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, 2004.

 

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

 

for the transition period from                      to                         .

 

Commission File Number 1-14841

 

MARKWEST HYDROCARBON, INC.

(Exact name of registrant as specified in its charter)

 

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

 

155 Inverness Drive West, Suite 200, Englewood, CO  80112-5000

(Address of principal executive offices)

 

Registrant’s telephone number, including area code:  303-290-8700

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

DOCUMENTS INCORPORATED BY REFERENCE

 

None.

 

 

MarkWest Hydrocarbon, Inc.

Form 10-K

Table of Contents

 

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

 

2

 

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

 

Glossary of Terms

 

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

 

Bbls	barrels
Bbl/d	barrels per day
Bcf	one billion cubic feet of natural gas
Btu	one British thermal unit, an energy measurement
Gal/d	gallons per day
Gross Margin	revenues less purchased product costs
MBbl	one thousand barrels
Mcf	one thousand cubic feet of natural gas
Mcfe	one thousand cubic feet of natural gas equivalent (1)
Mcf/d	one thousand cubic feet of natural gas per day
Mcfe/d	one thousand cubic feet of natural gas equivalent per day
MMBtu	one million British thermal units, an energy measurement
MMcf	one million cubic feet of natural gas
MMcfe	one million cubic feet of natural gas equivalent
MMcf/d	one million cubic feet of natural gas per day
NGLs	natural gas liquids, such as propane, butanes and natural gasoline
NA	not applicable
Tcf	one trillion cubic feet of natural gas

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

 

Explanatory Note

 

We have determined that, in certain cases, we did not comply with generally accepted accounting principles in the preparation of our 2002 and 2003 consolidated financial statements and, accordingly, we have restated our 2002 and 2003 annual financial statements in this 2004 Annual Report on Form 10-K.  The Company has also filed Form 10-Q/A’s for the first three quarters of 2004 to restate its quarterly financial statements for 2003 and 2004.

 

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

 

As discussed more fully in Note 23, Restatement of Consolidated Financial Statements, to the consolidated financial statements in Item 8 of this Form 10-K, the restatements have been made to account for the sale by the Company of its general partnership interests in the Partnership’s general partner to certain of its employees and directors, and the sale by the Company of its subordinated units of the Partnership to certain employees and directors of the Company as compensatory arrangements pursuant to the guidance in Accounting Principles Board Opinion (“APB”) No. 25, Accounting for Stock Issued to Employee and Emerging Issues Task Force (“EITF”) No. 95-16, Accounting for Stock Compensation Arrangements with Employer Loan Features under APB Opinion No. 25.  This guidance requires the Company to record compensation expense for the difference between the market value of the subordinated Partnership units and the formula value of the general partner interests held by these employees and directors at the end of each reporting period.  These transactions were previously reflected as sales of assets.

 

3

 

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

 

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

 

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

 

Forward-Looking Information

 

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

 

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

 

•      Our expectations regarding MarkWest Energy Partners, L.P.

•      Our ability to grow MarkWest Energy Partners, L.P.

•      Our ability to amend certain producer contracts.

•      Our expectations regarding natural gas, NGLs product and prices.

•      Our efforts to increase fee-based contract volumes.

•      Our ability to manage our commodity price risk.

•      Our ability to maximize the value of our NGL output.

•      The adequacy of our general public liability, property, and business interruption insurance.

•      Our ability to comply with environmental and governmental regulations.

 

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

 

•      The availability of raw natural gas supply for our gathering and processing services.

•      The availability of NGLs for our transportation, fractionation and storage services.

•      Prices of NGL products and natural gas, including the effectiveness of any hedging activities.

•      Our ability to negotiate favorable marketing agreements.

•      The risks that third party natural gas exploration and production activities will not occur or be successful.

•      Our dependence on certain significant customers, producers, gatherers, treaters and transporters of natural gas.

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

 

4

 

•      Our substantial debt and other financial obligations could adversely impact our financial condition.

•      Our ability to successfully integrate our recent or future acquisitions.

•      Our ability to identify and complete grass-roots projects or acquisitions complementary to our business.

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

•      Winter weather conditions.

 

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements.  Other unknown or unpredictable factors could also have material adverse effects on future results.  The Company does not update publicly any forward looking statement whether as a result of new information or future events.  Investors are cautioned not to put undue reliance on forward-looking statements.  You should read Risk Factors included in Item 7 of this Form 10-K for further information.

 

5

 

PART I

 

ITEMS 1. AND 2.  BUSINESS AND PROPERTIES

 

General

 

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

 

Our assets consist almost exclusively of partnership interests in MarkWest Energy.  As of December 31, 2004, we owned a 25% interest in the Partnership consisting of the following:

 

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

•      a 90% ownership interest in MarkWest Energy GP, 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 the Partnership.

 

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

 

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

 

Overview

 

Since the formation of the Partnership, we have transformed MarkWest Hydrocarbon into a company focused on increasing shareholder value through our ownership in MarkWest Energy.  Specifically, we discontinued our exploration and production business in 2003 while facilitating the growth of MarkWest Energy through its acquisition of third-party midstream assets.  From 2002 through December 31, 2004, the Partnership completed six acquisitions for an aggregate purchase price of $354.4 million.  These acquisitions included:

 

•      In July 2004, the Partnership acquired natural gas gathering and processing assets located in east Texas for $240.7 million.  The assets, which we refer to as our East Texas System, consisted of approximately 210 miles of natural gas gathering system pipelines, natural gas gathering system pipelines currently under construction, 15 centralized compressor stations representing 74,000 horsepower of compression and a proposed natural gas processing facility, now under construction.

•      In April 2004, the Partnership acquired a lateral pipeline in Hobbs, New Mexico for approximately $2.3 million.

•      In December 2003, the Partnership acquired an intrastate crude oil pipeline in Michigan for approximately $21.3 million.

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

•      In September 2003, the Partnership acquired a 70-mile intrastate gas transmission pipeline near Lubbock, Texas for approximately $12.2 million.

•      In March 2003, the Partnership completed its acquisition of $39.9 million of midstream assets from Pinnacle in the Southwest.  The acquired assets, primarily located in Texas, were comprised of (i) three lateral natural gas pipelines transporting natural gas under firm contracts to power plants and (ii) twenty gathering systems. One of the smaller gathering systems acquired was subsequently disposed of in December 2003 for an insignificant amount and two were sold in 2004 for proceeds of approximately $0.1 million.

 

6

 

Strategy

 

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

 

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

 

Financial Information About Segments

 

Our business activities are segregated into two segments:

 

•      Managing MarkWest Energy

•      Marketing of natural gas and NGLs

 

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

 

Narrative Description of Business

 

Our Relationship with MarkWest Energy

 

We spun off the majority of our then-existing natural gas gathering and processing and NGL transportation, fractionation and storage assets into MarkWest Energy in May 2002, just before the Partnership completed its initial public offering. At the time of its formation and initial public offering, we entered into four contracts with MarkWest Energy whereby MarkWest Energy provides midstream services for us in exchange for a fee. In accordance with generally accepted accounting principles, MarkWest Energy’s financial results are included in our consolidated financial statements.  All intercompany accounts and transactions are eliminated during consolidation. Also at the time of MarkWest Energy’s initial public offering, we entered into an omnibus agreement with MarkWest Energy and related parties that govern potential competition and indemnification obligations among the involved parties.

 

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

 

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

 

Overview of the Industry

 

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

 

7

 

 

The industry is characterized by regional competition based on the proximity of gathering systems and processing plants to producing natural gas wells.

 

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

 

Most natural gas produced at the wellhead is not suitable for long-haul pipeline transportation or commercial use and must be gathered, compressed and transported via pipeline to a central processing facility and then processed to remove the heavier hydrocarbon components and other contaminants that would interfere with pipeline transportation or the end use of the gas. Our business includes these necessary services for either a fee or a percentage of the NGLs removed or gas units processed.

 

The natural gas gathering process begins with the drilling of wells into gas bearing rock formations.  Once a well has been completed, the well is connected to a gathering system.  Gathering systems typically consist of a network of small diameter pipelines and, if necessary, compression systems that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission.

 

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

 

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

 

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

 

Described below are the five basic NGL products and their typical uses:

 

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

 

8

 

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

 

•         Propane.  Propane is used for heating fuel, engine fuel, industrial fuel and for agricultural burning and drying and as a petrochemical feedstock for production of ethylene and propylene.  Propane is principally used as a fuel in our operating area.

 

•         Normal butane.  Normal butane is principally used for gasoline 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 key ingredient of synthetic rubber.  In Appalachia we sell the majority of our normal butane to a specialty chemical manufacturer.

 

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

 

•         Natural gasoline. Natural gasoline is principally used as a motor gasoline blend stock or petrochemical feedstock.

 

9

 

MarkWest Energy’s Assets

 

The Partnership has five primary geographic areas of operation, three in the Southwest, one in Appalachia and one in Michigan:

 

•              Southwest

 

•      East Texas.  On July 30, 2004, the Partnership acquired certain natural gas gathering and processing assets, the East Texas System, located in east Texas from American Central Eastern Texas Gas Company, Limited Partnership.  The East Texas System currently consists of natural gas gathering system pipelines, natural gas gathering system pipelines currently under construction, centralized compressor stations and a natural gas processing facility, also currently under construction.  The East Texas System is located in Panola County and services the Carthage Field, one of Texas’ largest onshore natural gas fields.  Producing formations in Panola County currently consist of the Cotton Valley, Pettit and Travis Peak formations which form one of the largest natural gas producing regions in the United States.  The Carthage Field has approximately 18 Tcf of estimated recoverable reserves and cumulative historical production in excess of 12 Tcf.

 

•      Oklahoma. The Partnership owns the Foss Lake gathering system and the Arapaho gas processing plant located in the western Oklahoma counties of Roger Mills and Custer, respectively.  The gathering system is comprised of a pipeline system that is connected to natural gas wells and associated compression facilities.  All of the gathered gas is ultimately compressed and delivered to the processing plant.  After processing, all residue gas is delivered to a third party pipeline and all natural gas liquids are sold to one customer.

 

•      Other Southwest. The Partnership owns 17 natural gas gathering systems located in Texas, Louisiana, Mississippi and New Mexico.  These systems generally service long-lived natural gas basins that continue to experience drilling activity.  The Partnership gathers a significant portion of the gas produced from fields adjacent to its gathering systems.  In many areas, MarkWest Energy is the primary gatherer, and in some of the areas served by its smaller systems the Partnership is the sole gatherer.  In addition, MarkWest Energy owns four lateral pipelines in Texas and New Mexico.

 

•      Appalachia.  The Partnership is a processor of natural gas in the Appalachian basin with fully integrated processing, fractionation, storage and marketing operations.  The Appalachian basin is a large natural gas producing region characterized by long-lived reserves and modest decline rates.  The Partnership’s Appalachian assets include five natural gas processing plants, a NGL pipeline, a NGL fractionation plant and two caverns storing propane.

 

•      Michigan.  The Partnership owns the largest intrastate crude oil pipeline in Michigan.  The Partnership refers to this system as the Michigan Crude Pipeline.  MarkWest Energy also owns a natural gas gathering system and a natural gas processing plant in Michigan.

 

10

 

The Partnership’s Southwest Assets

 

Gathering and Processing Facilities

 

East Texas

 

The table below describes the Partnership’s East Texas gathering and processing assets:

 

Year Ended December 31, 2004

Facility

Location

Year of Initial Construction

Design Throughput Capacity (Mcf/d)

Natural Gas Throughput (Mcf/d)(1)

Utilization of Design Capacity

NGL Throughput (gal/day)

East Texas gathering system(2)(3)

Panola County, TX

1990

350,000

259,300

74

%

NA

East Texas processing plant(4)

Panola, County, TX

2005, anticipated

200,000

NA

NA

NA

 

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

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

(3)   The design throughput capacity for the East Texas gathering system includes the throughput capacity upon completion of the 18 miles of natural gas pipeline under construction.

(4)   Construction is anticipated to be completed in 2005.

 

East Texas gathering system.  The Partnership acquired the East Texas System in July 2004.  The system is a low-pressure regional gathering system consisting of approximately 210 miles of natural gas gathering pipeline connected to approximately 1,730 upstream well connections, with approximately 20 additional miles of pipeline currently under construction, and includes 15 centralized compressor stations with an aggregate of approximately 74,000 horsepower of compression, with an additional 16,000 horsepower of new compression and processing plant recompression currently being installed.  The system gathers natural gas from the Carthage Field in east Texas from approximately 20 producers.

 

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

 

The Partnership generates revenues in East Texas through fixed fee gathering and compression, settlement margin and condensate sales contracts, which are described in more detail under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Our Contracts.

 

Oklahoma

 

The table below describes the Partnership’s Oklahoma gathering and processing assets:

 

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

 

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

(2)   The Partnership acquired the Foss Lake gathering system and the Arapaho processing plant on December 1, 2003.

 

11

 

Foss Lake Gathering System.  The Partnership acquired the Foss Lake Gathering System as part of the western Oklahoma acquisition in December 2003. The system is a low-pressure gathering system consisting of approximately 240 miles of four to 20-inch pipeline connected to approximately 310 wells and includes approximately 16,000 horsepower of owned-compression and approximately 3,000 horsepower of leased-compression. The system gathers natural gas from the Anadarko Basin in western Oklahoma from approximately 75 producers. The Partnership generates revenues by charging fixed-fees per Mcf of natural gas gathered and through settlement margin arrangements. All of the natural gas gathered into the system is dehydrated at our Butler compression station for delivery to the Partnership’s Arapaho processing plant.

 

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

 

Other Southwest

 

The table below describes the Partnership’s Other Southwest gathering and processing assets:

 

Year Ended December 31, 2004

Facility

Location

Year of Initial Construction

Design Throughput Capacity (Mcf/d)

Natural Gas Throughput (Mcf/d)(1)

Utilization of Design Capacity

NGL Throughput (gal/day)

Appleby Gathering System(2)

Nacogdoches County, TX

1990

40,000

27,100

68

%

NA

Other Gathering Systems(2)

Various in TX, LA, MS, NM

Various

53,000

17,000

32

%

NA

 

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

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

 

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

 

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

 

12

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

13

 

The Partnership’s Appalachian Assets

 

Appalachian Gathering and Processing Facilities

 

The table below describes the Partnership’s processing assets in the Appalachian region:

 

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

 

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

(2)   In 2004, the Partnership began construction of a new 24 MMcf/d processing plant. This new plant replaces the Partnership’s existing Cobb plant.  It was completed in the first quarter of 2005.

(3)   The Kermit processing plant is operated by a third party producer and MarkWest Energy does not receive inlet volume information.

 

Kenova Processing Plant.  The Partnership’s Kenova cryogenic facility was expanded by 40 MMcf/d in 2001 to accommodate expected new production from a third party producer. The cryogenic process utilizes a turbo-expander and heat exchangers to cool the gas, which condenses the NGLs. The NGLs are then separated from condensed gaseous components by distillation. This facility receives all of its intake of natural gas from Columbia Gas’ transmission pipeline and processes gas from adjoining counties. NGLs extracted at this facility are transported to our Siloam fractionator via pipeline.

 

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

 

Maytown Processing Plant.  Pursuant to contract, a third party producer provides certain operating services at the Partnership’s Maytown facility, a straight refrigeration plant, on its behalf.  While providing operating services, this third party is responsible for the day-to-day operation of the Maytown plant. Under the Partnership’s Gas Processing Agreement with this third party, the Partnership has the right to assume the role of operator upon providing them with a 30-day written notice. Like the Boldman plant, the Maytown plant also processes gas using a propane refrigeration system to cool the gas and condense the NGLs. The NGLs are then separated from condensed gaseous components by distillation. This facility receives all of its intake of natural gas from the third party’s gathering system in Kentucky. NGLs extracted at this facility are transported to Siloam via pipeline.  The plant also contains a truck unloading facility that allows for the delivery of NGLs into the Partnership’s pipeline system for transportation to its Siloam fractionator.

 

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

 

14

 

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

 

Appalachian NGL Pipelines

 

The Partnership’s Appalachia liquids pipeline includes the following segments:

 

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

 

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

(2)   NGLs transported through the Ranger to Kenova pipeline are included in the Kenova to Siloam volumes.

 

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

 

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

 

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

 

15

 

Appalachian Fractionation Facility

 

The Partnership’s Siloam fractionation plant receives substantially all of its NGLs via pipeline or tanker truck from its five Appalachia processing plants, with the balance received from tanker truck and rail car deliveries from other third-party NGL sources. The NGLs are then separated into NGL products, including propane, isobutane, normal butane and natural gasoline. The typical composition of the NGL throughput in the Partnership’s Appalachian operations has been approximately 64% propane, 18% normal butane, 6% isobutene and 12% natural gasoline. The Partnership does not currently produce or sell any ethane.  The Partnership generates revenues by charging fees for fractionating NGLs that it receives from the Partnership’s processing plants and third parties.

 

The following table provides additional detail regarding the Partnership’s Siloam fractionation plant:

 

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

 

Appalachian Storage Facilities

 

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

 

The Partnership’s Michigan Assets

 

Michigan Gathering and Processing Facilities

 

The table below describes the Partnership’s Michigan gathering and processing assets:

 

						Design		Year Ended December 31, 2004
Facility		Location		Year Constructed		Throughput Capacity (Mcf/d) (1)		Natural Gas Throughput (Mcf/d)		Utilization of Design Capacity		NGL Throughput (gal/day)
90-mile Gas Gathering Pipeline		Manistee, Mason and Oceana Counties, MI		1994 –1998		35,000		12,300		35	%	NA
Fisk Processing Plant		Manistee County, MI		1998		35,000		12,300		35	%	26,900

 

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

 

The Partnership’s Michigan gathering pipeline gathers and transports sour gas produced by third parties in Oceana, Mason and Manistee Counties for sulfur removal at a treatment plant that is owned and operated by one of the Partnership’s customers. MarkWest Energy’s Fisk processing plant is located adjacent to the Partnership’s customer’s treatment plant. The Partnership’s gathering pipeline serves approximately 30 wells and four producers in this three county area. The Fisk plant processes all of the natural gas gathered by the Partnership’s pipeline and produces propane and a butane-natural gasoline mix.  MarkWest Energy processes natural gas under a number of third-party agreements containing both fee and percent-of-proceeds components. Under these agreements, production from all of the acreage adjacent to the Partnership’s pipeline and processing facility is dedicated to its gathering and processing facilities.  Fee arrangements represent approximately one-half of the Partnership’s gathering and processing gross margin in Michigan.

 

16

 

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

 

Michigan Crude Pipeline

 

The Michigan Crude Pipeline consists of approximately 150 miles of eight to 16-inch main pipeline, approximately 100 miles of four to ten-inch gathering pipeline, four truck loading facilities and 15 storage tanks.  The pipeline, which serves over 1,000 oil and gas wells on the Niagaran Reef Trend, delivers crude oil to the Enbridge Pipeline.  The Partnership generates operating margins by charging a pipeline transportation fee based on volumes.  The pipeline has a capacity of 60,000 bbl/d and transported approximately 14,700 bbl/d of crude oil for the year ended December 31, 2004.

 

MarkWest Hydrocarbon Assets

 

Marketing

 

Our marketing group markets our NGL production in Appalachia.  In 2004, we sold approximately 174 million gallons of NGLs extracted at the Partnership’s Siloam facility.  We ship NGL products from Siloam by truck, rail and barge. Our marketing customers include propane retailers, refineries, petrochemical plants and NGL product resellers.  Most marketing sales contracts have terms of one year or less, are made on best-efforts basis and are priced in reference to Mt. Belvieu index prices or plant posting prices.  In addition to our NGL product sales, our marketing operations are also responsible for the purchase of natural gas delivered for the account of producers pursuant to our keep-whole processing contracts.

 

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

 

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

 

Our operating agreements with Columbia Gas require us to enter into contracts with the natural gas producers for their production to be processed in the Partnership’s Kenova, Boldman and Cobb facilities prior to delivery of the producer’s natural gas to Columbia. We have contractual commitments with approximately 260 such producers in Appalachia. Approximately 54% of these contracts representing approximately 27% of the committed volumes expire in 2009. The remaining balance of approximately 46% of the contracts representing approximately 73% of the committed volumes expires in 2015.  Under the provisions of our contracts with the Appalachian producers, the producers have committed all of the natural gas they deliver into Columbia Gas’ transmission facilities upstream of MarkWest Energy’s Kenova, Boldman and Cobb facilities for processing.

 

As compensation for providing processing services to our Appalachian producers (we have since outsourced these services to MarkWest Energy as discussed below), we earn both a fee and retain the NGLs produced.  In return, we are required to replace, in dry natural gas, the energy content of the NGLs extracted. This Btu replacement obligation is referred to in the industry as a “keep-whole” arrangement. In keep-whole arrangements, our principal cost is the replacement of the Btus extracted from the gas stream in the form of NGLs or consumed as fuel during processing with dry gas of an equivalent Btu content. Generally, the value of the NGLs

 

17

 

extracted is greater than the cost of replacing those Btus with dry gas, resulting in positive operating margins under these contracts.  In the event natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, the cost of keeping the producer “whole” results in operating losses.  The spread between the NGL product sales price and the purchase price of natural gas with an equivalent Btu content is called the “frac spread”.

 

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

 

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

 

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

 

Our natural gas marketing group markets natural gas for MarkWest Energy’s facilities, purchases our replacement Btu gas requirements and assists with our business development efforts.  We also purchase and resell natural gas obtained from third parties.  Historically, a significant percentage of our overall revenue came from gas marketing, although the contribution to gross margin is generally modest.  With the growth of MarkWest Energy, the percentage of revenue derived from gas marketing has decreased significantly.  For the years ended December 31, 2004, 2003, and 2002, 8%, 17%, and 37%, respectively, of gathering, processing and marketing revenue stemmed from gas marketing. However, the gas marketing gross margin as a percent of gathering, processing and marketing gross margin was 1%, 0%, and 12%, respectively.

 

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

 

Exploration and Production

 

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

 

18

 

Reserves

 

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

 

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

 

Production

 

The following table sets forth information regarding net oil and natural gas production, average sales prices and other production information. Hedging gains and losses are disclosed separately for the years ended December 31, 2004, 2003 and 2002.

 

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

 

(1)   Oil and liquid production is converted to natural gas equivalents (Mcfe) at a rate of one barrel to six Mcf.

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

 

19

 

Productive Wells

 

The following table sets forth information regarding the number of productive wells in which we held a working interest at December 31, 2004:

 

		2004 Productive Wells (1)
		Gas Wells				Oil Wells
		Gross (2)		Net (3)		Gross		Net
United States
San Juan Basin		—		—		—		—
Michigan		3		.62		—		—
Total		3		.62		—		—
Canada
Alberta		—		—		—		—
Total wells		3		.62		—		—

 

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

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

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

 

Drilling and Recompletion Activity

 

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

 

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

 

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

(2)   One net well is deemed to exist when the sum of the fractional ownership working interest in gross wells equals one producing well, in addition to the existing producing horizon.  These are dually completed wells.

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

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

 

20

 

producing well, in addition to the existing producing horizon.  These are dually completed wells.

 

Acreage

 

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

 

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

 

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

(2)   Undeveloped acres are considered to be those acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.  It should not be confused with undrilled acreage held by production under the terms of a lease.

(3)   On December 12, 2003, the Company assigned all of its remaining undeveloped acreage located in Michigan to M & M Exploration Partners, LLC.  After the second anniversary of the assignment, the Company has the right to receive re-assignment of any acreage not committed to an exploration venture.

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

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

 

Factors Affecting our Operations

 

Seasonality

 

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

 

Competition

 

MarkWest Hydrocarbon

 

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

 

MarkWest Energy

 

The Partnership faces competition for natural gas and crude oil transportation and in obtaining natural gas supplies for its processing and related services operations, in obtaining unprocessed NGLs for fractionation, and in marketing our products and services. Competition for natural gas supplies is based primarily on the location of gas gathering facilities and gas processing plants, operating efficiency and reliability and ability to obtain a satisfactory price for products recovered. Competitive factors affecting our fractionation services include availability of capacity, proximity to supply and to industry marketing centers and cost efficiency and reliability of service. Competition for customers is based primarily on price, delivery capabilities, flexibility and maintenance of quality customer relationships.

 

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

 

•              major integrated oil companies;

 

21

 

•              medium and large sized independent E&P companies;

 

•              major interstate and intrastate pipelines;

 

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

 

•              a relatively large number of smaller gas gatherers of varying financial resources and experience.

 

Many of the Partnership’s competitors operate as master limited partnerships and enjoy a cost of capital comparable, and in some cases lower, than the Partnerships.  Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than MarkWest Energy Partners.  Smaller local distributors may enjoy a marketing advantage in their immediate service areas.

 

Operational Risks and Insurance

 

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

 

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

 

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

 

Title to Properties

 

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

 

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

 

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

 

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

 

22

 

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

 

The Partnership has pledged substantially all of its assets to secure the debt of the Partnership’s subsidiary MarkWest Energy Operating Company, L.L.C. (the “Operating Company”) as discussed in Note 9 of the accompanying Notes to Consolidated and Combined Financial Statements included in Item 8 of this Form 10-K.

 

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

 

Regulatory Matters

 

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

 

Some of the Partnership’s gas, liquids and crude oil gathering and transmission operations are subject to regulation by various regulatory bodies.  In many cases, various phases of the Partnership’s gas, liquids and crude oil operations in the states in which it operates are subject to rate and service regulation. Applicable statutes generally require that the Partnership’s rates and terms and conditions of service provide no more than a fair return on the aggregate value of the facilities used to render services.

 

The Partnership’s Appalachian pipeline carries NGLs across state lines. The primary shipper on the pipeline is MarkWest Hydrocarbon, who has entered into agreements with the Partnership providing for a fixed transportation charge for the term of the agreements, which expire on December 31, 2015.  The Partnership is the only other shipper on the pipeline. As the Partnership does not operate the Appalachian pipeline as a common carrier and does not hold the pipeline out for service to the public generally, there are currently no third-party shippers on this pipeline and the pipeline is and will continue to be operated as a proprietary facility and consequently should not be subject to regulation by the Federal Energy Regulatory Commission, (“FERC”).  However, we cannot provide assurance that FERC would not determine that such transportation is within its jurisdiction.  In such a case, MarkWest Energy would be required to file a tariff for such transportation with FERC and provide a cost justification for the transportation charge.  MarkWest Hydrocarbon has agreed to not challenge the status of the Partnership’s Appalachian pipeline or the transportation charge during the term of its agreements with MarkWest Hydrocarbon.  Moreover, the likelihood of other entities seeking to utilize the Partnership’s Appalachian pipeline is remote.  However, the Partnership cannot predict whether an assertion of FERC jurisdiction might be made with respect to this pipeline, nor provide assurance that such an assertion would not adversely affect its results of operations.  With respect to the Michigan Crude Pipeline, one shipper recently contacted FERC to inquire about a transportation rate increase and the pipeline’s regulatory rate structure.  In response, FERC requested that the Partnership contact the shipper to initiate a discussion regarding the shipper’s questions.  The Partnership is presently in discussions with all shippers regarding rate structures and is attempting to resolve any issues they may have.  FERC also requested that the Partnership file a tariff.  While the Michigan Crude Pipeline operations are entirely within the state of Michigan and have been regulated by the State of Michigan, the Partnership has calculated and determined that its current and proposed rate structures are well below rates that would be allowed under FERC’s cost of service rate-making structure.  However, the Partnership cannot predict whether a FERC jurisdictional assertion might be made with respect to the Michigan Crude Pipeline, nor provide assurance that such a development would not adversely affect the Company’s results of operations.

 

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

 

23

 

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

 

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

 

On November 8, 2004, a leak and release of vapors occurred in a pipeline transporting NGLs from the Maytown gas processing plant to the Partnership’s Siloam fractionator.  This pipeline is owned by a third party, and leased and operated by the Partnership’s subsidiary, MarkWest Energy Appalachia, LLC.  A subsequent ignition and fire from the leaked vapors resulted in property damage to five homes and injuries to some of the residents.  The exact cause of the leak and resulting fire is unknown and is being investigated by the OPS, the owner and the Partnership.  Pursuant to a Corrective Action Order issued by the OPS on November 18, 2004 and amended November 24, 2004, pipeline and valve integrity evaluation, testing and repair efforts are required and are being conducted on the affected pipeline segment before service can be resumed.  Both the Partnership and the pipeline owner are working with OPS to assure compliance with the Order.

 

Environmental Matters

 

MarkWest Hydrocarbon

 

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

 

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

 

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

 

24

 

MarkWest Energy

 

General.  The Partnership’s processing and fractionation plants, pipelines and associated facilities in connection with the gathering and processing of natural gas, the transportation, fractionation and storage of NGLs and the storage and gathering and transportation of crude oil are subject to multiple environmental obligations and potential liabilities under a variety of federal, state and local laws and regulations, including without limitation, the Comprehensive Environmental Response, Compensation, and Liability Act, the Resource Conservation and Recovery Act, the Clean Air Act, the Federal Water Pollution Control Act or the Clean Water Act, the Oil Pollution Act, and analogous state and local laws and regulations.  Such laws and regulations affect many aspects of the Partnership’s present and future operations and generally require the Partnership to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals, with respect to air emissions, water quality, wastewater discharges, solid and hazardous waste management.  Failure to comply with these laws, regulations, permits and licenses may expose the Partnership to fines, penalties and/or interruptions in its operations that could be material to the Company’s results of operations.  If an accidental leak, spill or release of hazardous substances occurs from the Partnership’s lines or facilities, in the process of transporting natural gas, or at any facilities that the Partnership owns, operates or otherwise uses, or where the Partnership sends materials for treatment or disposal, MarkWest Energy could be held jointly and severally liable for all resulting liabilities, including investigation, remedial and clean up costs.  Likewise, the Partnership could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination or to perform remedial operations to prevent future contamination for properties owned, leased or acquired by the Partnership which may have been previously operated by third parties and who may have released or disposed of hazardous substances or wastes, all of which could materially affect the our results of operations and cash flows.

 

Nevertheless, we believe that the Partnership’s operations and facilities are in substantial compliance with applicable environmental laws and regulations and that the cost of compliance with such laws and regulations will not have a material adverse effect on the our results of operations or financial condition.  However, we cannot ensure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to the Partnership.  The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts the Partnership currently anticipates.  Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from the Partnership’s customers, could have a material adverse effect on its business, financial condition, results of operations and cash flow.

 

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

 

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

 

25

 

Plant’s Clean Air Act permit.  MarkWest Energy has filed written responses to the NOV with the WVDEP and is in the process of negotiating a resolution of the alleged violations.  We do not believe that the resolution of these allegations will have a material adverse impact on our financial condition or results of operations.

 

Employee Safety

 

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

 

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

 

Employees

 

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

 

Available Information

 

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

 

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

 

26

 

ITEM 3.  LEGAL PROCEEDINGS

 

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

 

The Company, the Partnership and several of its affiliates were served in early 2005 with two lawsuits captioned as follows:

 

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

 

Charles C. Reid, et al. v. MarkWest Hydrocarbon, Inc. et al., (Floyd Circuit Court, Commonwealth of Kentucky, Civil Action No. 05-CI-00156), filed February 8, 2005.

 

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

 

While investigation into the incident and defense of the action continues, settlement has been reached with respect to several of the plaintiffs and claims, and at this time the Company believes that it has adequate insurance coverage for third-party property damage and personal injury liability resulting from the incident. The deductible for the insurance is $0.3 million, which has been accrued as a charge to operations in 2004.

 

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

 

The Company along with several other defendants are defending a lawsuit captioned Merrimans v. Atlas Gas Company, et al., (Columbia County Court of Common Pleas, Ohio, case number 2003 CV 0202).  This case involves a claim that propane or methane gas escaped into the basement of a residence and ignited causing injuries to the plaintiff.  The claim against the Company concerns proper oderization of propane product which plaintiff had used.  The Company denies plaintiff’s claims and among other defenses, the Company also asserts that the residential supplier had responsibility for proper oderization, and has filed a cross-claim for indemnity against such party, together with a third party complaint against such party’s insurer.  Discovery is continuing and settlement discussions are being pursued.  A trail date has been rescheduled several times but has been vacated and a trial date is presently unscheduled.  The Company is actively defending the action, and believes that it has valid defenses to plaintiff’s claims, and a valid cross-claim for indemnity against the residential supplier, and a bad faith claim against the insurer.  The court recently granted Summary Judgment in favor of the Company regarding its cross-claim for indemnification.  However, the Company is unable to determine at this time, whether it will ultimately be successful in its defenses with regard to the plaintiffs, its remaining bad faith claim, or any appeals of the Summary Judgment cross-claims in the action.  Notwithstanding, at this time, the Company believes that it has adequate insurance coverage for any liability resulting from the incident.

 

27

 

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

 

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

 

28

 

PART II

 

ITEM 5.  MARKET FOR THE 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 September 9, 2005, there were 10,794,729 shares of common stock outstanding held by approximately 40 holders of record. The following table sets forth quarterly high and low sales prices as reported by the American Stock Exchange, as retroactively restated to give effect to the 2004 and 2003 stock dividends (see below), for the periods indicated, as well as the amount of cash dividends paid per share per quarter for 2004 and 2003.

 

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

 

Dividend Policy

 

The Company does not have a formal dividend policy. However, the Company’s objective is to maintain a regular quarterly dividend.  Payment of dividends in the future will depend on our earnings, financial condition and contractual restrictions, including those under our bank line of credit or imposed by law and other factors deemed relevant by our Board of Directors.

 

Stock Dividends

 

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

 

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

 

29

 

ITEM 6.  SELECTED FINANCIAL DATA

 

The following table sets forth selected consolidated historical financial and operating data for MarkWest Hydrocarbon.  Certain prior year amounts have been reclassified to conform to the 2004 presentation. The selected consolidated statement of operations and balance sheet data for the years ended December 31, 2004, 2003 and 2002, and as of December 31, 2004 and 2003, are derived from, and are qualified by reference to, our audited Consolidated Financial Statements included elsewhere in this Form 10-K.  The selected consolidated statement of operations and balance sheet data set forth below for the years ended December 31, 2001 and 2000, and as of December 31, 2002, 2001 and 2000, have been derived from audited financial statements not included in this Form 10-K. You should read this in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements and accompanying Notes included elsewhere in this Form 10-K.

 

On April 11, 2005, management, after discussion with the Audit Committee of our Board of Directors, determined that previously issued financial statements for the years ended December 31, 2002 and 2003 and for each of the first three quarters of 2003 and 2004 should be restated to reflect compensation expense attributable to the sale of subordinated Partnership units and interests in the Partnership’s general partner to certain employees and directors of MarkWest Hydrocarbon that occurred during 2002, 2003 and 2004.  These transactions were previously reflected as sales of assets.  In addition, an adjustment of $2.5 million was also made to restate restricted marketable securities from restricted cash.  Finally, the Company adjusted the income tax provision (benefit) for the restatement adjustments.

 

The Company has also restated revenue for 2003 by $0.1 million to record natural gas inventory at cost.  Previously the inventory was incorrectly identified as a pipeline imbalance and was recorded at market value.

 

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

 

30

 

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

 

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

 

31

 

Operating Data

 

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

 

(1)   Represents sales at the Siloam fractionator.

(2)   Represents sales from our wholesale business.  Volumes are from the period since the Company started the line of business in February 2004.

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

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

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

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

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

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

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

 

32