | **MarkWest Energy  Partners** | ** ** | **Eliminating Entries** | ** ** | **Total** | ** ** |
|------------------------------------------------------|------------|---------------------------------------|------------|-------------------------------|------------|-------------------------|------------|-----------|------------|
| Revenues                                             |       | $                                     | 280,015    |                          | $          | 499,084                 |       | $         | (64,922    | ) | $ | 714,177 |   |
| Purchased  product costs                             |       | 258,188                               |       | 366,878                       |       | (41,982                 | )          | 583,084   |       |
| Facility  expenses                                   |       | 20,545                                |       | 47,972                        |       | (22,940                 | )          | 45,577    |       |
| Selling,  general and administrative expenses        |       | 11,777                                |       | 21,573                        |       | —                  |       | 33,350    |       |
| Depreciation                                         |       | 1,295                                 |       | 19,534                        |       | —                  |       | 20,829    |       |
| Amortization  of intangible assets                   |       | —                                |       | 9,656                         |       | —                  |       | 9,656     |       |
| Accretion of  asset retirement and lease obligations |       | 1                                     |       | 159                           |       | —                  |       | 160       |       |
| Total  operating expenses                            |       | 291,806                               |       | 465,772                       |       | (64,922                 | )          | 692,656   |       |
|                                                 |       |                                  |       |                          |       |                    |       |      |       |
| Operating  income (loss)                             |       | $                                     | (11,791    | )                             | $          | 33,312                  |       | $         | —     |   | $ | 21,521 |   |
| Total assets                                         |       | $                                     | 86,211     |                          | $          | 1,046,039               |       | $         | —     |   | $ | 1,132,304 |   |
|                                                 |       |                                  |       |                          |       |                    |       |      |       |
| **Year Ended December 31, 2004:**               | ** ** | **MarkWest  Hydrocarbon  Standalone** | ** ** | **MarkWest Energy  Partners** | ** ** | **Eliminating Entries** | ** ** | **Total** | ** ** |
| 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 and lease obligations |       | 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 |   |
| Total assets                                         |       | $                                     | 64,152     |                          | $          | 529,422                 |       | $         | —     |   | $ | 593,574 |   |
|                                                 |       |                                  |       |                          |       |                    |       |      |       |
| **Year Ended December 31, 2003:**               | ** ** | **MarkWest  Hydrocarbon  Standalone** | ** ** | **MarkWest Energy  Partners** | ** ** | **Eliminating Entries** | ** ** | **Total** | ** ** |
| 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 | ) |
| Total assets                                         |       | $                                     | 67,624     |                          | $          | 212,871                 |       | $         | —     |   | $ | 280,495 |   |
|                                                      |            |                                       |            |                               |            |                         |            |           |            |  |  |  |  |  |  |  |  |

 

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

 
| ** **                                                                                                | ** ** | **December 31,** | ** ** |
|-----------------------------------------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                | ** ** | **2005**              | ** ** | **2004** | ** ** | **2003** | ** ** |
| Operating  income (loss)                                                                                  |       | $                     | 21,521     |   | $ | 19,460 |   | $ | (26,080 | ) |
| Loss from  unconsolidated subsidiary                                                                      |       | (2,153                | )          | — |   | — |   |
| Interest  income                                                                                          |       | 1,060                 |       | 647 |   | 106 |   |
| Interest  expense                                                                                         |       | (22,622               | )          | (9,383 | ) | (4,347 | ) |
| Amortization  of deferred financing cost (a component of interest expense)                                |       | (6,979                | )          | (5,281 | ) | (2,104 | ) |
| Dividend income                                                                                           |       | 392                   |       | 259 |   | — |   |
| Other income  (expense)                                                                                   |       | 266                   |       | 788 |   | (92 | ) |
| Income  (loss) before non-controlling interest in net income of consolidated  subsidiary and income taxes |       | $                     | (8,515     | ) | $ | 6,490 |   | $ | (32,517 | ) |

 

***22.*****      ****Quarterly Results of Operations**(Unaudited)

 

*The following summarizes the Company’squarterly results of operations:*

 
| ** **                                | ** ** | **Three months ended** | ** ** |
|-------------------------------------------|------------|------------------------|------------|
| **2005**                                  | ** ** | **March 31**      | ** ** | **June 30** | ** ** | **September 30** | ** ** | **December 31** | ** ** |
| Revenue                                   |       | $                      | 138,353    |   | $ | 141,040 |   | $ | 170,625 |   | $ | 264,159 |   |
| Income  (loss) from operations            |       | 1,539                  |       | (1,609 | ) | (5,688 | ) | (1,044 | ) |
| Net Income  (loss)                        |       | 1,539                  |       | (1,609 | ) | (5,688 | ) | (1,044 | ) |
|                                      |       |                   |       |   |   |   |   |   |   |
| Earnings  (loss) per share:               |       |                   |       |   |   |   |   |   |   |
| Basic                                     |       | $                      | 0.14       |   | $ | (0.15 | ) | $ | (0.53 | ) | $ | (0.09 | ) |
| Diluted                                   |       | $                      | 0.14       |   | $ | (0.15 | ) | $ | (0.53 | ) | $ | (0.09 | ) |
|                                      |       |                   |       |   |   |   |   |   |   |
| ** **                                | ** ** | **Three months ended** | ** ** |
| **2004**                                  | ** ** | **March 31**      | ** ** | **June 30** | ** ** | **September 30** | ** ** | **December 31** | ** ** |
| Revenue                                   |       | $                      | 93,700     |   | $ | 89,024 |   | $ | 121,511 |   | $ | 155,878 |   |
| Income  (loss) from continuing operations |       | 720                    |       | (6,368 | ) | (1,966 | ) | 6,711 |   |
| Net Income  (loss)                        |       | 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 |   |

 

**23.****       Valuation and QualifyingAccounts**

 

Activity inthe allowance for doubtful accounts is as follows (in thousands):

 

| ** **                      | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------|------------|----------------------------------|------------|
| ** **                      | ** ** | **2005**                         | ** ** | **2004** | ** ** | **2003** | ** ** |
| Balance at  beginning of period |       | $                                | 249        |   | $ | 120 |   | $ | 87 |   |
| Charged to  costs and expenses  |       | 46                               |       | 277 |   | 177 |   |
| Deductions  (Collections)       |       | (120                             | )          | (148 | ) | (144 | ) |
| Balance at  end of period       |       | $                                | 175        |   | $ | 249 |   | $ | 120 |   |

 

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

 

On September 20, 2005, the Company informedKPMG LLP (KMPG) that it would be dismissing KPMG as its registered independentaccounting firm effective upon the completion of their audit of the Company’sconsolidated financial statements for the year ended December 31, 2004. TheRegistrant’s Audit Committee made the decision to change independentaccountants and that decision was approved, ratified and adopted by theCompany’s Board of Directors. KPMG completed its audit and the Company’s Form10-K was filed with the Securities and Exchange Commission on October 21, 2005.

 

The report of KPMG on the consolidated financialstatements as of and for the year ended December 31, 2004 contained no adverseopinion or disclaimer of opinion and was not qualified or modified as touncertainty, audit scope, or accounting principle. The audit report of KPMG onmanagement’s assessment of the effectiveness of internal control over financialreporting and the effectiveness of internal control over financial reporting asof December 31, 2004 did not contain an adverse opinion or disclaimer ofopinion, and was not qualified or modified as to uncertainty, audit scope oraccounting principles, except that KPMG’s report indicates that the Company didnot maintain effective internal control over financial reporting as of December31, 2004 because of the effect of material weakness on the achievement of theobjectives of the control criteria and contains an explanatory paragraph thatstates that the following material weaknesses have been identified and includedin management’s assessment:

 

•     Ineffective Control Environment

•      Insufficient technical accountingexpertise, inadequate policies and procedures related to accounting matters,and inadequate management review in thefinancial reporting process

•     Inadequate personnel, processesand controls at the Partnership’s Southwest Business Unit 

•     Inadequately designed controls andprocedures over property, plant and equipment

In connection with its audit for the yearended December 31, 2004 and during the subsequent interim period throughOctober 21, 2005, there have been no disagreements with KPMG on any matter ofaccounting principles or practices, financial statement disclosure, or auditingscope or procedure, which disagreements, if not resolved to the satisfaction ofKPMG would be expected to cause them to make reference thereto in their reportson financial statements for such year.

 

During the two most recent fiscal years andthrough October 21, 2005, except as noted in this paragraph, there have been no“Reportable Events” (as defined in Regulation S-K, Item 304(a)(1)(v)). Inconjunction with KPMG’s audit of the consolidated financial statements for theyear ended December 31, 2004, KPMG communicated to the Company’s AuditCommittee the existence of material weaknesses related to (i) ineffectivecontrol environment, (ii) insufficient accounting expertise, inadequatepolicies and procedures related to accounting matters, and inadequatemanagement review in the financial reporting process, (iii) inadequatepersonnel, processes and controls at our Southwest Business Unit, and (iv)inadequately designed controls and procedures over property, plant andequipment.

 

On September 20, 2005, the Companyengaged Deloitte & Touche LLP as the Registrant’s registered independentaccounting firm for the year ending December 31, 2005, and to performprocedures related to the financial statements included in the Company’squarterly reports on Form 10-Q, beginning with the quarter endedMarch 31, 2005.  The Audit Committee made the decision to engageDeloitte & Touche LLP and that decision was then approved, adopted andratified by the Company’s Board of Directors.  The Company has notconsulted with Deloitte & Touche LLP during its two most recent fiscalyears or during any subsequent interim period prior to its appointment asauditor regarding either (i) the application of accounting principles to aspecified transaction, either completed or proposed; or the type of auditopinion that might be rendered on the Registrant’s consolidated financialstatements, and neither a written report was provided to the Company nor oraladvice was provided that Deloitte & Touche LLP concluded was an importantfactor considered by the Company in reaching a decision as to the accounting,auditing or financial reporting issue; or (ii) any matter that was eitherthe subject of disagreement (as defined in Item 304(a)(1)(iv) ofRegulation S-K and the related instructions) or a reportable event (withinthe meaning of Item 304(a)(1)(v) of Regulation S-K).

 

On February 23, 2004, the Companydismissed PricewaterhouseCoopers LLP as its independent accountants effectiveupon the filing of the Partnership’s Form 10-K for fiscal year ended December 31,2003. Our Form 10-K was filed on March 15, 2004. The Audit Committeeof the Board of Directors participated in, recommended and approved thedecision to change independent accountants.

 

The report of PricewaterhouseCoopers LLP onthe consolidated financial statements for the year ended

 

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December 31, 2003, contains no adverseopinion or disclaimer of opinion and was not qualified or modified as touncertainty, audit scope, or accounting principle.

 

In connection with its audit for thefiscal year ended December 31, 2003, and through March 15, 2004,there have been no disagreements with PricewaterhouseCoopers LLP on any matterof accounting principles or practices, financial statement disclosure, orauditing scope or procedure, which disagreements, if not resolved to thesatisfaction of PricewaterhouseCoopers LLP would have caused them to make referencethereto in their report on the financial statements for the fiscal year ended December 31,2003.

 

During the fiscal year ended December 31,2003, and through March 15, 2004, there have been no “Reportable Events”(as defined in Regulation S-K, Item 304(a)(1)(v)); however, as disclosedin our Annual Report on Form 10-K for the year ended December 31,2003, PricewaterhouseCoopers LLC identified to the Company’s management andAudit Committee in connection with the audit for fiscal 2003 certain deficienciesin the Company’s internal controls that, when considered collectively, may beconsidered a material weakness.

 

On April 12, 2004, the Audit Committee of theBoard of Directors, engaged KPMG LLP as our independent accountants forthe fiscal year ending December 31, 2004.  The Company has notconsulted with KPMG LLP during the fiscal years ended December 31,2003 and 2002 or during any subsequent interim period prior to its appointmentas auditor regarding the application of accounting principles to a specifiedtransaction, either completed or proposed, or the type of audit opinion thatmight be rendered on the Partnership’s consolidated financial statements, orany matter that was either the subject of a disagreement (as defined inItem 304(a)(1)(iv) of Regulation S-K and the relatedinstructions) or reportable event (within the meaning of Item 304(a)(1)(v) ofRegulation S-K).

 

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**ITEM 9A.****                                            CONTROLSAND PROCEDURES**

 

***Disclosure Controls and Procedures***

 

Disclosure controls andprocedures (as defined in Rule 13a-15(e) under the SecuritiesExchange Act of 1934, as amended (the “Exchange Act”)) are controls and otherprocedures that are designed to provide reasonable assurance that theinformation that we are required to disclose in the reports that we file orsubmit under the Exchange Act is recorded, processed, summarized and reportedwithin the time periods specified in the SEC’s rules and forms, and thatsuch information is accumulated and communicated to our management, includingour Chief Executive Officer and Chief Financial Officer, as appropriate toallow timely decisions regarding required disclosure.

 

In connection with thepreparation of this Annual Report, our management, with the participation ofour Chief Executive Officer and our Chief Financial Officer, carried out anevaluation of the effectiveness of the design and operation of our disclosurecontrols and procedures as of December 31, 2005. In making thisevaluation, our management considered material weaknesses discussed below.Based on this evaluation, our Chief Executive Officer and Chief FinancialOfficer concluded that our disclosure controls and procedures were noteffective at the reasonable assurance level as of December 31, 2005.

 

In light of the materialweaknesses described below, through the date of the filing of this Form 10-K,we have adopted remedial measures to address the deficiencies in our internalcontrols that existed on December 31, 2005.  In addition, we have applied compensatingprocedures and processes as necessary to ensure the reliability of ourfinancial reporting.  Such additionalprocedures include detailed management review of account reconciliations forall accounts in all business units and multiple level management review ofaccounting treatment for significant non-routine transactions.  Accordingly, management believes that theconsolidated financial statements included in this Annual Report presentfairly, in all material respects, our financial condition, results ofoperations and cash flows as of, and for, the periods presented in conformitywith GAAP.

 

**MANAGEMENT’S REPORT ON INTERNAL CONTROLS OVER FINANCIAL REPORTING**

 

Managementof the Company is responsible for establishing and maintaining adequateinternal control over financial reporting, as defined in Rule 13a-15(f) underthe Exchange Act.  The Company’s internalcontrol over financial reporting is a process designed to provide reasonableassurance regarding the reliability of financial reporting and the preparationof financial statements for external purposes in accordance with generallyaccepted accounting principles in the United States of America and includesthose policies and procedures that:

 

•                  pertainto the maintenance of records that in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the Company;

 

•                  providereasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally acceptedaccounting principles, and that receipts and expenditures of the Company arebeing made only in accordance with authorizations of management and directorsof the Company; and

 

•                  providereasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use or disposition of the Company’s assets that could have amaterial effect on the financial statements.

 

Management,including our CEO and CFO, does not expect that our internal controls willprevent or detect all errors and all fraud.  A control system, no matterhow well designed and operated, can provide only reasonable, not absolute,assurance that the objectives of the control system are met. Further, thedesign of a control system must reflect the fact that there are resource constraints,and the benefits of controls must be considered relative to their costs. Inaddition, any evaluation of the effectiveness of controls is subject to risksthat those internal controls may become inadequate in future periods because ofchanges in business conditions, or that the degree of compliance with thepolicies or procedures deteriorates.

 

Managementassessed the effectiveness of our internal controls over financial reporting asof December 31, 2005. In making this assessment, management used thecriteria established in Internal Control-Integrated Framework issued by theCommittee of Sponsoring Organizations of the Treadway Commission (“COSO”).

 

Amaterial weakness is a significant deficiency (within the meaning of PCAOBAuditing Standard No. 2), or combination of significant deficiencies, thatresult in there being a more than remote likelihood that a materialmisstatement of the annual or interim financial statements will not beprevented or detected.

 

88

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Asreported in Item 9 of the Company’s 2004 Form 10-K, material weaknessesexisted as of December 31, 2004, related to 1) ineffective controlenvironment, 2) insufficienttechnical accounting expertise, inadequate policies and procedures related toaccounting matters, and inadequate management review in the financial reportingprocess, 3) Inadequate personnel, processes, and controls at the Partnership’sSouthwest Business Unit, and 4) Inadequately designed controls andprocedures over property, plant and equipment.

 

While the Company hasundertaken numerous steps in an effort to remediate its material weaknesses, asdiscussed under remediation plans below, in connection with management’scurrent year assessment, management has identified the following materialweaknesses that existed at December 31, 2005:

 

*Internal ControlEnvironment* – The Company’s control environment did notsufficiently promote effective internal control over financial reportingthrough the management structure to prevent a material misstatement, as wasevidenced by deficiencies or significant deficiencies in the following areas:

 

•                  *S**egregation ofduties* withincertain key processes was inadequate to support management’s assertions withrespect to accuracy and completeness of financial records.

 

•                  *Entitylevel controls* including the anti-fraud program and controls necessary to address the COSOelements of risk assessment, information and communication.

 

•                  *Applicationcontrols* over financially significant applications with respectto change management and information systems operations.

 

•                  *Fixedassets* controls including instances of inappropriate authorization ofinvoices and improper reconciliation procedures.

 

•                  *Financialreporting* controls related to the closing process, includingcontrol over non-routine transactions, unusual journal entries and the use ofestimates and judgment.

 

•                  Controls over*expenditures* including instances of inappropriateauthorization of invoices and the inability to independently validate accuracy andvalidity of amounts recorded.

 

•                  *Spreadsheetcontrols* related to change management within key financialspreadsheets.

 

•                  *Accountingfor Income Taxes*related to reconciliationof tax accounts.

 

*Risk Management and Accounting for DerivativeFinancial Instruments* –The Company did not have adequate internal controls and processes in place tosupport management’s assertions with respect to the completeness, accuracy andvalidity of commodity transactions.  Thedesign of internal controls over commodity transactions did not supportindependent validation of data or control and review of transacting activity.In particular, personnel responsible for executing and entering transactionsinto commodity accounting systems also have duties that are not compatible withtransaction execution and entry.

 

                                                BecauseJavelina was acquired late in 2005, management did not include the internalcontrol processes for the Javelina entities in its assessment of internalcontrols as of December 31, 2005. Management will include all aspects of internal controls for Javelina inits 2006 assessment.

 

*Conclusion:*

 

Becauseof the material weaknesses described above, management has concluded that, asof December 31, 2005, the Company did not maintain effective internalcontrol over financial reporting.

 

TheCompany’s independent registered accounting firm has issued an attestationreport on management’s assessment of the Company’s internal control overfinancial reporting, which appears on page 92.

 

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| Date: March 20, 2006 | By:    | /s/FRANK M. SEMPLE       |   |
|---------------------------|--------|--------------------------|--------|
|                      |   | Frank M.  Semple         |
|                      |   | Chief  Executive Officer |
|                      |   |                     |
| Date: March 20, 2006 | By:    | /s/JAMES G. IVEY         |   |
|                      |   | James G.  Ivey           |
|                      |   | Chief  Financial Officer |

 

***CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING***

 

Nochanges were made to internal control that affected management’s assertionsabout our internal control over financial reporting.  Specific changes that have occurred andfurther planned changes are discussed below under the heading “Remediation ofMaterial Weaknesses in Internal Controls.”

 

***REMEDIATION OF MATERIAL WEAKNESSES ININTERNAL CONTROL***

 

Inresponse to the material weaknesses identified in the 2004 Form 10-K andthose still existing at December 31, 2005, our management, with oversightfrom our audit committee, has dedicated significant resources to improve ourcontrol environment and to remedy the identified material weaknesses.  These ongoing efforts are focused on (i) expandingour organizational capabilities through the addition of employees withappropriate skills and abilities to improve our control environment and (ii) implementingprocess changes to strengthen our internal control design and monitoringactivities.

 

Froman organizational capabilities perspective, we have made significant strides.  Among other things:

 

•                  Wehave hired a Senior Vice President, Chief Accounting Officerwith public company accounting and reporting technical expertise.

 

•                  Wehave hired additional external reporting, tax and accounting staff tosupplement our existing technical accounting resources and mitigate segregationof duties deficiencies.

 

•                  Wehave hired a Vice President of Risk and Compliance to coordinate our internalaudit and internal control compliance efforts and to oversee and ensureimprovements in our commodity transacting verification and monitoringcapabilities.

 

•                  Wehave implemented an internal audit outsourcing and technical consultationarrangement with a professional accounting and consulting firm.

 

•                  Wehave hired a Director of Risk Management and staff to establish appropriateverification and monitoring activities associated with our commoditytransacting.

 

Allof these resources were added in the third and fourth quarters of 2005 or thefirst quarter of 2006 and, while we believe we have substantially improved ourorganizational capabilities, the full impact of the changes had not beenrealized by December 31, 2005.  Wewill continue to evaluate our resources and remain committed to adding thenecessary resources as needs are identified.

 

Wehave and will continue to implement changes to our processes to improvedisclosure controls and procedures and to improve our internal control overfinancial reporting.  Among the changeswe have made and intend to make are the following:

 

•                  Wehave formalized the monthly account reconciliation process for all balancesheet accounts.  We have also implementeda formal review of reconciliations by our business unit accounting management.

 

•                  Wehave established a Compliance Office focused on control deficiencyidentification and remediation, i.e., purchasing controls, revenue recognitioncontrols and application and spreadsheet change controls.  The Compliance Office performs ongoinginternal control evaluation and assessment and works actively with the processowners in developing appropriate remediation of control deficiencies.

 

•                  Wehave conducted an entity-level risk assessment, established an internal auditplan and we have begun to execute that internal audit plan.  Results are reported directly to our auditcommittee.

 

•                  Weare segregating front-office, mid-office and back-office processes related tocommodity transacting to ensure that proper segregation of duties exists andthat control procedures are carried out by the appropriate groups.  We are enhancing hedge reporting to executivemanagement.  We are enhancing riskmanagement policies and procedures related to the review and approval ofmaterial purchase or sale contracts that may meet the definition of derivatives.

 

•                  Wehave enhanced entity level controls through the implementation of significantnew controls.   We have strengthened ourdisclosure review committee charter to solicit and review input from managementpersonnel throughout the Company regarding possible instances of fraud orsignificant events requiring disclosure. Also, we have implemented a technical accounting issues forum to addressnon-routine transactions and the use of estimates and judgment.

 

90

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•                  Weare enhancing employee awareness of our Code of Conduct, ethics and anti-fraudpolicies, including a revised training program to be delivered to all employeesin 2006.  This includes heightenedawareness of the ethics hotline availability and access options.

 

•                  Weare conducting a detailed review and re-documentation of all of our controlprocesses and will undertake significant control design changes to ensure thatall control objectives are met.

 

Webelieve that the foregoing actions have improved and will continue to improveour internal control over financial reporting, as well as our disclosurecontrols and procedures.  However, giventhe breadth of areas affected, it will take time to remediate all of ourmaterial weaknesses.  Our management,with oversight of our audit committee, will continue to identify and take stepsto remedy all known material weaknesses as expeditiously as possible andenhance the overall design and capability of our control environment.

 

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**REPORT OF INDEPENDENT REGISTEREDPUBLIC ACCOUNTING FIRM**

 

To the Board of Directors ofMarkWest Hydrocarbon, Inc. **Englewood, Colorado

 

We have audited management’s assessment,included in the accompanying Management’s Report on Internal Control overFinancial Reporting, that MarkWest Hydrocarbon, Inc. and subsidiaries (the“Company”) did not maintain effective internal control over financial reportingas of December 31, 2005, because of the effect of the material weaknessesidentified in management’s assessment based on criteria established in *Internal Control—Integrated Framework*issuedby the Committee of Sponsoring Organizations of the Treadway Commission.  As described in Management’s Report onInternal Control over Financial Reporting, management excluded from their assessmentthe internal control over financial reporting at Javelina Company, JavelinaPipeline Company, Javelina Land Company L.L.C. (the “Gulf Coast Business Unit”),which was acquired on November 1, 2005, because the Gulf Coast BusinessUnit was acquired very late in the year, management did not include theinternal control processes for the Gulf Coast Business Unit in its assessmentof internal controls as of December 31, 2005.  The Gulf Coast Business Unit constitutes 3%and 42% of net and total assets, respectively, 3% of total revenues of theconsolidated financial statement amounts as of and for the year ended December 31,2005.  Accordingly, our audit did not include the internal control overfinancial reporting at the Gulf Coast Business Unit.** **The Company’smanagement is responsible for maintaining effective internal control overfinancial reporting and for its assessment of the effectiveness of internalcontrol over financial reporting.  Our responsibility is to express anopinion on management’s assessment and an opinion on the effectiveness of theCompany’s internal control over financial reporting based on our audit.

 

We conducted our audit inaccordance with the standards of the Public Company Accounting Oversight Board(United States).  Those standards require that we plan and perform theaudit to obtain reasonable assurance about whether effective internal controlover financial reporting was maintained in all material respects.  Ouraudit included obtaining an understanding of internal control over financialreporting, evaluating management’s assessment, testing and evaluating thedesign and operating effectiveness of internal control, and performing suchother procedures as we considered necessary in the circumstances.  Webelieve that our audit provides a reasonable basis for our opinions.

 

A company’s internal controlover financial reporting is a process designed by, or under the supervision of,the company’s principal executive and principal financial officers, or personsperforming similar functions, and effected by the company’s board of directors,management, and other personnel to provide reasonable assurance regarding thereliability of financial reporting and the preparation of financial statementsfor external purposes in accordance with generally accepted accountingprinciples.  A company’s internal control over financial reportingincludes those policies and procedures that (1) pertain to the maintenanceof records that, in reasonable detail, accurately and fairly reflect thetransactions and dispositions of the assets of the company; (2) providereasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally acceptedaccounting principles, and that receipts and expenditures of the company arebeing made only in accordance with authorizations of management and directorsof the company; and (3) provide reasonable assurance regarding preventionor timely detection of unauthorized acquisition, use, or disposition of thecompany’s assets that could have a material effect on the financial statements.

 

Because of the inherentlimitations of internal control over financial reporting, including thepossibility of collusion or improper management override of controls, materialmisstatements due to error or fraud may not be prevented or detected on atimely basis.  Also, projections of any evaluation of the effectiveness ofthe internal control over financial reporting to future periods are subject tothe risk that the controls may become inadequate because of changes inconditions, or that the degree of compliance with the policies or proceduresmay deteriorate.

 

A material weakness is asignificant deficiency, or combination of significant deficiencies, thatresults in more than a remote likelihood that a material misstatement of theannual or interim financial statements will not be prevented or detected. The following material weaknesses have been identified and included inmanagement’s assessment:

 

*Internal Control Environment* — The Company’scontrol environment did not sufficiently promote effective internal controlover financial reporting through their management structure to prevent amaterial misstatement, as was evidenced by deficiencies or significantdeficiencies in the following areas:

 

•                  *S**egregation ofduties* withincertain key processes was inadequate to support management’s assertions withrespect to accuracy and completeness of financial records.

 

•                  *Entitylevel controls* including the *anti-fraud program and controls*necessary to address the COSO elements of risk assessment, information andcommunication.

 

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•                  *Applicationcontrols* over financially significant applications withrespect to change management and information systems operations.

 

•                  *Fixedassets* controls including inappropriate authorization of invoices andimproper reconciliation procedures.

 

•                  *Financialreporting* controls related to the closing process includingcontrol over non-routine transactions, unusual journal entries and the use ofestimates and judgment.

 

•                  Controls over*expenditures* including inappropriate authorization ofinvoices and the inability to independently validate accuracy and validity ofamounts recorded.

 

•                  *S**preadsheetcontrols* related to change management within key financialspreadsheets.

 

•                  And, *accounting for income taxes*related toreconciliations of tax accounts.

 

*Risk Management and Accounting for DerivativeFinancial Instruments* —The Company did not have adequateinternal controls and processes in place to support management’s assertionswith respect to the completeness, accuracy and validity of commoditytransactions.  The design of internalcontrols over commodity transactions did not support independent validation ofdata or control and review of transacting activity. In particular, personnelresponsible for executing and entering transactions into commodity accountingsystems also have duties, which are not compatible with transaction executionand entry.

 

The material weaknessesresult from both a deficiency in the design of internal controls, as well as, adeficiency in the operating effectiveness of key controls relied on bymanagement.  The design deficienciesprimarily represent situations where control activities did not exist to meetcontrol objectives necessary to support the financial statementassertions.  Operating effectivenessdeficiencies were, in many cases, a result of the Company’s control activitiesthat were not performed adequately to address the control objective.  The significant turnover of accountingpersonnel in the fourth quarter of 2005 was a contributing factor in thefailure of key control activities to operate effectively.  As a result of the pervasive nature of thematerial weaknesses, the risk exists that the Company’s financial reportingprocesses and controls may not identify a material misstatement in theconsolidated financial statements.

 

These material weaknesseswere considered in determining the nature, timing, and extent of audit testsapplied in our audit of the consolidated financial statements as of and for theyear ended December 31, 2005, of the Company and this report does notaffect our report on such financial statements.

 

In our opinion, management’sassessment that the Company did not maintain effective internal control overfinancial reporting as of December 31, 2005, is fairly stated, in allmaterial respects, based on the criteria established in *Internal Control—Integrated Framework*issuedby the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, because of the effect of the material weaknesses describedabove on the achievement of the objectives of the control criteria, the Companyhas not maintained effective internal control over financial reporting as of December 31,2005, based on the criteria established in *InternalControl—Integrated Framework*issued by the Committee of SponsoringOrganizations of the Treadway Commission.

 

We have also audited, inaccordance with the standards of the Public Company Accounting Oversight Board(United States), the consolidated financial statements as of and for the yearended December 31, 2005, of the Company and our report dated March 17,2006 expressed an unqualified opinion on those financial statements.

 
| /s/ DELOITTE &  TOUCHE LLP |   |
|-------------------------------------|--------|
|                                |
| Denver, Colorado                    |
| March 20, 2006                 |

 

**ITEM 9B.****                                            OTHERINFORMATION**

 

None.

 

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**ITEM 10.****                                              DIRECTORSAND EXECUTIVE OFFICERS OF THE REGISTRANT**

 

The following table shows information for thedirectors and executive officers of MarkWest Hydrocarbon, Inc. Executiveofficers are appointed and directors are elected for three-year terms.

 
| **Name**              | ** ** | **Age** | ** ** | **Position**                                       | ** ** |
|-----------------------|------------|---------|------------|----------------------------------------------------|------------|
|                  |       |    |       |                                               |       |
| John M. Fox           |       | 65      |       | Chairman of  the Board of Directors                |       |
| Michael L.  Beatty    |       | 58      |       | Director                                           |       |
| Donald C.  Heppermann |       | 63      |       | Director                                           |       |
| William A.  Kellstrom |       | 64      |       | Director                                           |       |
| Anne E.  Mounsey      |       | 39      |       | Director                                           |       |
| Karen L.  Rogers      |       | 49      |       | Director                                           |       |
| William F.  Wallace   |       | 66      |       | Director                                           |       |
| Donald D.  Wolf       |       | 62      |       | Director                                           |       |
| Frank M.  Semple      |       | 54      |       | President,  Chief Executive Officer and Director   |       |
| C. Corwin  Bromley    |       | 48      |       | Vice  President, General Counsel and Secretary     |       |
| James G.  Ivey        |       | 54      |       | Senior Vice  President and Chief Financial Officer |       |
| Nancy K.  Masten      |       | 36      |       | Senior Vice  President, Chief Accounting Officer   |       |
| John C.  Mollenkopf   |       | 44      |       | Senior Vice  President, Southwest Business Unit    |       |
| Randy S.  Nickerson   |       | 44      |       | Senior Vice  President, Corporate Development      |       |
| Richard A.  Ostberg   |       | 40      |       | Vice  President, Risk and Compliance               |       |
| Andrew L.  Schroeder  |       | 47      |       | Vice  President, Finance and Treasurer             |       |
| David L.  Young       |       | 46      |       | Senior Vice  President, Northeast Business Unit    |       |

 

**John M. Fox** hasserved as MarkWest Hydrocarbon’s Chairman of the Board of Directors since itsinception in April 1988, and in the same capacity for the general partnerof MarkWest Energy since May 2002. Mr. Fox also served as Presidentand Chief Executive Officer of MarkWest Hydrocarbon and the general partner ofMarkWest Energy from April 1988 until his retirement as President onNovember 1, 2003 and his resignation as Chief Executive Officer effectiveDecember 31, 2003. Mr. Fox was a founder of Western GasResources, Inc. and was its Executive Vice President and Chief OperatingOfficer from 1972 to 1986.

 

**MichaelL. Beatty**has served as a member of the Board ofDirectors of MarkWest Hydrocarbon, Inc. since June 2005. Mr. Beatty iscurrently Chairman and CEO of the law firm of Beatty & Wozniak, P.C. locatedin Denver, Colorado, with a practice focused on energy, oil and gas, businessand commercial litigation. A Harvard Law School graduate, Mr. Beatty began hiscareer in the energy industry as in-house counsel for Colorado Interstate GasCompany, and ultimately became Executive Vice President, General Counsel and aDirector of The Coastal Corporation. Mr. Beatty also served as Chief of Staffto Colorado Governor Roy Romer from 1993 to 1995. Mr. Beatty has handled numerous energyrelated cases in his career, including successfully arguing a case before theU. S. Supreme Court. Prior to his work as an energy litigator, Mr. Beatty was atenured law professor at the University of Idaho, and visiting law professor atthe University of Wyoming. Mr. Beatty graduated from the University ofCalifornia, Berkeley with a Bachelor of Arts degree, and received his jurisdoctorate from Harvard Law School. Mr. Beatty has also been active in a numberof civic organizations, including as a member of the board of directors of theColorado Leadership Alliance and of the Bighorn Action Committee, and served ascoach with several championship teams in the Colorado State High School MockTrial competitions.

 

**Donald C. Heppermann**served as Executive Vice President, Chief Financial Officer and Secretary ofMarkWest Hydrocarbon, Inc. and the general partner of MarkWest Energysince October 2003 until his retirement in March 2004. Mr. Heppermannjoined MarkWest Hydrocarbon and the general partner of the Partnership inNovember 2002 as Senior Vice President and Chief Financial Officer, andserved as Senior Executive Vice President beginning in January 2003. Mr. Heppermannhas served as a member of the Company’s Board of Directors sinceNovember 2002 and the general partner of the Partnership’s board ofdirectors since its inception in May 2002 and serves as Chairman of theFinance Committee. Prior to joining MarkWest Hydrocarbon and the generalpartner of MarkWest Energy, Mr. Heppermann was a private investor and acareer executive in the energy industry with responsibilities in operations,finance, business development and strategic planning. From 1990 to 1997,Mr. Heppermann served as President and Chief Operating Officer forInterCoast Energy Company, an unregulated subsidiary of Mid American EnergyCompany. From 1987 to 1990, Mr. Heppermann was employed by Pinnacle WestCapital Corporation, the holding company for Arizona Public Service Company,where he was Vice President of Finance. From 1965 to 1987, Enron Corporationand its predecessors employed Mr. Heppermann in a

 

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variety of positions, includingExecutive Vice President, Gas Pipeline Group.

 

**William A. Kellstrom**has served as a member of the Board of Directors of MarkWest Hydrocarbon sinceMay 2000 and the general partner of MarkWest Energy since its inception inMay 2002. Mr. Kellstrom has held a variety of managerial positions inthe natural gas industry since 1968. They include distribution, pipelines andmarketing. He held various management and executive positions with EnronCorporation, including Executive Vice President, Pipeline Marketing and SeniorVice President, Interstate Pipelines. In 1989, he created and was President ofTenaska Marketing Ventures, a gas marketing company for the Tenaska Power Group.From 1992 until 1997 he was with NorAm Energy Corporation (since merged withReliant Energy, Incorporated) where he was President of the Energy MarketingCompany and Senior Vice President, Corporate Development. Mr. Kellstromretired in 1997 and is periodically engaged as a consultant to energycompanies.

 

**Anne E. Mounsey**has served as a member of theCompany’s Board of Directors since October 2004. From 1991 to 2003,Ms. Mounsey held various positions with the Company, her most recent asManager of Marketing and Business Development. Ms. Mounsey is the daughterof John M. Fox, the Company’s Chairman of the Board of Directors.

 

**Karen L. Rogers**hasserved as a member of the Board of Directors of MarkWest Hydrocarbon sinceJune 2000. In June 2005, Ms. Rogers joined BlacksandEnergy, Inc., a privately held oil and gas development and productioncompany, as the chief financial officer. Prior to joining BlacksandEnergy, Inc. Ms. Rogers was employed since 2000 as Vice President,Energy Group, for Wells Fargo Bank N.A. Prior to 1997, Ms. Rogers wasSenior Vice President and Manager of NationsBank Energy Group Denver, Inc.She has more than 25 years of experience in energy finance and corporatebanking.

 

**William F. Wallace**has served as a member of theBoard of Directors of MarkWest Hydrocarbon since June 2004. Prior to hisretirement in 2001, Mr. Wallace was Vice Chairman of the board ofdirectors of Barrett Resources Corp. since 1996, after being named to thatposition in 1995 following the merger of Barrett Resources and Plains PetroleumCo., both oil and gas exploration companies. From 1994 to 1995,Mr. Wallace was President, Chief Operating Officer and a Director ofPlains Petroleum Co. Prior to joining Plains Petroleum, Mr. Wallace spent23 years with Texaco Inc., an integrated oil and gas company, including sixyears as Vice President of Exploration for Texaco USA and as Regional VicePresident of Texaco’s Eastern Region. Mr. Wallace has served on the KerrMcKee Corporation board of directors since 2004. Previously, he served as adirector of Westport Resources Corporation from 1997 until Westport’s mergerwith Kerr McKee Corporation in 2004.

 

**Donald D. Wolf**has served as a member of theCompany’s Board of Directors since June 1996. In September 2004,Mr. Wolf joined Aspect Energy as President and Chief Executive Officer. Mr. Wolfserved as Chairman, Chief Executive Officer and Director of Westport ResourcesCorporation from April 2000 until Westport’s merger with Kerr McKee Corporationin 2004. He joined Westport Oil and Gas Company, Inc. in June 1996 asChairman and Chief Executive Officer and has a diversified 35-year career inthe oil and natural gas industry.

 

**Frank M. Semple** wasappointed as President of both MarkWest Hydrocarbon and the general partner ofMarkWest 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, most recently as Chief OperatingOfficer of WilTel Communications, formerly Williams CommunicationsGroup, Inc. (“WCG”) from 1997 to 2003. Prior to his tenure at WilTelCommunications, he was the Senior Vice President/General Manager of WilliamsNatural Gas from 1995 to 1997, Vice President of Marketing and Vice Presidentof Operations and Engineering for Northwest Pipeline, and Director of ProductMovements and Division Manager for Williams Pipeline during his 22-year careerwith The Williams Companies. During his tenure at Williams Communications, healso served on the board of directors for PowerTel Communications and theCompetitive Telecommunications Association (Comptel). 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 enteredan order confirming the Debtors’ plan of reorganization that became effectiveOctober 15, 2002. Mr. Semple holds a Mechanical Engineering degree fromthe United States Naval Academy and is a professional engineer registered inthe state of Kansas.

 

**C. Corwin Bromley******has served as Vice President, General Counsel and Secretaryof both MarkWest Hydrocarbon and the general partner of MarkWest Energy sinceSeptember 2004. Prior to that, Mr. Bromley served as AssistantGeneral Counsel at RAG American Coal Holding, Inc. from 1999 through 2004,and as General-Managing Attorney at Cyprus Amax Minerals Company from 1989 to1999. Prior to that, Mr. Bromley spent four years in private practice withthe law firm Popham, Haik, Schnobrich & Kaufman. Preceding his legalcareer, Mr. Bromley was employed by CBI, Inc. as a structural/designengineer involved in several LNG and energy projects. Mr. Bromley receivedhis J.D. from the University of Denver and his bachelor’s degree in civilengineering from the University of Wyoming.

 

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**James G. Ivey** hasserved as Chief Financial Officer of both MarkWest Hydrocarbon and the generalpartner of MarkWest Energy since June 2004. Prior to joining the Company,Mr. Ivey served as Treasurer of The Williams Companies from 1999 toApril 30, 2004, and as acting Chief Financial Officer from mid 2002 to mid2003. Prior to joining Williams, Mr. Ivey held similar positions withTenneco Gas and NORAM Energy. Prior to that, he held various engineeringpositions with Conoco and Fluor Corporation. He currently serves on the boardsof directors for MACH Gen LLC, National Energy & GasTransmission, Inc. and the Tulsa Boys Home. Mr. Ivey retired in early2004 from the Army Reserve with the rank of colonel. Mr. Ivey is a graduate ofTexas A&M University and has an MBA from the University of Houston. He isalso a graduate of the Army Command and General Staff College.

 

**Nancy K. Masten**wasappointed Chief Accounting Officer of both MarkWest Hydrocarbon and the generalpartner of MarkWest Energy in November 2005. Previous to her appointment, Ms.Masten was the Chief Financial Officer for Experimental and Applied Sciences("EAS") in Golden, Colorado. EAS is a wholly owned subsidiary of theRoss Product Division of Abbott Laboratories. Prior to her employment at EAS,Ms. Masten was a Vice President with TransMontaigne Inc. in Denver, Colorado. Precedingthis appointment, Ms. Masten was a Partner with Ernst & Young LLP, havingspent time in the firm's Denver, London, New York and Washington, D.C. offices.

 

**John C. Mollenkopf**wasappointed Senior Vice President, Southwest Business Unit, of MarkWestHydrocarbon and the general partner of MarkWest Energy in January 2004. Previouslyhe served as Vice President, Business Development of the Company sinceJanuary 2003. Prior to that, he served as Vice President, MichiganBusiness Unit, of MarkWest Energy’s general partner since its inception inMay 2002 and in the same capacity with MarkWest Hydrocarbon sinceDecember 2001. Prior to that, Mr. Mollenkopf was General Manager ofthe Michigan Business Unit of MarkWest Hydrocarbon since 1997. He joinedMarkWest Hydrocarbon in 1996 as Manager, New Projects. From 1983 to 1996,Mr. Mollenkopf worked for ARCO Oil and Gas Company, holding variouspositions in process and project engineering, as well as operationssupervision.

 

**Randy S. Nickerson**has served as Senior Vice President, Corporate Development of MarkWestHydrocarbon and MarkWest Energy’s general partner since October 2003. Priorto that, Mr. Nickerson served as Executive Vice President, CorporateDevelopment of the Partnership’s general partner since January 2003 and asSenior Vice President of the Partnership’s general partner since its inceptionin May 2002 and has served in the same capacity with MarkWest Hydrocarbonsince December 2001. Prior to that, Mr. Nickerson served as MarkWestHydrocarbon’s Vice President and the General Manager of the Appalachia BusinessUnit since June 1997. Mr. Nickerson joined MarkWest Hydrocarbon inJuly 1995 as Manager, New Projects and served as General Manager of theMichigan Business Unit from June 1996 until June 1997. From 1990 to1995, Mr. Nickerson was a Senior Project Manager and Regional EngineeringManager for Western Gas Resources, Inc. From 1984 to 1990,Mr. Nickerson worked for Chevron USA and Meridian Oil Inc. in variousprocess and project engineering positions.

 

**Richard A. Ostberg**was appointed the Vice President of Risk and Compliance of MarkWest Hydrocarbonand the general partner of MarkWest Energy in July 2005. Prior to that, Mr.Ostberg served as Vice President and Controller of Black Hills Energy. Prior toBlack Hills, Mr. Ostberg spent four years with Pacific Minerals, Inc, theoperator of the Bridger Coal mine and spent eight years with Deloitte &Touche in their audit practice, including two years consulting from hisnational office assignment in Washington, D.C.

 

**Andrew L. Schroeder******has served as VicePresident and Treasurer of MarkWest Hydrocarbon and the Partnership’s generalpartner since February 2003. Prior to his appointment, he was Director ofFinance/Business Development at Crestone Energy Ventures from 2001 through 2002.Prior to that, Mr. Schroeder worked at Xcel Energy for two years asDirector of Corporate Financial Analysis. Prior to that, he spent seven yearsworking with various energy companies. He began his career with Touche,Ross & Co. and spent eight years in public accounting. He is aCertified Public Accountant licensed in the state of Colorado.

 

**David L. Young**wasappointed Senior Vice President, Northeast Business Unit of MarkWestHydrocarbon and the Partnership’s general partner effective February 1,2004. Prior to joining MarkWest, Mr. Young spent eighteen years at TheWilliams Companies, Inc. in Tulsa, Oklahoma, having served most recentlyas Vice President and General Manager of the video services business for WilTelCommunications, formerly WCG from 1997 to 2003. 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 forrelief under the Bankruptcy Code with the United States Bankruptcy Court forthe 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.

 

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**Part III**

 

# **Audit Committee Financial Expert**

 

The members of the Company’s Audit Committee of the Board of Directorsare Mr. Kellstrom (chairman), Mr. Beatty, Ms. Rogers,Mr. Wallace and Mr. Wolf. Each of the individuals serving on ourAudit Committee satisfies the standards for independence of the AMEX and theSEC as they relate to audit committees. Our Board of Directors believes each ofthe members of the Audit Committee is financially literate. In addition, ourBoard of Directors has determined that Mr. Kellstrom is financiallysophisticated and qualifies as an “audit committee financial expert” within themeaning of the regulations of the SEC.

 

**Audit Committee Pre-Approval Policy**

** **

 The Audit Committee pre-approves all audit and permissiblenon-audit services provided by the independent auditors on a case-by-case basis.These services may include audit services, audit-related services, tax servicesand other services. Our Chief Accounting Officer is responsible for presentingthe Audit Committee with an overview of all proposed audit, audit-related, taxor other non-audit services to be performed by the independent auditors. Thepresentation must be in sufficient detail to define clearly the services to beperformed. The Audit Committee does not delegate its responsibilities topre-approve services performed by the independent auditor to management or to anindividual member of the Audit Committee. The Audit Committee may, however,from time to time delegate its authority to the Audit Committee Chairman, whoreports on the independent auditor services approved by the Chairman at thenext Audit Committee meeting.

 

**Code of Conduct and Ethics**

** **

We have adopted a Code of Conduct and Ethics that complies with SECstandards, applicable to the persons serving as our directors, officers(including, without limitation, our CEO, CFO, CAO and Principal FinancialOfficer) and employees. This includes the prompt disclosure to the SEC of aCurrent Report on Form 8-K of any waiver of the code for executiveofficers or directors approved by the board of directors. A copy of our Code ofBusiness Conduct and Ethics is available free of charge in print to anyshareholder who sends a request to the office of the Secretary of MarkWestHydrocarbon, Inc. at 155 Inverness Drive West, Suite 200, Englewood,Colorado 80112-5000. The Code of Conduct and Ethics is also posted on ourwebsite, www.markwest.com.

 

**Section 16(a) Beneficial OwnershipReporting Compliance**

** **

Section 16(a) of the Securities Exchange Act of 1934 requiresour directors and executive officers, and persons who own more than 10% of anyclass of our equity securities registered under Section 12 of the ExchangeAct, to file with the SEC initial reports of ownership and reports of changesin ownership in such securities and other equity securities of our Company. SECregulations also require directors, executive officers and greater than 10%stockholders to furnish us with copies of all Section 16(a) reportsthey file.

 

To our knowledge, based solely on review of the copies of such reportsfurnished to us and written representations that no other reports wererequired, we believe our directors, executive officers and greater than 10%stockholders complied with all Section 16(a) filing requirementsduring the year ended December 31, 2005, except for the following:

 
| ** **      | ** ** | **No. of Late  Reported  Transactions** | ** ** | **No. of Late  Form 3 Filings** | ** ** | **No. of Late  Form 4 Filings** | ** ** |
|-----------------|------------|----------------------------------------------|------------|-------------------------------------------|------------|-------------------------------------------|------------|
| Mr. Fox         |       | 2                                            |       | —                                    |       | 2                                         |       |
| Mr. Beatty      |       | 2                                            |       | 1                                         |       | 1                                         |       |
| Mr.  Heppermann |       | 2                                            |       | —                                    |       | 2                                         |       |
| Mr.  Kellstrom  |       | 2                                            |       | —                                    |       | 2                                         |       |
| Ms. Mounsey     |       | 1                                            |       | —                                    |       | 1                                         |       |
| Ms. Rogers      |       | 2                                            |       | —                                    |       | 2                                         |       |
| Mr. Wallace     |       | 3                                            |       | —                                    |       | 3                                         |       |
| Mr. Wolf        |       | 2                                            |       | —                                    |       | 2                                         |       |
| Mr. Ostberg     |       | 1                                            |       | 1                                         |       | —                                    |       |

 

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We are not aware of any other failure to file aSection 16(a) form with the SEC, or any transaction that was requiredto be reported, but that was not reported on a timely basis.

 

# **ITEM 11.**                                              EXECUTIVE COMPENSATION

# ** **

The following table sets forth the cash and non-cash compensationearned for fiscal years 2005, 2004 and 2003 by each person who served as ChiefExecutive Officer of the Company in 2005 and the four other highest paidofficers, whose salary and bonus exceeded $100,000 for services rendered during2005 (the “Named Executive Officers”).

 

**Summary Compensation Table**

 
| ** **                                      | ** ** | **Annual Compensation** | ** ** | **Long-Term Compensation**               | ** ** |
|-------------------------------------------------|------------|-------------------------|------------|------------------------------------------|------------|
| **Name and Principal Positions**                | ** ** | ** **              | ** ** | **Restricted  Unit  Awards  ($)****(3)** | ** ** | **LTIP  Payouts  ($)****(4)** | ** ** | **Other  Compensation  ($)****(5)** | ** ** |
| ** **                                      |
| **Fiscal  Year**                                | ** ** | **Salary  ($)****(1)**  | ** ** | **Bonus  ($)****(2)**                    |
|                                            |       |                    |       |                                     |       |   |   |   |   |   |   |   |   |
| Frank M. Semple                                 |       | 2005                    |       | $                                        | 288,462    |   | $ | 143,000 |   | $ | 84,280 |   | $ | 22,634 |   | $ | 20,550 |   |
| President and Chief Executive Officer           |       | 2004                    |       | 280,385                                  |       | 47,250 |   | 108,750 |   | 20,500 |   | 52,838 |   |
|                                            |       | 2003                    |       | 36,346                                   |       | 6,413 |   | 279,000 |   | 4,800 |   | 623 |   |
|                                            |       |                    |       |                                     |       |   |   |   |   |   |   |   |   |
| James G. Ivey (6)                               |       | 2005                    |       | $                                        | 218,846    |   | $ | 60,000 |   | $ | 27,567 |   | $ | 21,661 |   | $ | 18,965 |   |
| Chief Financial Officer                         |       | 2004                    |       | 126,154                                  |       | 5,979 |   | 251,500 |   | 8,640 |   | 37,408 |   |
|                                            |       | 2003                    |       | —                                   |       | — |   | — |   | — |   | — |   |
|                                            |       |                    |       |                                     |       |   |   |   |   |   |   |   |   |
| Randy S. Nickerson                              |       | 2005                    |       | $                                        | 188,846    |   | $ | 97,000 |   | $ | 41,088 |   | $ | 9,536 |   | $ | 19,677 |   |
| Senior Vice President, Corporate  Development   |       | 2004                    |       | 181,155                                  |       | 30,625 |   | 108,750 |   | 5,363 |   | 13,686 |   |
|                                            |       | 2003                    |       | 164,743                                  |       | 23,515 |   | 26,875 |   | 10,675 |   | 13,193 |   |
|                                            |       |                    |       |                                     |       |   |   |   |   |   |   |   |   |
| John C. Mollenkopf                              |       | 2005                    |       | $                                        | 184,231    |   | $ | 95,000 |   | $ | 41,088 |   | $ | 6,336 |   | $ | 19,400 |   |
| Senior Vice President, Southwest Business  Unit |       | 2004                    |       | 180,865                                  |       | 30,625 |   | 65,250 |   | 6,703 |   | 13,426 |   |
|                                            |       | 2003                    |       | 144,354                                  |       | 20,684 |   | 59,475 |   | 11,985 |   | 12,331 |   |
|                                            |       |                    |       |                                     |       |   |   |   |   |   |   |   |   |
| David L. Young (7)                              |       | 2005                    |       | $                                        | 181,462    |   | $ | 72,000 |   | $ | 34,717 |   | $ | 7,699 |   | $ | 8,077 |   |
| Senior Vice President, Northeast Business  Unit |       | 2004                    |       | 161,538                                  |       | 25,521 |   | 77,000 |   | 4,380 |   | — |   |
|                                            |       | 2003                    |       | —                                   |       | — |   | — |   | — |   | — |   |

 

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(1)          Represents actual salarypaid in each respective fiscal year for services rendered on behalf of both thePartnership and MarkWest Hydrocarbon.

(2)          Represents actual bonus paid in each respective fiscal year forservices rendered on behalf of both the Partnership and MarkWest Hydrocarbon.Bonuses are paid in accordance with provisions of MarkWest Hydrocarbon’sIncentive Compensation Plan.

(3)          Represents the value of the executive officer’s MarkWest Energyrestricted unit awards plus the MarkWest Hydrocarbon restricted share awards(calculated by multiplying the closing market price of the correspondingsecurities on the date of grant by the number of units or shares awarded). Asof December 31, 2005, the named executives held an aggregate of 14,083restricted units and 5,279 restricted shares with an aggregate market value of$770,205.

(4)          Represents distributions received for restricted units and restrictedshares.

(5)          Represents actual MarkWest Hydrocarbon contributions under MarkWestHydrocarbon’s 401(k) Savings and Profit Sharing Plan. Included inMr. Semple’s and Mr. Ivey’s other compensation, in 2004, arerelocation payments of $34,453 and $37,408, respectively.

(6)          Mr. Ivey became the Chief Financial Officer on May 25, 2004. Mr. Iveyis currently being paid an annual salary of $220,000.

(7)          Mr. Young became the Senior Vice President of the NortheastBusiness Unit on February 2, 2004. Mr. Young is currently being paidan annual salary of $185,000.

 

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# **Option Grants in Last Year**

# ** **

# **None**

# ** **

# **SAR Grants in Last Year**

 

The Company has also entered into arrangements with certain directorsand officers of the Company.  These arrangements are referred to as theParticipation Plan.  Under the Participation Plan, the Company sellssubordinated partnership units of the Partnership and interests in thePartnership’s general partner to employees and directors of the Company under apurchase and sale agreement.  The interests in the general partner aresold with certain put and call provisions that allow the individual to requireMarkWest Hydrocarbon to buy back or requires the individual to sell back theirinterest in the general partner to MarkWest Hydrocarbon.  As the formulaused to determine the sale and buy-back price is not based on fair value,coupled with the attributes of the put and call provisions, these transactionsare considered compensatory arrangements, similar to a stock appreciationright.  The subordinated partnership units of the Partnership are alsosold to the employees and directors at a formula that is not based on fairvalue.  The subordinated units are sold without any restrictions ontransfer.  The Company has established an implied repurchase obligationhowever, through its pattern of buying back the subordinated units each time anemployee or director has left MarkWest Hydrocarbon.  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, 2005.  There were no subordinatedpartnership units sold during 2005.  All interests were sold under theCompany’s Participation Plan.  The plan has not been approved by theStockholders.

 
| **Individual Grants**                                                   | ** ** | **Exercise or base**                       | ** ** | **Expiration**                 | ** **   | **Potential realizable value at  assumed annual rates of  stock price appreciation for  SAR term** | ** ** | **Grant Date**      | ** ** |
|------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|--------------------------------|--------------|------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------|------------|
| **Percent of General  Partner Interest  underlying SAR** | ** ** | **Percent of  SARs granted  to employees** |
| **granted (%)**                                                         | ** ** | **in year**                                     | ** ** | **price ($ /Sh)(1)** | ** **   | **date(2)**                                                                                                                                          | ** ** | **5% ($ )(2)** | ** ** | **10% ($ )(2)** | ** ** | **Present Value ($ )** | ** ** |
|                                                                         |       |                                                 |       |                           |         |                                                                                                                                                 |       |                     |       |   |   |   |   |
| —                                                                       |       |                                                 |       | $                              |  — |                                                                                                                                                 | —     |                     | $          |  — |   | $ |  — |   | $ |  — |   |
|                                                                              |            |                                                      |            |                                |              |                                                                                                                                                      |            |                          |            |  |  |  |  |  |  |  |  |

 

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(1)  The Companysells interests in the Partnership’s general partner under a variable plan tocertain directors and employees of the Company. The interest in thePartnership’s general partner are sold with certain put and call provisionsthat allow the individual to require MarkWest Hydrocarbon to buy back orrequires the individual to sell their interest in the general partner toMarkWest 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 the then existingmembers; (3) any amendment, alteration or repeal of the provisions of thegeneral partner agreement is undertaken which materially and adversely affectsthe then existing rights, duties, obligations or restrictions of the employeesand directors; 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 has 120 days after the put event toexercise the put under (4) and 30 days after notice to exercise under(1) through (3).  MarkWest Hydrocarbon can exercise its call optionif the employee or director ceases to be a director or employee of MarkWestHydrocarbon or any of its affiliates or if there is a change of control. The Company has 12 months following the termination date to exercise its calloption.  As the formula used to determine the sale and buy-back price isnot based on fair value, coupled with the attributes of the put and callprovisions, these transactions are considered compensatory arrangements,similar to a stock appreciation right.  As the stock appreciation right isexercised through a callable or puttable event, there is no defined expirationdate.

 

99

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(2)  Theinterests in the Partnership’s general partner are sold without an expirationdate.  As a result, when calculating the potential realizable value of theappreciation of the award, the Company assumed a 10 year life to be consistentwith the terms used on the Company’s other stock based compensation awards.

 

# **Aggregated Option Exercises inLast Year and Year-End Option Values**

 

The following tableprovides information as to options exercised during the year endedDecember 31, 2005, and the value of outstanding options held by the NamedExecutive Officers at December 31, 2005.

 
| ** **          | ** ** | **Shares  Acquired on** | ** ** | **Value**                   | ** ** | **Number of Securities  Underlying Unexercised  Options at End of 2005 (#)** | ** ** | **Value of Unexercised In-the-  Money Options at End of 2005  (#)** | ** ** |
|---------------------|------------|------------------------------|------------|-----------------------------|------------|----------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------------------------------|------------|
| ** **          | ** ** | **Exercise (#)**        | ** ** | **Realized ($ )** | ** ** | **Exercisable**                                                                                                      | ** ** | **Unexercisable**                                                                                           | ** ** | **Exercisable** | ** ** | **Unexercisable** | ** ** |
| ** **          | ** ** | ** **                   | ** ** | ** **                  | ** ** | ** **                                                                                                           | ** ** | ** **                                                                                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Frank M. Semple     |       | —                       |       | $                           | —     |                                                                                                                 | 11,000     |                                                                                                        | 11,000     |   | $ | 137,110 |   | $ | 137,110 |   |
| James G. Ivey       |       | —                       |       | —                      |       | 2,750                                                                                                                |       | 8,250                                                                                                       |       | 32,652 |   | 97,957 |   |
| Randy S. Nickerson  |       | —                       |       | —                      |       | 3,859                                                                                                                |       | —                                                                                                      |       | 53,832 |   | — |   |
| John C. Mollenlkopf |       | —                       |       | —                      |       | 7,119                                                                                                                |       | —                                                                                                      |       | 102,070 |   | — |   |
| David L. Young      |       | —                       |       | —                      |       | 687                                                                                                                  |       | 2,063                                                                                                       |       | 8,201 |   | 24,627 |   |
|                     |            |                              |            |                             |            |                                                                                                                      |            |                                                                                                             |            |  |  |  |  |  |  |  |

 

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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, 2005, and theoption price per share multiplied by the number of shares subject to theoption.

 

# **Aggregated SAR Exercises inLast Year and Year-End SAR Values**

 

The following tableprovides information as to the value of the subordinated partnership units ofthe Partnership and interests in the Partnership’s general partner held by theNamed Executive Officers at December 31, 2005.  We did not buy backany of the subordinated partnership units of the Partnership or interests inthe Partnership’s general partner from the Named Executive Officers during the yearended December 31, 2005.

 
| ** **          | ** ** | **Percent of General  Partner Interest  Underlying Unexercised  SAR at End of 2005  (%)(1)** | ** ** | **Number of  Partnership  subordinated units  Underlying  Unexercised SAR at  End of 2005 (#)(1)** | ** ** | **Value of GP Interest  Underlying SAR at  End of 2005 ($ )(2)** | ** ** | **Value of  Subordinated Units  Underlying SAR at  End of 2005 ($ )(3)** | ** ** |
|---------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------------------|------------|
| ** **          | ** ** | ** **                                                                                                                           | ** ** | ** **                                                                                                                            | ** ** | ** **                                                                                                    | ** ** | ** **                                                                                                       | ** ** |
| Frank M. Semple     |       | 2.0                                                                                                                                  | %          | —                                                                                                                                |       | $                                                                                                             | 1,403,961  |                                                                                                             | —     |   |
| James G. Ivey       |       | 0.5                                                                                                                                  | %          | —                                                                                                                                |       | 201,547                                                                                                       |       | —                                                                                                           |       |
| Randy S. Nickerson  |       | 1.6                                                                                                                                  | %          | —                                                                                                                                |       | 1,179,349                                                                                                     |       | —                                                                                                           |       |
| John C. Mollenlkopf |       | 1.6                                                                                                                                  | %          | —                                                                                                                                |       | 1,179,349                                                                                                     |       | —                                                                                                           |       |
|                     |            |                                                                                                                                      |            |                                                                                                                                       |            |                                                                                                               |            |                                                                                                                  |            |  |

 

----

(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.  These arrangements are referred to as theParticipation 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.  The interest in the Partnership’s generalpartner are sold with certain put and call provisions that allow the individualto require MarkWest Hydrocarbon to buy back or requires the individual to selltheir interest in the general partner to MarkWest Hydrocarbon. Specifically, the employees and directors can exercise their put if(1) MarkWest Hydrocarbon or the Partnership’s general partner undergoes achange of control; (2) additional membership interests are issued and ifthe issuance of additional membership interests, on a pro forma basis,decreases the distributions to all the then existing members; (3) anyamendment, alteration or repeal of the provisions of the general partneragreement is undertaken which materially and adversely affects the then existingrights, duties,

 

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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 estatehas 120 days after the put event to exercise the put under (4) and 30 daysafter notice to exercise under (1) through (3).  MarkWest Hydrocarboncan exercise its call option if the employee or director ceases to be adirector or employee of MarkWest Hydrocarbon or any of its affiliates or ifthere is a change of control.  The Company has 12 months following thetermination date to exercise its call option.  As the formula used todetermine the sale and buy-back price is not based on fair value, coupled withthe attributes of the put and call provisions, these transactions areconsidered compensatory arrangements, similar to a stock appreciationright.  The subordinated partnership units of the Partnership are alsosold to the employees and directors at a formula that is not based on fairvalue.  The subordinated units are sold without any restrictions ontransfer.  The Company has established an implied repurchase obligationhowever, through its pattern of buying back the subordinated units each time anemployee or director has left MarkWest Hydrocarbon.  The employees’ anddirectors’ subordinated units converted into MarkWest Energy’s common units onAugust 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 the executive. The formula value is the amount MarkWest Hydrocarbon would have to pay theemployees and directors to repurchase the Partnership’s general partnerinterests which is derived from the current market value of the Partnership’scommon units, as reported by the American Stock Exchange on December 31,2004, and the quarterly distributions 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 onDecember 31, 2004, and the amount paid by the named executive.

 

## **Indemnification Agreements**

 

In February 2004,MarkWest Hydrocarbon entered into Indemnification Agreements with certaindirectors and officers (“Indemnitees”).  By the terms of theIndemnification Agreement, the Company shall indemnify Indemnitees to thefullest extent permitted by law against all expenses and liabilities (as definedin the Indemnification Agreement) if Indemnitees were or are, or are threatenedto be made 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 inthe right of the Company or otherwise, by reason of (or arising in part out of)any event or occurrence related to the fact that Indemnitees are or were adirector, officer, employee, agent or fiduciary of the Company, or anysubsidiary of the Company, or are or were serving at the request of the Companyas a director, officer, employee, agent or fiduciary of another corporation,partnership, joint venture, trust or other enterprise, or by reason of any actionor inaction on the part of the Indemnitees while serving in such capacity.

 

## **Non-Competition,Non-Solicitation and Confidentiality Agreement and Severance Plan**

##  

Except for Frank Semple, each of our general partner’s named executiveofficers is a party to a Non-Competition, Non-Solicitation and ConfidentialityAgreement. As a result of signing the Non-Competition, Non-Solicitation andConfidentiality Agreement, the named executive officers are eligible for theMarkWest Hydrocarbon 1997 Severance Plan. It provides for payment of benefitsin the event that (i) the employee terminates his or her employment for“good reason” (as defined), (ii) the employee’s employment is terminated“without cause” (as defined), (iii) the employee’s employment isterminated by reason of death or disability or (iv) the employeevoluntarily resigns. In the case of (i), (ii) and (iii) above, theemployee 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 aperiod ranging from one month to six months and continued medical benefits fora period ranging from one month to six months. 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.

 

**EmploymentAgreement**

 

**Frank M. Semple**

 

Mr. Sempleentered into an executive employment agreement with MarkWest Hydrocarbon onNovember 1, 2003, pursuant to which Mr. Semple serves as MarkWestHydrocarbon’s President and Chief Executive Officer and pursuant to which theBoard of Directors of MarkWest Hydrocarbon appointed Mr. Semple to serveas the President and Chief Executive Officer of our general partner. Theemployment agreement may be terminated by either Mr. Semple or MarkWest

 

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Hydrocarbon at any time.

 

Under theemployment agreement, Mr. Semple receives an annual base salary and isentitled to receive benefits for which employees and/or executive officers aregenerally eligible. In addition, Mr. Semple was awarded phantom units in ourgeneral partner under the general partner’s long-term incentive plan, and stockoptions under the MarkWest Hydrocarbon incentive stock option plan.Mr. Semple also agreed to purchase from MarkWest Hydrocarbon an interestin each of our general partner and the Partnership, subject to certainrepurchase rights by MarkWest Hydrocarbon following the termination of hisemployment.

 

Under hisemployment agreement, in the event Mr. Semple’s employment is terminatedwithout cause, or if he resigns for good reason, he is entitled to severancepayments equal to his base salary for a period of thirty-six months. Inaddition, Mr. Semple is entitled to COBRA benefits for a period oftwenty-four months. In the event Mr. Semple voluntarily resigns, he is entitledto receive severance payments equal to his base salary and COBRA benefits for aperiod of six months. In the event Mr. Semple is terminated for cause, heshall not be entitled to receive any severance or COBRA benefits.

 

# **Director Compensation**

# ** **

On January 27, 2006, the Board of Directors of the Companyapproved director compensation for 2006. Each non-officer/employee directorwill receive an annual retainer of $20,000 and 1,000 restricted units per year.Chairs of the Audit Committee, Conflicts Committee and Compensation Committeewill receive an additional annual retainer of $4,000, $2,000 and $2,000,respectively. In addition, each non-officer/employee director will receivecompensation of $2,000 for either in-person or telephonic attendance atmeetings of the board of directors. Members of committees will receive $1,000for each meeting.

 

Previously, each independent director received an annual retainer of$18,000 and 1,000 restricted units per year. In addition, eachnon-officer/employee director received compensation of $2,000 for eitherin-person or telephonic attendance at meetings of the board of directors orcommittees of the board of directors. The members of the Audit, Conflicts andCompensation committees received compensation of $1,000 for each committeemeeting. Additionally, members of the Audit and Conflict committees received anannual retainer of $3,000.

 

Each 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 us for actionsassociated with being a director to the extent permitted under Delaware law. Aspreviously disclosed, officers or employees of our general partner who alsoserve as directors will not receive additional compensation.

 

**Compensation Committee Interlocksand Insider Participation**

 

Thereare no Compensation Committee interlocks.

 

# **Board Compensation CommitteeReport On Executive Compensation**

 

The Compensation Committee of the Board of Directors is composed offive non-employee directors, including Mr. Wolf (chairman), Mr. Fox,Mr. Kellstrom, Mr. Wallace and Ms. Mounsey.  The Committeeis responsible for developing and approving our executive compensationpolicies.  In addition, the Compensation Committee determines, on anannual basis, the compensation to be paid to the Chief Executive Officer and toeach of the other executive officers.  The overall objectives of ourexecutive compensation program are to provide compensation that will attractand retain superior talent and reward performance.

 

***CompensationPhilosophy***

 

The executive compensation program is based on thefollowing four objectives: (i) to link the interests of management withthose of unitholders by encouraging ownership in the Partnership; (ii) toattract and retain superior executives by providing them with the opportunityto earn total compensation packages that are competitive with the industry;(iii) to reward individual results by recognizing performance through salary,annual cash incentives and long-term restricted unit based incentives; and(iv) to manage compensation based on the level of skill, knowledge, effortand responsibility needed to perform the job successfully.

 

The components of our compensation program for our executive officersinclude base salary, performance based cash bonuses, and long-term incentivecompensation in the form of stock options, restricted stock awards andrestricted unit grants of MarkWest Energy Partners, L.P.

 

102

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***Base Salary***

 

TheCommittee annually reviews base salaries of executive officers, including theNamed Executive Officers listed in the Summary Compensation Table. Industrycompensation surveys are used to establish base salaries that are within therange of those persons holding comparably responsible positions at othersimilar-sized energy companies/partnerships, both regionally and nationally.The current compensation structure falls generally within the midpoint salary rangeof compensation structures adopted by the other companies in the salary surveysreviewed. Executive’s salary may be increased based on (i) theindividual’s increased contribution over the preceding year; (ii) theindividual’s increased responsibilities over the preceding year; and(iii) any increase in median competitive pay levels.

 

***Annual Cash Bonuses***

 

TheCommittee recommends the payment of bonuses from time-to-time to the employees,including its executive officers, to provide an incentive to these persons tobe productive over the course of each fiscal year. These bonuses are awardedonly if the Partnership achieves or exceeds certain performance goals. Theperformance goals include both financial and non-financial measures. TheCommittee establishes the manner in which the performance goals are calculatedand may exclude the impact of certain specified events from the calculation.The size of the cash bonus to each executive officer is based on the individualexecutive’s performance and the Company’s performance during the precedingyear, as well as that level of combination of cash compensation and restrictedunits that would be required from a competitive point of view to retain theservices of a valued executive officer.

 

***Long-term IncentivePlans*** 

 

The Committee believes that a key component to thecompensation of its executive officers should be through the issuance of stockoptions, restricted stock awards and restricted unit grants of MarkWest EnergyPartners, L.P. Stock options,restricted stock awards and restricted unit grants utilized for this purposehave been designed to provide an incentive to these employees by allowing themto directly participate in any increase in the long-term value of thePartnership. This incentive is intended to reward, motivate and retain theservices of executive employees. 

 

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. AtDecember 31, 2005, there were 409,935 options available for grant underthis plan.

 

The Companyalso issues restricted stock under the Company’s 1996 Stock Incentive Plan and1996 Non-employee Director Stock Option Plan.  Restricted stock is grantedfor no consideration, and vests over a stated period.

 

Our general partner has adopted the MarkWest EnergyPartners, L.P. Long-Term Incentive Plan for employees and directors of ourgeneral partner. The long-term incentive plan consists of two components:restricted units and unit options. The plan currently permits the grant ofawards covering an aggregate of 500,000 common units, 200,000 of which may beawarded in the form of restricted units. At December 31, 2005, the Partnershiphad granted 38,864 restricted units that are subject to vesting periodsestablished from time to time by the Committee.

 

TheCompensation Committee evaluates several factors in awarding restricted units.Rather, it evaluates a series of factors including: (i) the overallperformance of the Partnership for the fiscal year in question; (ii) theperformance of the individual in question; (iii) the anticipatedcontribution by the individual on an overall basis; (iv) the historicallevel of compensation of the individual; (v) the level of compensation ofsimilarly situated executives in the Partnership’s industry; and (vi) thatcombination of cash compensation and restricted units that would be requiredfrom a competitive point of view to retain the services of a valued executiveofficer.

 

***Savings PlanBenefits***

 

We make a matching contribution under our 401(k) Savings and ProfitSharing Plan.  We may also make a discretionary profit sharing paymentannually to executives and all other employees under this plan based upon ourfinancial performance compared to corporate goals for that year.  Inaddition, we provide medical and other miscellaneous benefits to executiveofficers that are generally available to all employees.

 

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***Chief ExecutiveOfficer Compensation***

 

In January 2006, the Compensation Committeeestablished the Chief Executive Officer’s 2006 annual base salary at $350,000. Mr. Semple’sannual base salary is within the range of compensation structures of thosepersons holding comparable positions at similar sized partnerships/companies.In setting this amount, the Committee took into account the scope ofMr. Semple’s responsibility and the Board’s confidence in his skills andability to implement the Partnership’s strategy and business model as evidencedby past performance. Mr. Semple took no part in discussions relating tohis own compensation.

 

Compensation Committee of MarkWest Hydrocarbon, Inc.:

 

Mr. Donald D.Wolf, Chairman

Mr. John M. Fox

Mr. William A.Kellstrom

Mr. William F.Wallace

Ms. Anne E.Mounsey

 

*Deductibility of ExecutiveCompensation. *Section 162(m) of theInternal Revenue Code generally disallows a tax deduction for compensation inexcess of $1.0 million paid to the Company’s Chief Executive Officer andcertain other highly compensated executive officers.  Qualifying“performance-based” compensation will not be subject to the deduction limit ifcertain requirements are met.  We anticipate that incentive-basedcompensation paid in excess of $1.0 million will be deductible underSection 162(m).  The Compensation Committee believes, however, thatthere may be circumstances in which our interests are best served by providingcompensation that is not fully deductible under Section 162(m) andreserves the ability to exercise discretion to authorize such compensation.

 

# **PERFORMANCE GRAPH**

# ** **

 

Source: FactSet Research Systems and Bloomberg.

 

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(a)                                  Peergroup companies include Crosstex Energy, Inc., Kinder Morgan, Inc. andTransmontaigne, Inc. Crosstex Energy, Inc., began trading on 1/13/04. The indexis weighted based on market capitalization. Peer group companies were selectedbased on their business mix and market capitalization.

 

**ITEM 12.****                                              SECURITYOWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT**

 

The following table sets forth certain information as of December 31, 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 January 1,   2006 (2)** | ** ** | **Total Shares   Beneficially   Owned (3)** | ** ** | **Percent of Total   Shares (4)** | ** ** |
|--------------------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|----------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------|------------|-------------------------------------------------------|------------|
| ** **                                                                                                   | ** ** | ** **                       | ** ** | ** **                                                                                         | ** ** | ** **                                                      | ** ** | ** **                                            | ** ** |
| John M. Fox (5)                                                                                         |       | 4,992,346                        |       | —                                                                                             |       | 4,992,346                                                       |       | 46.2                                                  | %          |
| Wellington Management Company, LLP 75 State  Street Boston, Massachusetts 02109 (6)                          |       | 444,750                          |       | —                                                                                             |       | 444,750                                                         |       | 4.1                                                   | %          |
| Kayne Anderson Capital Advisors, L.P. 1800  Avenue of the Stars, Second Floor Los Angeles, CA 90067 (7) |       | 862,046                          |       | —                                                                                             |       | 862,046                                                         |       | 8.0                                                   | %          |
| Richard A. Kayne 1800 Avenue of the Stars,  Second Floor Los Angeles, CA 90067 (7)                           |       | 862,046                          |       | —                                                                                             |       | 862,046                                                         |       | 8.0                                                   | %          |
| Michael L. Beatty                                                                                            |       | —                           |       | —                                                                                             |       | —                                                          |       |                                                  | *          |
| Donald C. Heppermann                                                                                         |       | 18,925                           |       | —                                                                                             |       | 18,925                                                          |       |                                                  | *          |
| William A. Kellstrom                                                                                         |       | 18,110                           |       | —                                                                                             |       | 18,110                                                          |       |                                                  | *          |
| Anne E. Mounsey                                                                                              |       | 10,798                           |       | —                                                                                             |       | 10,798                                                          |       |                                                  | *          |
| Karen L. Rogers                                                                                              |       | 12,270                           |       | —                                                                                             |       | 12,270                                                          |       |                                                  | *          |
| William F. Wallace                                                                                           |       | 2,367                            |       | —                                                                                             |       | 2,367                                                           |       |                                                  | *          |
| Donald D. Wolf                                                                                               |       | 22,680                           |       | —                                                                                             |       | 22,680                                                          |       |                                                  | *          |
| Frank M. Semple                                                                                              |       | 17,316                           |       | 723                                                                                                |       | 18,039                                                          |       |                                                  | *          |
| C. Corwin Bromley                                                                                            |       | 550                              |       | 86                                                                                                 |       | 636                                                             |       |                                                  | *          |
| James G. Ivey                                                                                                |       | 2,750                            |       | 237                                                                                                |       | 2,987                                                           |       |                                                  | *          |
| Nancy K. Masten                                                                                              |       | —                           |       | —                                                                                             |       | —                                                          |       |                                                  | *          |
| John C. Mollenkopf                                                                                           |       | 7,738                            |       | 282                                                                                                |       | 8,020                                                           |       |                                                  | *          |
| Randy S. Nickerson                                                                                           |       | 10,848                           |       | 282                                                                                                |       | 11,130                                                          |       |                                                  | *          |
| Richard A. Ostberg                                                                                           |       | —                           |       | —                                                                                             |       | —                                                          |       |                                                  | *          |
| Andrew L. Schroeder                                                                                          |       | 1,511                            |       | 907                                                                                                |       | 2,418                                                           |       |                                                  | *          |
| David L. Young                                                                                               |       | 687                              |       | 926                                                                                                |       | 1,613                                                           |       |                                                  | *          |
| All directors and executive officers as a  group (17 persons)                                                |       | 5,118,896                        |       | 3,443                                                                                              |       | 5,122,339                                                       |       | 47.4                                                  | %          |

 

----

*      Indicatesless than 1.0%.

 

(1)   Unlessotherwise noted, the address for the stockholder listed is c/o MarkWestHydrocarbon, Inc., 155 Inverness Drive West, Suite 200, Englewood,Colorado 80112-5000.

(2)   Thiscolumn reflects the number of shares that could be purchased by the exercise ofoptions exercisable on December 31, 2005, or within sixty days thereafterunder our stock option plans.

(3)   Forexecutive officers, the numbers include interests in shares held in employeebenefit plans.  Unless otherwise indicated, the directors and NamedExecutive 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)   Allpercentages have been determined at December 31, 2005, in accordance withRule 13d-3 under the Securities Exchange Act of 1934, as amended (the“Exchange Act”). For purposes of this table, a person or group of persons isdeemed to have “beneficial ownership” of any shares of common stock that suchperson or group has the right to acquire within sixty days afterDecember 31, 2005. For purposes of computing the percentage of outstandingshares of common stock held by each person or group of persons named above, anysecurity which such person or group has the right to acquire within sixty daysafter December 31, 2005, is deemed to be outstanding for the purpose ofcomputing the percentage ownership of such person or group. AtDecember 31, 2005, a total of 10,802,488 shares were outstanding.Options to acquire a total of 83,270 shares of common stock were exercisablewithin sixty days.

 

105

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(5)   Includesan aggregate of (i) 4,509,443 shares owned directly by MWHCHolding, Inc., an entity controlled by Mr. Fox, of which Mr. Foxis also considered a beneficial owner (Mr. Fox has an indirect pecuniaryinterest in the MWHC shares); (ii) 73,864 shares held in the aggregate inthe Brian T. Crabtree Trust which Mr. Fox is the Trustee; and(iii) 112,941 shares held by the MaggieGeorge Foundation, for whichcertain family members of Mr. Fox are directors.  Mr. Foxdisclaims beneficial ownership of the shares held in the MaggieGeorgeFoundation within the meaning of Rule 13d-3 under the Exchange Act.

(6)   Informationis based solely on a Schedule 13G/A filed with the Securities and ExchangeCommission by Wellington Management Company, LLP (“Wellington”), onFebruary 14, 2006, with respect to shares held as of December 31,2005. The Schedule 13G indicates that Wellington has shared voting powerwith respect to 654,250 shares and shared dispositive power with respect to858,250.

(7)   Informationis based solely on a Schedule 13G filed with the Securities and ExchangeCommission by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne, onFebruary 9, 2006, with respect to shares held as of December 31,2005. The Schedule 13G indicates that Kayne Anderson Capital Advisors,L.P. and Richard A. Kayne have shared voting power and dispositive power withrespect 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 the general partner of the limitedpartnerships and investment adviser to the other accounts.  Richard A.Kayne is the controlling shareholder of the corporate owner of Kayne AndersonInvestment Management, Inc., the general partner of Kayne Anderson CapitalAdvisors, L.P.  Mr. Kayne is also a limited partner of each of thelimited partnerships and a shareholder of the registered investmentcompany.  Kayne Anderson Capital Advisors, L.P. disclaims beneficialownership of the shares reported, except those shares attributable to it byvirtue of its general partner interests in the limited partnerships. Mr. Kayne disclaims beneficial ownership of the shares reported, exceptthose shares held by him or attributable to him by virtue of his limited partnershipinterests in the limited partnerships, his indirect interest in the interest ofKayne Anderson Capital Advisors, L.P. in the limited partnership, and hisownership of common stock of the registered investment company.

 

***MarkWest GP, L.L.C.***

 

The following tablesets forth the beneficial ownership of the Partnership’s general partner as ofDecember 31, 2005, held by the directors, each named executive officer andby all directors and officers as a group.

 
| **Name of Beneficial Owner**                   | ** ** | **Percentage of   Limited Liability Company   Interests Owned** | ** ** |
|---------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------|------------|
| John M. Fox (1)                                          |       | 90.9                                                                                          |       |
| Frank M. Semple                                               |       | 2.0                                                                                           |       |
| James G. Ivey                                                 |       | 0.5                                                                                           |       |
| Randy S. Nickerson                                            |       | 1.6                                                                                           |       |
| John C. Mollenkopf                                            |       | 1.6                                                                                           |       |
| David L. Young                                                |       | —                                                                                        |       |
| Keith E. Bailey                                               |       | —                                                                                        |       |
| Donald C. Heppermann                                          |       | 1.0                                                                                           |       |
| William A. Kellstrom                                          |       | —                                                                                        |       |
| William P. Nicoletti                                          |       | —                                                                                        |       |
| Charles K. Dempster                                           |       | —                                                                                        |       |
| All directors and executive officers as a  group (11 persons) |       | 97.6                                                                                          |       |

 

----

(1)   Includesa 1.6% ownership interest held directly by Mr. Fox and an 89.7% ownershipinterest held by MarkWest Hydrocarbon. As of December 31, 2005,Mr. Fox beneficially owned approximately 43% of the voting securities ofMarkWest Hydrocarbon. Mr. Fox currently serves as MarkWest Hydrocarbon’sChairman of the Board. Mr. Fox resigned as President of MarkWestHydrocarbon effective November 1, 2003, and as Chief Executive Officereffective January 1, 2004. As a result, Mr. Fox may be deemed tobe the beneficial owner of the ownership interests owned by MarkWestHydrocarbon.

 

106

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***MarkWest EnergyPartners, L.P.***

 

The following tablesets forth the beneficial ownership of units as of December 31, 2005, heldby beneficial owners of 5% or more of the units; by directors of our generalpartner; by each named executive officer listed in the summary compensationtable included in this Form 10-K; and by all directors and officers of ourgeneral partner 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** | ** ** |
|----------------------------------------------------------------|------------|-------------------------------------------------------------------|------------|------------------------------------------------------------------------------------|------------|----------------------------------------------------------------|------------|------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------|------------|
| MarkWest Energy GP, L.L.C.                                     |       | —                                                            |       | —                                                                             |       | —                                                         |       | —                                                                                   |       | —                                                                          |       |
| MarkWest Hydrocarbon, Inc. (2)                            |       | 836,162                                                           |       | —                                                                             |       | 1,633,334                                                      |       | 90.7                                                                                     | %          | 19.2                                                                            | %          |
| John M. Fox (3)                                           |       | 44,731                                                            |       |                                                                               | *          | 1,637,384                                                      |       | 91.0                                                                                     | %          | 23.7                                                                            | %          |
| Kayne Anderson Capital Advisors, L.P (4)                  |       |                                                              |       |                                                                               |       |                                                           |       |                                                                                     |       |                                                                            |       |
| 1800 Avenue of the Stars, Second Floor Los Angeles, CA 90067   |       | 1,670,380                                                         |       | 15.1                                                                               | %          | —                                                         |       | —                                                                                   |       | 13.0                                                                            | %          |
| Richard A. Kayne (4)                                           |       |                                                              |       |                                                                               |       |                                                           |       |                                                                                     |       |                                                                            |       |
| 1800 Avenue of the Stars, Second Floor Los Angeles, CA 90067   |       | 1,670,380                                                         |       | 15.1                                                                               | %          | —                                                         |       | —                                                                                   |       | 13.0                                                                            | %          |
| Tortoise Capital Advisors L.L.C. (5)                           |       |                                                              |       |                                                                               |       |                                                           |       |                                                                                     |       |                                                                            |       |
| 10801 Mastin Boulevard, Suite 222 Overland Park, KS 66210 |       | 966,704                                                           |       | 8.3                                                                                | %          | —                                                         |       | —                                                                                   |       | 7.2                                                                             | %          |
| Tortoise Energy Infrastructure Corporation  (5)                |       |                                                              |       |                                                                               |       |                                                           |       |                                                                                     |       |                                                                            |       |
| 10801 Mastin Boulevard, Suite 222 Overland Park, KS 66210 |       | 805,810                                                           |       | 7.3                                                                                | %          | —                                                         |       | —                                                                                   |       | 6.3                                                                             | %          |
| Tortoise MWEP, L.P.                                            |       | —                                                            |       | —                                                                             |       | 166,666                                                        |       | 9.3                                                                                      | %          | 1.3                                                                             | %          |
| Frank M. Semple                                                |       | 13,734                                                            |       |                                                                               | *          |                                                           |       |                                                                                     | *          |                                                                            |       |
| James G. Ivey                                                  |       | 3,151                                                             |       |                                                                               | *          | —                                                         |       | —                                                                                   |       |                                                                            | *          |
| Randy S. Nickerson                                             |       | 12,495                                                            |       |                                                                               | *          |                                                           |       |                                                                                     | *          |                                                                            |       |
| John C. Mollenkopf                                             |       | 7,936                                                             |       |                                                                               | *          |                                                           |       |                                                                                     | *          |                                                                            |       |
| David L. Young                                                 |       | 136                                                               |       |                                                                               | *          | —                                                         |       | —                                                                                   |       |                                                                            | *          |
| Keith E. Bailey                                                |       | 2,000                                                             |       |                                                                               | *          | —                                                         |       | —                                                                                   |       |                                                                            | *          |
| Donald C. Heppermann                                           |       | 11,667                                                            |       |                                                                               | *          |                                                           |       |                                                                                     | *          |                                                                            | *          |
| William A. Kellstrom                                           |       | 4,042                                                             |       |                                                                               | *          | —                                                         |       | —                                                                                   |       |                                                                            | *          |
| William P. Nicoletti                                           |       | 3,542                                                             |       |                                                                               | *          | —                                                         |       | —                                                                                   |       |                                                                            | *          |
| Charles K. Dempster                                            |       | 1,542                                                             |       |                                                                               | *          | —                                                         |       | —                                                                                   |       |                                                                            | *          |
| All directors and executive officers as a  group (11 persons)  |       | 68,525                                                            |       |                                                                               | *          | 1,637,384                                                      |       | 91.0                                                                                     | %          | 24.2                                                                            | %          |

 

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*      Lessthan 1%

(1)   Beneficialownership for the purposes of the foregoing table is defined by Rule 13d-3 under the Securities Exchange Act of 1934. Under that rule, a person isgenerally considered to be the beneficial owner of a security if he has orshares the power to vote or direct the voting thereof (“Voting Power”) or todispose or direct the disposition thereof (“Investment Power”) or has the rightto acquire either of those powers within sixty (60) days.

(2)   Includessecurities owned directly and indirectly through subsidiaries.

(3)   Includes1,633,334 subordinated units owned by MarkWest Hydrocarbon and itssubsidiaries, and approximately 4,050 subordinated units owned by TortoiseMWEP, L.P. in which Mr. Fox owns an equity interest. As ofDecember 31, 2005, Mr. Fox beneficially owned approximately 43% ofthe voting securities of MarkWest Hydrocarbon. Mr. Fox currently serves asMarkWest Hydrocarbon’s Chairman of the Board. Mr. Fox resigned asPresident of MarkWest Hydrocarbon effective November 1, 2003, and as ChiefExecutive Officer effective January 1, 2004. As a result, Mr. Foxmay be deemed to be the beneficial owner of the subordinated units ownedby MarkWest Hydrocarbon.

(4)   Informationis based solely on a Schedule 13G filed with the Securities and ExchangeCommission by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne, onFebruary 9, 2006, with respect to units held as of December 31, 2005.The Schedule 13G indicates that Kayne Anderson Capital Advisors, L.P. andRichard A. Kayne have shared voting power and dispositive power with respect to1,670,380 units. The reported units are owned by investment accounts managed,with discretion to purchase or sell securities, by Kayne Anderson CapitalAdvisors, L.P., as a registered investment advisor. Kayne Anderson CapitalAdvisors, L.P. is the general partner of the limited partnerships andinvestment adviser to the other accounts. 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 limited partner of each of the limitedpartnerships and a shareholder of the registered investment company. KayneAnderson Capital Advisors, L.P. disclaims beneficial ownership of the unitsreported, except those units attributable to it by virtue of its generalpartner interests in the limited partnerships. Mr. Kayne disclaimsbeneficial ownership of the units reported, except those units held by him orattributable to him by virtue of his limited partnership interests in the limitedpartnerships, his indirect interest in the interest of Kayne Anderson CapitalAdvisors, L.P. in the limited partnership, and his ownership of common units ofthe registered investment company.

(5)   TortoiseCapital Advisors LLC (“TCA”) acts as an investment advisor to Tortoise EnergyInfrastructure Corporation (“TYG”), a closed-end investment company. TCA, byvirtue of an Investment Advisory Agreement with TYG, has all investment andvoting power over securities owned of record by TYG. Despite its delegation of investmentand voting power to TCA, however, TYG may be deemed to be the beneficialowner under Rule 13d-3 of the Securities and Exchange Act of 1940, of thesecurities it owns of record because it has the right to acquire investment andvoting power through termination of the Investment Advisory Agreement. Thus,TCA and TYG have reported that they share voting power and dispositive powerover the securities owned of record by TYG. TCA also acts as an investmentadvisor to certain managed accounts. Under contractual agreements withindividual account holders, TCA, with respect to the securities held in themanaged accounts, shares investment and voting power with certain accountholders, and has no voting power but shares investment power with certain otheraccount holders. TCA may be deemed the beneficial owner of the securitiescovered by this statement under Rule 13d-3 of the Act. None of thesecurities are owned of record by TCA, and TCA disclaims any beneficialinterest in such shares.

 

**Securities Authorizedfor Issuance under Equity Compensation Plans**

 

The following tableprovides information about the shares of our common stock that may be issuedupon the exercise of options, warrants and rights under all of the Company’sexisting equity compensation plans, including the Stock Incentive Plan andNon-Employee Director Plan as of December 31, 2004.  We do not haveequity plans that have not received stockholder approval.

 

**Equity Compensation Plan Information**

 
| **Plan category**                                      | ** ** | **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))** | ** ** |
|-------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|
| ** **                                                  | ** ** | **(a)**                                                                                                                                              | ** ** | **(b)**                                                                                                     | ** ** | **(c)**                                                                                                                                                                                                      | ** ** |
| Equity compensation plans approved by  security holders     |       | 114,007                                                                                                                                              |       | $                                                                                                           | 8.28       |                                                                                                                                                                                                         | 176,078    |   |
| Equity compensation plans not approved by  security holders |       | —                                                                                                                                               |       | —                                                                                                      |       | —                                                                                                                                                                                                       |       |
|                                                        |       |                                                                                                                                                 |       |                                                                                                        |       |                                                                                                                                                                                                         |       |
| Total                                                       |       | 114,007                                                                                                                                              |       | $                                                                                                           | 8.28       |                                                                                                                                                                                                         | 176,078    |   |

 

107

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**ITEM 13. ****                                           CERTAINRELATIONSHIPS AND RELATED TRANSACTIONS**

 

**Investment with Affiliate**

 

Through our wholly owned subsidiary, MarkWest Resources, Inc.(“Resources”), we 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 partnerof MAK-J is a corporation owned and controlled by our former President and ChiefExecutive 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 jointoperating agreements entered into between Resources and MAK-J.  Resourceswas the operator under such agreements.  The joint operating agreementswere governed by a Participation and Operations Agreement, most recentlyamended June 2, 2003.  The joint property acquisitions and joint operatingagreements were subject to the approval of the independent members of our Boardof Directors.  As the operator, Resources was obligated to provide certainaccounting and well operations services to the parties.  The Participationand Operations Agreement provided for a monthly fee ($2,000 per month) payableto Resources to offset the costs of accounting and well operations on a monthlybasis.  As a part of the sale of our San Juan Basin oil and gas propertiesto a third party on June 30, 2003, the Participation and OperationsAgreement was assigned to the purchasing third party.

 

From time to time, MarkWest Hydrocarbon entered into hedges withcounterparties on behalf of MAK-J.  MarkWest Hydrocarbon billed orremitted to MAK-J, as circumstances dictated, its portion of transaction costsand settlements on a monthly basis.  As of July 2003, all such hedgeshad been settled.

 

Through our wholly owned subsidiary, Matrex, LLC, we hold interests incertain exploration and production assets in which MAK-J also ownsinterests.  Both parties are participants to joint operating agreementswith third parties operators.

 

We have receivables due from MAK-J, representing its share of operatingand capital costs generated in the normal course of business, of less than $0.1million as of December 31, 2004 and 2003, respectively.   As of December 31, 2005 there wereoutstanding related party receivables. We also have payable 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, 2005, 2004 and 2003,respectively. 

 

Mr. Fox has agreed that as long as he is an officer or director ofMarkWest Hydrocarbon and for two years thereafter, he will not, directly orindirectly, participate in any future oil and gas exploration or productionactivities with us except and to the extent that our independent andunaffiliated directors deem it advisable and in our best interest to includeone or more additional participants, which participants may include entitiescontrolled by Mr. Fox.

 

**Relationship of Directors with MarkWestHydrocarbon**

 

Donald D. Wolf, a member of the Board of Directors, was the Chairmanand Chief Executive Officer of Westport Resources Corporation and William F.Wallace, also a member of the Board of Directors, was a director of WestportResources Corporation until Westport’s merger with Kerr McKee Corporation in2004.  Mr. Wallace is currently a director of the Kerr McKeeCorporation.  Westport Resources Corporation was a party to certain 1997contracts with indirect subsidiaries of MarkWest Hydrocarbon fortransportation, treating and processing services in Western Michigan.  Noservices were performed in the last year pursuant to these contracts.  Theterms of these contracts were negotiated on an arm’s length basis prior toMr. Wolf’s 1999 election and Mr. Wallace’s 2004 election to the Boardof Directors.

 

**Related Transactions**

 

In February 2004 MarkWest Hydrocarbon entered into a Separationand Release Agreement with Arthur J. Denney, Senior Vice President, pursuant towhich the Company agreed to pay Mr. Denney his base salary throughFebruary 28, 2006, or approximately $0.4 million.

 

In February 2004 MarkWest Hydrocarbon entered into a Separationand Release Agreement with Donald C. Heppermann, Chief Financial Officer,pursuant to which MarkWest Hydrocarbon agreed to pay Mr. Heppermann hisbase salary through August 31, 2004.

 

108

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In March 2004 MarkWest Hydrocarbon entered into a ConsultingAgreement with Donald C. Heppermann to advise MarkWest Hydrocarbon’s Board ofDirectors, chief executive officer, treasurer and controller on mattersrelating to banking, financing, mergers and acquisitions and general corporatestrategy.  Pursuant to the agreement, MarkWest Hydrocarbon agreed to payMr. Heppermann $9,000 a month for his consulting services for up to aperiod of two years (or $0.2 million), unless given notice by MarkWestHydrocarbon.

 

In March 2004 MarkWest Hydrocarbon entered into a Separation andRelease Agreement with John M. Fox, Chief Executive Officer, pursuant to whichMarkWest Hydrocarbon agreed to pay Mr. Fox his base salary throughDecember 31, 2004 or approximately $0.4 million.

 

In April 2004 the Company entered into an agreement with a thirdparty to buy Mr. Semple’s house as a part of his relocation to Denver,Colorado.  Under the agreement, MarkWest Hydrocarbon agreed to pay thevalue of Mr. Semple’s equity in the house and associated operating costsof $0.3 million to the third party until the house was subsequently sold to abuyer.  Upon the sale, the third party agreed to refund the equity paid byMarkWest Hydrocarbon to the extent that the proceeds covered the establishedvalue minus certain costs incurred to sell the home.  In 2005 the housewas sold and the Company paid total costs of approximately $0.1 million.

 

**Participation Plan**

 

From time to time, MarkWest Hydrocarbon sells to certain of itsexecutive officers and directors (i) a certain amount of the subordinatedunits the Company obtained during the formation of MarkWest Energy inMay 2002 and (ii) a portion of its ownership interest in the generalpartner, which was also obtained by the Company during the formation of thePartnership.  These transactions are accounted for as compensatoryarrangements, 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 OpinionNo. 25,*which requires the Company to record compensationexpense based on the market value of the subordinated Partnership units and theformula value of the general partner interests held by the employees anddirectors, at the end of each reporting period. The sales are governed by apurchase and sales agreement that outlines the terms and conditions.Immediately after MarkWest Energy’s initial public offering on May 24,2002, MarkWest Hydrocarbon sold an 8.6% interest in the general partner of thePartnership and 24,864 of its Partnership subordinated units, to certainofficers of MarkWest Hydrocarbon for $0.2 million and $0.4 million,respectively.  The officers and executives paid approximately 30% of thepurchase price in cash and financed the remainder with loans from MarkWestHydrocarbon.  The loans are evidenced by non-recourse promissory notesrequiring the principal balance to be repaid no later than June 30, 2009and bearing interest at the rate of 7% per annum on the unpaidbalance.   MarkWest Hydrocarbon has sold additional interests in thegeneral partner to employees and directors of 3.9% for $0.2 million andPartnership subordinated units of 12,500 for $0.3 million.  In 2004, theCompany sold interests aggregating 0.7% in the general partner of thePartnership to employees and directors for $0.2 million and 1,500 Partnershipsubordinated units for $0.1 million.  Outstanding notes receivable fromofficers pertaining to the loans made in May 2002 were approximately $0.2million as of December 31, 2004 and 2003.  In the second quarter of2005, one former director/executive re-paid his outstanding loan for less than$0.1 million. Outstanding notes receivable of approximately $0.1 million werepayable by Mr. Mollenkopf and Mr. Nickerson at both December 31,2004 and 2003.  In accordance with the Sarbanes-Oxley Act of 2002, theCompany no longer grants loans to employees.

 

# **Future Transactions**

# ** **

The terms of any future transactions between us and our directors,officers, principal stockholders or other affiliates, or the decision toparticipate or not participate in transactions offered by our directors,officers, principal stockholders or other affiliates will be approved by amajority of our independent and unaffiliated directors. Our Board of Directorswill use such procedures in evaluating their terms as are appropriateconsidering the fiduciary duties of the Board of Directors under Delaware law.In any such review the Board may use outside experts or consultants includingindependent legal counsel, secure appraisals or other market comparisons, referto generally available statistics or prices or take such other actions as areappropriate under the circumstances. Although such procedures are intended toensure that transactions with affiliates will be at least as favorable to theCompany as an arm’s length transaction with an unaffiliated third party, thoughno assurance can be given that such procedures will produce such result.

 

# **ITEM 14.**                                              PRINCIPAL ACCOUNTANTFEES AND EXPENSES 

# ** **

For the year ended December 31, 2005 and 2004, Deloitte & ToucheLLP’s and KPMG LLP’s accounting fees and services (in thousands) were asfollows:

 

109

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| ** **                         | ** ** | **2005** | ** ** | **2004** | ** ** |
|------------------------------------|------------|----------|------------|----------|------------|
| Audit fees                         |       | $        | 3,282      |     | $          | 2,945 |   |
| Audit-related fees (1)             |       | 125      |       | 110      |       |
| Tax fees (2)                       |       | —   |       | —   |       |
| All other fees (3)                 |       | 5        |       | —   |       |
|                               |       |     |       |     |       |
| Total accounting fees and services |       | $        | 3,412      |     | $          | 3,055 |   |

 

----

(1)                                 Audit-relatedfees include fees for reviews of registration statements and issuances ofconsents, reviews of private placement offering documents, benefit plan audits,issuance of letter to underwriters, due diligence pertaining to potentialbusiness acquisitions and a review of risk management policies and procedures.

(2)                                 Taxfees include fees for tax return preparation and technical tax advice.

(3)                                 Allother fees consist of a subscription to an on-line accounting research tool.

 

*Pre-Approval of Audit and Permitted Non-AuditServices.*The Audit Committee is responsible forappointing, setting compensation and overseeing the work of the independentpublic accountants. The Audit Committee established a policy that requires thePartnership to have the Audit Committee pre-approve all audit and permittednon-audit services from the independent public accountants. The Company’smanagement submits request to the Audit Committee for pre-approval of any suchallowable services. The Audit Committee considers whether the provision ofnon-audit services by the independent public accountants is compatible withmaintaining the accountants’ independence. The Audit Committee considers eachengagement of the independent public accountants on a case-by-case basis. TheAudit Committee pre-approved the performance of the services described above.

 

110

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**PARTIV**

** **

# **ITEM 15.**                                              EXHIBITS AND FINANCIALSTATEMENT SCHEDULES 

 

(a)         The following documents are filed as part of this report:

 

(1) Financial Statements:

 

You should read the Index to ConsolidatedFinancial Statements included in Item 8 of this Form 10-K for a list of allfinancial statements filed as a part of this report, which is incorporatedherein by reference.

 

(2) FinancialStatement Schedules: All omitted schedules have been omitted because theyare not required or 

 

because the required information is contained in the financial statementsor notes thereto.

 

(3) Exhibits: See (b) below.

 

(b) Exhibitsrequired by Item 601 of Regulation S-K.

 
| **Exhibit  Number** | ** ** | **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 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.                                                                                                                                 |

 

111

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| 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).                                                                                                                                                                                                                                                                                                                                                                                    |
|          |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.1(2)  |   | 1996 Incentive Compensation Plan.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |
|          |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.2(1)  |   | 1996 Stock Incentive Plan.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
|          |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.3(1)  |   | 1996 Non-employee Director Stock Option Plan.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
|          |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.4(1)       |   | Form of Non-Compete Agreement between  John M. Fox and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
|          |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.5(3)       |   | MarkWest Hydrocarbon, Inc., 1997  Severance and Non-Compete Plan.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
|          |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.6(5)       |   | Amendment to Gas Processing Agreement  (Maytown) dated as of March 26, 2002, between Equitable Production  Company and MarkWest Hydrocarbon, Inc.                                                                                                                                                                                                                                                                                                                                                                                                   |
|          |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.7(11)      |   | Credit Agreement dated as of May 20,  2002, among MarkWest Energy Operating Company, L.L.C. (as borrower), MarkWest  Energy Partners, L.P. (as a Guarantor), and various lenders.                                                                                                                                                                                                                                                                                                                                                                        |
|          |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.8(5)       |   | Contribution, Conveyance and Assumption  Agreement dated as of May 24, 2002, among MarkWest Energy Partners,  L.P.; MarkWest Energy Operating Company, L.L.C; MarkWest Energy GP, L.L.C.;  MarkWest Michigan, Inc.; MarkWest Energy Appalachia, L.L.C.; West Shore  Processing Company, L.L.C.; Basin Pipeline, L.L.C.; and MarkWest  Hydrocarbon, Inc.                                                                                                                                                                                        |
|          |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.9(6)       |   | Fifth Amended and Restated Credit Agreement  among MarkWest Hydrocarbon, Inc. and various lenders, dated as of  May 24, 2002.                                                                                                                                                                                                                                                                                                                                                                                                                       |
|          |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.10(11)     |   | Amended and Restated Canadian Credit Agreement  among MarkWest Resources Canada Corp. and various lenders, dated as of May 24,  2002.                                                                                                                                                                                                                                                                                                                                                                                                                    |
|          |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.11(5)      |   | Omnibus Agreement dated as of May 24,  2002, among MarkWest Hydrocarbon, Inc.; MarkWest                                                                                                                                                                                                                                                                                                                                                                                                                                                             |

 

112

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|            |   | 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, 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) ^     |   | 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) ^ |   | MarkWest Energy Partners, L.P. Long-Term  Incentive Plan.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
|            |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.24(5) ^ |   | 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                   |

 

113

----

 
| 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
|      |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.29(21) |   | Fourth Amended and Restated Credit Agreement,  dated as of November 1, 2005.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
|      |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.30(22) |   | Fifth Amended and Restated Credit Agreement  dated as of December 29, 2005, 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,  Forties Capital Corp., as Documentation Agent, U.S. Bank National  Association, as Documentation Agent, Society General, 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 $615,000,000 Senior Credit Facility. |
|      |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 11.1(13)  |   | Statement regarding computation of earnings  per share.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
|      |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 16.1(19)  |   | Letter from KPMG LLP regarding Change in Certifying  Accountants.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
|      |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 16.2(20)  |   | Letter from PricewaterhouseCoopers LLP  regarding Change in Certifying Accountants.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
|      |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 21.1 *    |   | List of Subsidiaries of MarkWest  Hydrocarbon, Inc.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
|      |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 23.1 *    |   | Consent of Deloitte & Touche LLP.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|      |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 23.2 *    |   | Consent of KPMG LLP.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
|      |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 23.3 *    |   | Consent of PricewaterhouseCoopers LLP.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
|      |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 31.1 *    |   | Chief Executive Officer Certification Pursuant  to Rule 13a-14(a) of the Securities Exchange Act.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
|      |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 31.2 *    |   | Chief Financial Officer Certification Pursuant  to Rule 13a-14(a) of the Securities Exchange Act.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
|      |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 32.1 *    |   | Certification of the Chief Executive Officer  Pursuant to 18 U.S. C. Section 1350, as adopted Pursuant to  Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
|      |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 32.2 *    |   | Certification of the Chief 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.                                                              |

 

 

114

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| (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.                                                                                                                               |
| (19) | Incorporated by reference to MarkWest  Hydrocarbon, Inc.’s Current Report on Form 8-K, filed with the  Commission on September 23, 2005.                                                                                                                                 |
| (20) | Incorporated by reference to MarkWest Hydrocarbon, Inc.’s  Current Report on Form 8-K, filed with the Commission on April 6, 2004.                                                                                                                                       |
| (21) | Incorporated by reference to MarkWest Energy  Partners, L.P.’s Current Report on Form 8-K filed with the Commission on  November 7, 2005.                                                                                                                                     |
| (22) | Incorporated by reference to MarkWest Energy  Partners, L.P.’s Current Report on Form 8-K filed with the Commission on  January 5, 2006.                                                                                                                                      |
| +    | 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.                                                                                                                                                                                                                                                                         |
| ^    | Identifies each management contract or  compensatory plan or arrangement.                                                                                                                                                                                                               |

 

(b)                                 Thefollowing exhibits are filed as part of this report:  See Item 15(a)(2) above.

 

(c)          The following financialstatement schedules are filed as part of this report:  None required.

 

115

----

 

**SIGNATURES**

 

Pursuant to the requirements of section 13 or 15(d) of the SecuritiesExchange Act of 1934, the Registrant has duly caused this Report to be signedon its behalf by the undersigned, thereunto duly authorized.

 

 
|                 |   | MarkWest Hydrocarbon, Inc.                        |
|----------------------|--------|---------------------------------------------------|
|                 |   | (Registrant)                                      |
|                 |   |                                              |
| Date: March 20, 2006 | By:    |   /S/Frank M. Semple                    |
|                 |   |   Frank M. Semple                       |
|                 |   |   President and Chief Executive Officer |
|                 |   |   (Principal Executive Officer)         |

 

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

 
| Date: March 20, 2006 | By:    |   /S/Frank M. Semple                    |
|----------------------|--------|---------------------------------------------------|
|                 |   |   Frank M. Semple                       |
|                 |   |   President and Chief Executive Officer |
|                 |   |   (Principal Executive Officer)         |
|                 |   |                                              |
| Date: March 20, 2006 | By:    |   /S/James G. Ivey                      |
|                 |   |   James G. Ivey                         |
|                 |   |   Chief Financial Officer               |
|                 |   |   (Principal Financial Officer)         |
|                 |   |                                              |
| Date: March 20, 2006 | By:    |   /S/NANCY K. MASTEN                    |
|                 |   |   Nancy K. Masten                       |
|                 |   |   Chief Accounting Officer              |
|                 |   |   (Principal Accounting Officer)        |
|                 |   |                                              |
| Date: March 20, 2006 | By:    |   /S/John m. Fox                        |
|                 |   |   John M. Fox                           |
|                 |   |   Chairman of the Board and Director    |
|                 |   |                                              |
|                 |   |                                              |
| Date: March 20, 2006 | By:    |   /S/MICHAEL L. BEATTY                  |
|                 |   |   Michael L. Beatty                     |
|                 |   |   Director                              |
|                 |   |                                              |
| Date: March 20, 2006 | By:    |   /S/Donald C. Heppermann               |
|                 |   |   Donald C. Heppermann                  |
|                 |   |   Director                              |
|                 |   |                                              |
| Date: March 20, 2006 | By:    |   /S/WILLIAM A. KELLSTROM               |
|                 |   |   William A. Kellstrom                  |
|                 |   |   Director                              |
|                 |   |                                              |
| Date: March 20, 2006 | By:    |   /S/ANNE E. MOUNSEY                    |
|                 |   |   Anne E. Mounsey                       |
|                 |   |   Director                              |
|                 |   |                                              |
| Date: March 20, 2006 | By:    |   /S/karen l. rogers                    |
|                 |   |   Karen L. Rogers                       |
|                 |   |   Director                              |

 
| Date: March 20, 2006 | By:    |   /S/William f. WALLACE |
|----------------------|--------|-----------------------------------|
|                 |   |   William f. Wallace    |
|                 |   |   Director              |

 
| Date: March 20, 2006 | By:    |   /S/DONALD D. WOLF |
|----------------------|--------|-------------------------------|
|                 |   |   Donald D. Wolf    |
|                 |   |   Director          |

 

 

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