Annual Reports

  • 10-K (Feb 25, 2015)
  • 10-K (Feb 26, 2014)
  • 10-K (Feb 27, 2013)
  • 10-K (Feb 28, 2011)
  • 10-K (Mar 1, 2010)
  • 10-K (Mar 2, 2009)

 
Quarterly Reports

 
8-K

 
Other

MarkWest Energy Partners, LP 10-K 2007

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

x

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006.

or

o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

for the transition period from                  to                   .

 

Commission File Number 001-31239

 

MARKWEST ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware

 

27-0005456

(State or other jurisdiction of
incorporation or organization)

 

(I.R.S. Employer
Identification No.)

 

1515 Arapahoe Street, Tower 2, Suite 700, Denver, CO 80202-2126
(Address of principal executive offices)

 

Registrant’s telephone number, including area code:  303-925-9200

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

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

Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o

Indicate by check mark if the registrant is not required file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x

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 xNo o

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

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

Large accelerated filer o   Accelerated filer x          Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x

The aggregate market value of Common Units held by non-affiliates of the registrant on June 30, 2006 was approximately $556,894,000.

As of March 1, 2007, the number of the registrant’s Common Units and Subordinated Units were 31,206,514 and 1,200,000, respectively.

DOCUMENTS INCORPORATED BY REFERENCE: None.




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

PART I

 

 

Item 1.

 

Business

Item 1A.

 

Risk Factors

Item 1B.

 

Unresolved Staff Comments

Item 2.

 

Properties

Item 3.

 

Legal Proceedings

Item 4.

 

Submission of Matters to a Vote of Security Holders

 

 

 

PART II

 

 

Item 5.

 

Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities

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, Executive Officers and Corporate Governance

Item 11.

 

Executive Compensation

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

Item 14.

 

Principal Accountant Fees and Services

 

 

 

PART IV

 

 

Item 15.

 

Exhibits and Financial Statement Schedules

 

 

 

SIGNATURES

 

 

 

Throughout this document we make statements that are classified as “forward-looking.” Please refer to the “Forward-Looking Statements” included later in this section for an explanation of these types of assertions. Also, in this document, unless the context requires otherwise, references to “we,” “us,” “our,” “MarkWest Energy” or the “Partnership” are intended to mean MarkWest Energy Partners, L.P., 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

Mcf

 

one thousand cubic feet of natural gas

Mcf/d

 

one thousand cubic feet of natural gas per day

MMBtu

 

one million British thermal units, an energy measurement

MMcf

 

one million cubic feet of natural gas

MMcf/d

 

one million cubic feet of natural gas per day

MTBE

 

methyl tertieary butyl ether

Net operating margin (a non-GAAP financial measure)

 

revenues less purchased product costs

NGLs

 

natural gas liquids, such as propane, butanes and natural gasoline

NA

 

not applicable

Tcf

 

one trillion cubic feet of natural gas

 

2




Forward-Looking Statements

Statements included in this annual report on Form 10-K that are not historical facts are forward-looking statements. We use words such as “could,” “may,” “will,” “should,” “expect,”  “plan,” “project,” “anticipate,” “believe,” “estimate,” “intend” 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.

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

·                                          our ability to successfully integrate our recent or future acquisitions;

·                                          the availability of natural gas supply for our gathering and processing services;

·                                          the availability of crude oil refinery runs to feed our Javelina off-gas processing facility;

·                                          our substantial debt and other financial obligations could adversely impact our financial condition;

·                                          the availability of NGLs for our transportation, fractionation and storage services;

·                                          our dependence on certain significant customers, producers, gatherers, treaters and transporters of natural gas, including MarkWest Hydrocarbon;

·                                          the risks that third-party oil and gas exploration and production activities will not occur or be successful;

·                                          prices of crude oil, natural gas and NGL products, including the effectiveness of any hedging activities;

·                                          competition from other NGL processors, including major energy companies;

·                                          changes in general economic, market or business conditions in regions where our products are located;

·                                          our ability to identify and consummate grass roots projects or acquisitions complementary to our business;

·                                          the success of our risk management policies;

·                                          continued creditworthiness of, and performance by, contract counterparties;

·                                          operational hazards and availability and cost of insurance on our assets and operations;

·                                          the impact of any failure of our information technology systems;

·                                          the impact of current and future laws and government regulations;

·                                          liability for environmental claims;

·                                          damage to facilities and interruption of service due to casualty, weather, mechanical failure or any extended or extraordinary maintenance or inspection that may be required;

·                                          the impact of the departure of any key executive officers; and

·                                          our ability to raise sufficient capital to execute our business plan through borrowing or issuing equity.

This list is not necessarily complete. Other unknown or unpredictable factors could also have material adverse effects on future results. The Partnership does not update publicly any forward-looking statement with new information or future events. Investors are cautioned not to put undue reliance on forward-looking statements as many of these factors are beyond our ability to control or predict. You should read “Risk Factors” included in Item 1A of this Form 10-K for further information.

3




PART I

ITEM 1.                    Business

General

MarkWest Energy Partners, L.P. is a publicly traded Delaware limited partnership formed by MarkWest Hydrocarbon, Inc. on January 25, 2002, to acquire most of the assets, liabilities and operations of the MarkWest Hydrocarbon Midstream Business.  The MarkWest Hydrocarbon Midstream Business included natural gas gathering and processing assets and NGL transportation, fractionation and storage assets.  We are a master limited partnership engaged in the gathering, transportation and processing of natural gas; the transportation, fractionation and storage of NGLs; and the gathering and transportation of crude oil. We are the largest processor of natural gas in the Appalachia region. We also have a large natural gas gathering and transmission business in the southwestern United States, built primarily through acquisitions and investments: Pinnacle Natural Gas, the Lubbock transmission pipeline and the Foss Lake gathering system, all in 2003; the Carthage gas processing plant in East Texas in July 2004; a non-controlling, 50% interest in Starfish Pipeline Company, LLC (“Starfish”) and the Javelina entities’ natural gas processing and fractionation facility and pipeline in Corpus Christi, Texas, both in 2005; the initial construction of the Woodford gathering system in the Arkoma Basin of southeastern Oklahoma, and the acquisition of the Grimes gathering system in western Oklahoma, both in 2006.

MarkWest Energy Partners generates revenues for providing gathering, processing, transportation, fractionation, and storage services. We believe that the largely fee-based nature of its business and the relatively long-term nature of its contracts provide a relatively stable base of cash flows. As a publicly traded partnership, we have access to, and regularly utilize, both equity and debt capital markets as a source of financing, as well as that provided by our credit facility and the ability to use common units in connection with acquisitions. Our limited partnership structure also provides tax advantages to our unitholders.

We conduct our operations in three geographical areas:  the Southwest, the Northeast and the Gulf Coast.  Our assets and operations in each of these areas are described below.

Southwest Business Unit

·                  East Texas. We own the East Texas System, consisting of natural gas gathering system pipelines, centralized compressor stations, and a natural gas processing facility and NGL pipeline. The East Texas System is located in Panola, Harrison and Rusk Counties and services the Carthage Field, one of Texas’ largest onshore natural gas fields. Producing formations in Panola County consist of the Cotton Valley, Pettit and Travis Peak formations, which together form one of the largest natural gas producing regions in the United States.  The East Texas segment has one customer, Targa Resources Partners, L.P., which makes up a significant portion of its segment revenues as well as 13% of the Partnership’s consolidated revenue in 2006.

·                  Oklahoma. We own the Foss Lake gathering system and the Arapaho gas processing plant, located in Roger Mills, Custer and Ellis counties of western Oklahoma. The gathering portion consists of a pipeline system that is connected to natural gas wells and associated compression facilities. All of the gathered gas ultimately is compressed and delivered to the processing plant.  We also own a gathering system in the Woodford Shale play in the Arkoma Basin of southeastern Oklahoma, and we own the Grimes gathering system, which is located in Roger Mills and Beckham counties in western Oklahoma.  The Oklahoma segment has two customers which account for a significant portion of its segment revenue.  Of the two significant customers to the segment, only ONEOK, which accounts for 11% of consolidated revenue in 2006, was material to the Partnership.

·                  Other Southwest. We own a number of natural gas-gathering systems located in Texas, Louisiana, Mississippi and New Mexico, including the Appleby gathering system in the City and County of Nacogdoches, Texas. In addition, we own four lateral pipelines in Texas and New Mexico.  The Other Southwest segment does not have any customers which are considered to be significant to their segment.

Northeast Business Unit

·                  Appalachia. We are the largest processor of natural gas in the Appalachian Basin with fully integrated processing, fractionation, storage and marketing operations. Our Appalachian assets include the Kenova, Boldman, Maytown, Cobb and Kermit natural gas-processing plants, an NGL pipeline, an NGL fractionation plant and two caverns for storing propane.  The Appalachia segment has one customer which accounts for a significant portion of its segment revenue but does not account for a

4




significant portion of the Partnership’s consolidated revenue.

·                  Michigan. We own and operate a crude oil pipeline in Michigan, which we refer to as the Michigan Crude Pipeline. The Michigan Crude Pipeline is subject to regulation by the Federal Energy Regulatory Commission (“FERC”). We also own a natural gas-gathering system and the Fisk processing plant in Manistee County, Michigan.  The Michigan segment does not have any customers which are considered to be significant to their segment revenue.

Gulf Coast Business Unit

·                  Javelina. We own and operate the Javelina Processing Facility, a natural gas processing facility in Corpus Christi, Texas, which processes off-gas from six local refineries. The facility processes approximately 125 to 130 MMcf/d of inlet gas, but is expected to process up to its capacity of 142 MMcf/d as refinery output continues to grow.  The Javelina segment has five customers which account for a significant portion of its segment revenue but do not account for a significant portion of the Partnership’s consolidated revenue.

·                  Starfish. We own a 50% non-operating membership interest in Starfish, whose assets are located in the Gulf of Mexico and southwestern Louisiana. The Starfish interest is part of a joint venture with Enbridge Offshore Pipelines LLC, which is accounted for using the equity method; the financial results for Starfish are included in equity from earnings (losses) from unconsolidated affiliates and are not included in the Gulf Coast Business Unit results.

5




Industry Overview, Competition

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

The natural gas gathering process begins with the drilling of wells into gas bearing rock formations. Once 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 has a widely varying composition, depending on the field, the formation reservoir or facility from which it is produced. The principal constituents of natural gas are methane and ethane. 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. It must be gathered, compressed and transported via pipeline to a central facility, and then processed to remove the heavier hydrocarbon components and other contaminants that interfere with pipeline transportation or the end-use of the gas. Our business includes providing these services either for a fee or a percentage of the NGLs removed or gas units processed. The industry as a whole is characterized by regional competition, based on the proximity of gathering systems and processing plants to producing natural gas wells, or to facilities that produce natural gas as a byproduct of refining crude oil.

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

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. Raw natural gas from the wellhead is gathered at a processing plant, typically located near the production area, where it is dehydrated and treated, and then processed to recover a mixed NGL stream. In the case of our Javelina facilities, the natural gas delivered to our processing plant is a byproduct of the crude oil refining process.

The removal and separation of individual hydrocarbons by processing is possible because of differences in physical properties. Each component has a distinctive weight, boiling point, vapor pressure and other physical characteristics. Natural gas may also be diluted or contaminated by water, sulfur compounds, carbon dioxide, nitrogen, helium or other components. We also produce a high quality hydrogen stream that is delivered back to certain refinery customers.

After being separated from natural gas at the processing plant, the mixed NGL stream is typically transported to a

6




centralized facility for fractionation. Fractionation is the process by which NGLs are further separated into individual, more marketable components, primarily 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 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 our Siloam fractionator, as there is little petrochemical demand for ethane in Appalachia. It remains, therefore, in the natural gas stream. Ethane, however, is produced and sold in our East Texas and Oklahoma operations.

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

·                          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.

·                          Isobutane is principally used by refiners to enhance the octane content of motor gasoline, as well as in the production of MTBE, an additive in cleaner-burning motor gasoline.

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

We face competition for natural gas and crude oil transportation and in obtaining natural gas supplies for our 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 the ability to obtain a satisfactory price for products recovered. Competitive factors affecting our fractionation services include availability of capacity, proximity to supply and industry marketing centers, and cost efficiency and reliability of service. Competition for customers is based primarily on price, delivery capabilities, flexibility and maintenance of high-quality customer relationships.

Our competitors include:

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

·                          major integrated oil companies;

·                          medium and large sized independent exploration and production companies;

·                          major interstate and intrastate pipelines; and

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

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

We believe our competitive strengths include:

·                  Strategic and growing position with high-quality assets in the Southwest and the Gulf Coast. Our acquisitions and internal growth projects have allowed us to establish and expand our presence in several long-lived natural gas supply basins in the Southwest, particularly in Texas, Oklahoma and the Gulf Coast. In 2006, we expanded this strategy through our Newfield agreement by building the largest gathering system to date in the newly emerging Woodford Shale play in southeastern Oklahoma.  All of our major acquisitions in these regions have been characterized by several common critical success factors that include:

    an existing strong competitive position;

    access to a significant reserve or customer base with a stable or growing production profile;

    ample opportunities for long-term continued organic growth;

7




    ready access to markets; and

    close proximity to other acquisition or expansion opportunities.

Specifically, our East Texas and Appleby gathering systems are located in the East Texas basin producing from both the Cotton Valley and Travis Peak reservoirs. Our Foss Lake gathering system and the associated Arapaho gas processing plant, which we refer to as our western Oklahoma assets, are located in the Anadarko basin in Oklahoma. Additionally, as mentioned above, our Woodford gathering system is located in the rapidly growing Woodford shale reservoir.  Finally, our Starfish asset gathers gas from multiple reservoirs in the Gulf of Mexico.  Each of these basins are highly prolific with long lived reserves and significant growth potential.  Our gathering systems are relatively new and provide producers with low-pressure and fuel-efficient service, a significant competitive advantage for us over many competing gathering systems in those areas. We believe this competitive advantage is evidenced by our growing throughput volumes on our East Texas, Appleby, western and southeastern Oklahoma operations.

·                  Leading position in the Appalachian Basin. We are the largest processor of natural gas in Appalachia. We believe our significant presence and asset base provide us with a competitive advantage in capturing and contracting for new supplies of natural gas. The Appalachian Basin is a large natural gas-producing region characterized by long-lived reserves with modest decline rates and natural gas with high NGL content. These reserves provide a stable supply of natural gas for our processing plants and our Siloam NGL fractionation facility. Our concentrated infrastructure, and available land and storage assets, in Appalachia should provide us with a platform for additional cost-effective expansion.

·                  Stable cash flows. We believe our numerous fee-based contracts and our active commodity risk management program provide us with stable cash flows. For the year ended December 31, 2006, we generated approximately 32% of our net operating margin (a non-GAAP financial measure, see Item1.Business — Our Contracts) from fee-based services.  Net operating margin depends on throughput volume, but is typically not affected by short-term changes in commodity prices. In addition, a portion of our fee-based business is generated by our four lateral pipelines in the Southwest, which typically provide fixed transportation fees independent of the volumes transported. We also believe that an active commodity risk management program is a significant component of providing stable cash flows as our commodity exposure grows with our expanding operations.

·                  Common carrier crude oil pipeline in Michigan. We own a common carrier crude oil gathering pipeline in Michigan. Our pipeline receives oil directly from in-state well production and is connected to Enbridge pipeline for transportation to interstate destinations. We enjoy a competitive advantage over higher cost crude oil transportation alternatives such as trucking. Most of the crude oil we transport in the state is produced from the Niagaran Reef Trend, which is generally characterized by long-lived crude oil reserves.

·                  Long-term Contracts. We believe our long-term contracts, which we define as contracts with remaining terms of four years or more, lend greater stability to our cash-flow profile. For the year ended December 31, 2006, approximately 67% of our inlet volumes were tied to long-term contracts. In East Texas, approximately 80% of our current gathering volumes as of December 31, 2006, are under contract for longer than five years. Two of our Pinnacle lateral pipelines operate under fixed-fee contracts for the transmission of natural gas that expire in approximately 16 and 24 years, respectively. Approximately 26% of our daily throughput in the Foss Lake gathering system and Arapaho processing plant in western Oklahoma is subject to contracts with remaining terms of five years or more. In Appalachia, we have natural gas processing and NGL fractionation contracts with remaining terms from 5 to 11 years. In Michigan, our natural gas transportation, treating and processing agreements have remaining terms of 10 to 22 years.

·                  Experienced management with operational, technical and acquisition expertise. Each member of our executive management team has substantial experience in the energy industry. Our facility managers have extensive experience operating our facilities. Our operational and technical expertise has enabled us to upgrade our existing facilities, as well as to design and build new ones, specifically the Carthage gas processing plant.  Since our initial public offering in May 2002, our management team has utilized a disciplined approach to analyze and evaluate numerous acquisition opportunities, and has completed nine acquisitions. We intend to continue to use our management’s experience and disciplined approach in evaluating and acquiring assets to grow through accretive acquisitions — those acquisitions expected to increase our throughput volumes and cash flow distributable to our unitholders.

·                  Financial strength and flexibility. During 2006, we issued approximately $126.0 million of equity. Our goal is to maintain a capital structure with approximately equal amounts of debt and equity on a long-term basis.

8




As of December 31, 2006, we have available borrowing capacity of approximately $218.4 million under our $250.0 million revolving credit facility. This amount is determined on a quarterly basis and is further adjusted to take into consideration the cash flow contribution of an acquisition at the time of its closing. The credit facility, together with our ability to issue additional partnership units for financing and acquisition purposes, should provide us with a flexible financial structure that will facilitate the execution of our business strategy.

Our primary business strategy is to grow our business and increase distributable cash flow, and in turn distributions per unit to our common unitholders, improving financial flexibility and increasing our ability to access capital to fund our growth. We plan to accomplish this through the following:

·                  Increasing utilization of our facilities. We hope to add to, or provide additional services to, our existing customers, and to provide services to other natural gas and crude oil producers in our areas of operation. Increased drilling activity in our core areas of operation, particularly within certain fields in the Southwest, should also produce increasing natural gas and crude oil supplies, and a corresponding increase in utilization of our transportation, gathering, processing and fractionation facilities. In the meantime, we continue to develop additional capacity at several of our facilities, which enables us to increase throughput with minimal incremental costs.

·                  Expanding operations through internal growth projects. By expanding our existing infrastructure and customer relationships, we intend to continue growing in our primary areas of operation to meet the anticipated need for additional midstream services. During 2006, we spent approximately $75.1 million of growth capital to expand several of our gathering and processing operations. Projects included the initial construction of the Woodford gathering system in the Arkoma Basin in eastern Oklahoma, ongoing compressor expansions in East Texas, and well connection expansion projects in the Southwest Business Unit.

·                  Expanding operations through strategic acquisitions. We intend to continue pursuing strategic acquisitions of assets and businesses in our existing areas of operation that leverage our current asset base, personnel and customer relationships. We will also seek to acquire assets in certain regions outside of our current areas of operation.

·                  Securing additional long-term, fee-based contracts. We intend to continue to secure long-term, fee-based contracts in both our existing operations and strategic acquisitions, in order to further minimize our exposure to short-term changes in commodity prices.

The Partnership engages in risk management activities in order to reduce the effect of commodity price volatility related to future sales of natural gas, ethane, propane and crude oil. It may utilize a combination of fixed-price forward contracts, fixed-for-floating price swaps, options available in the over-the-counter market, and futures contracts traded on the New York Mercantile Exchange. The Partnership monitors these activities through enforcement of our risk management policy (see Item 7A, “Commodity Price Risk”).

To better understand our business and the results of operations discussed in Item 6, “Selected Financial Data” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation,” the following three factors are important to consider:

·                  the nature of the contracts from which we derive our revenues;

·                  the difficulty in comparing our results of operations across periods because of our acquisition activity; and

·                  the nature of our relationship with MarkWest Hydrocarbon, Inc.

Our Contracts

We generate the majority of our revenues and net operating margin (a non-GAAP measure, see below for discussion and reconciliation of net operating margin) from natural gas gathering, processing and transmission; NGL transportation, fractionation and storage; and crude oil gathering and transportation. We enter into a variety of contract types. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described below. We provide services under the following different types of arrangements (all of which constitute midstream energy operations):

·                                        Fee-based arrangements: Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, processing and transmission of natural gas; transportation, fractionation and storage of NGLs; and gathering and transportation of crude oil. The revenue we earn from these arrangements is directly related to the volume of natural gas, NGLs or crude oil that flows through our

9




systems and facilities and is not directly dependent on commodity prices. In certain cases, our arrangements provide for minimum annual payments. If a sustained decline in commodity prices were to result in a decline in volumes, however, our revenues from these arrangements would be reduced.

·                                          Percent-of-proceeds arrangements: Under percent-of-proceeds arrangements, we gather and process natural gas on behalf of producers, sell the resulting residue gas, condensate and NGLs at market prices and remit to producers an agreed-upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, we deliver an agreed-upon percentage of the residue gas and NGLs to the producer and sell the volumes we keep to third parties at market prices. Generally, under these types of arrangements our revenues and gross margins increase as natural gas, condensate prices and NGL prices increase, and our revenues and net operating margins decrease as natural gas and NGL prices decrease.

·                                          Percent-of-index arrangements: Under percent-of-index arrangements, we purchase natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount. We then gather and deliver the natural gas to pipelines where we resell the natural gas at the index price, or at a different percentage discount to the index price. With respect to (1) and (3) above, the net operating margins we realize under the arrangements decrease in periods of low natural gas prices because these net operating margins are based on a percentage of the index price. Conversely, our net operating margins increase during periods of high natural gas prices.

·                                          Keep-whole arrangements: Under keep-whole arrangements, we gather natural gas from the producer, process the natural gas and sell the resulting condensate and NGLs to third parties at market prices. Because the extraction of the condensate and NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make cash payment to the producers equal to the energy content of this natural gas. Accordingly, under these arrangements our revenues and net operating margins increase as the price of condensate and NGLs increases relative to the price of natural gas, and decrease as the price of natural gas increases relative to the price of condensate and NGLs.

·                                          Settlement margin: Typically, we are allowed to retain a fixed percentage of the volume gathered to cover the compression fuel charges and deemed-line losses. To the extent our gathering systems are operated more efficiently than specified per contract allowance, we are entitled to retain the difference for our own account.

The terms of our contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements. Our contract mix and, accordingly, our exposure to natural gas and NGL prices, may change as a result of changes in producer preferences, our expansion in regions where some types of contracts are more common and other market factors. Any change in mix will influence our financial results.

As of December 31, 2006, our primary exposure to keep-whole contracts was limited to our Arapaho (Oklahoma) processing plant and our East Texas processing contracts. At the Arapaho plant inlet, the Btu content of the natural gas meets the downstream pipeline specification; however, we have the option of extracting NGLs when the processing margin environment is favorable. In addition, approximately 25% (as measured in volumes) of the related gas gathering contracts include additional fees to cover plant operating costs, fuel costs and shrinkage costs in a low-processing margin environment. Due to our ability to operate the Arapaho plant in several recovery modes, our overall keep-whole contract exposure is limited to a small portion of the operating costs of the plant.

Approximately 18% of the gas processed in East Texas for producers was processed under keep-whole terms. Our keep-whole exposure in this area was offset to a great extent because the East Texas agreements provide for the retention of natural gas as a part of the gathering and compression arrangements with all producers on the system. This excess gas helps offset the amount of replacement natural gas purchases required to keep our producers whole on an MMbtu basis, thereby creating a partial natural hedge. The net result is a significant reduction in volatility for these changes in natural gas prices. The remaining volatility for these contracts results from changes in NGL prices. The Partnership has an active commodity risk management program in place to reduce the impacts of changing NGL prices.

Management evaluates contract performance on the basis of net operating margin (a non-GAAP financial measure), which is defined as income (loss) from operations, excluding facility expense, selling, general and administrative expense, depreciation, amortization, impairments and accretion of asset retirement. These charges have been excluded for the purpose of

10




enhancing the understanding by both management and investors of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance for purposes of planning and forecasting. Net operating margin does not have any standardized definition and therefore is unlikely to be comparable to similar measures presented by other reporting companies. Net operating margin results should not be evaluated in isolation of, or as a substitute for our financial results prepared in accordance with United States GAAP. Our usage of net operating margin and the underlying methodology in excluding certain charges is not necessarily an indication of the results of operations expected in the future, or that we will not, in fact, incur such charges in future periods.

The following is a reconciliation to the most comparable GAAP financial measure of this non-GAAP financial measure (in thousands):

 

Year ended December 31,

 

 

 

2006

 

2005

 

2004

 

Revenues

 

$

575,952

 

$

499,084

 

$

301,314

 

Purchased product costs

 

322,278

 

366,878

 

211,534

 

Net operating margin

 

253,674

 

132,206

 

89,780

 

Facility expenses

 

60,112

 

47,972

 

29,911

 

Selling, general and administrative

 

44,185

 

21,573

 

16,133

 

Depreciation

 

29,993

 

19,534

 

15,556

 

Amortization of intangible

 

16,047

 

9,656

 

3,640

 

Accretion of asset retirement obligation

 

102

 

159

 

13

 

Impairments

 

 

 

130

 

Income from operations

 

$

103,235

 

$

33,312

 

$

24,397

 

 

For the year ended December 31, 2006, we calculated the following approximate percentages of our revenues and net operating margin from the following types of contracts:

 

 

Fee-Based

 

Percent-of-
Proceeds (1)

 

Percent-of-
Index (2)

 

Keep-Whole (3)

 

Total

 

Revenues

 

14

%

25

%

43

%

18

%

100

%

Net operating margin

 

32

%

38

%

13

%

17

%

100

%


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

(2)           Includes settlement margin, condensate sales and other types of arrangements tied to natural gas prices.

(3)           Includes settlement margin, condensate sales and other types of arrangements tied to both NGL and natural gas prices.

Our short natural gas positions under our keep-whole contracts are largely offset by our long positions in our other operating areas. As a result, our net exposure to natural gas is not significant. While the percentages in the table above accurately reflect the percentages by contract type, we manage our business by taking into account the offset described above, required levels of operational flexibility and the fact that our hedge plan is implemented on this basis. When considered on this basis, the calculated percentages for the net operating margin in the table above for Percent-of-Proceeds, Percent-of-Index and Keep-Whole contracts change to 62%, 0% and 6%, respectively.

Acquisitions

Since our initial public offering, we have completed nine acquisitions for an aggregate purchase price of approximately $810 million, net of working capital. The following table sets forth information regarding each of these acquisitions:

 

Name

 

Assets

 

Location

 

Consideration

 

Closing Date

 

 

 

 

 

 

 

 

 

 

 

Santa Fe

 

Grimes gathering system

 

Oklahoma

 

$

15.0

 

December 29, 2006

 

 

 

 

 

 

 

 

 

 

 

Javelina (1)

 

Gas processing and fractionation
facility

 

Corpus Christi, TX

 

398.8

 

November 1, 2005

 

 

 

 

 

 

 

 

 

 

 

Starfish (2)

 

Natural gas pipeline, gathering system
and dehydration facility

 

Gulf of
Mexico/Southern
Louisiana

 

41.7

 

March 31, 2005

 

 

 

 

 

 

 

 

 

 

 

East Texas

 

Gathering system and gas
procession assets

 

East Texas

 

240.7

 

July 30, 2004

 

 

 

 

 

 

 

 

 

 

 

Hobbs

 

Natural gas pipeline

 

New Mexico

 

2.3

 

April 1, 2004

 

 

 

 

 

 

 

 

 

 

 

Michigan Crude Pipeline

 

Common carrier crude oil pipeline

 

Michigan

 

21.3

 

December 18, 2003

 

 

 

 

 

 

 

 

 

 

 

Western Oklahoma

 

Gathering system

 

Western Oklahoma

 

38.0

 

December 1, 2003

 

 

 

 

 

 

 

 

 

 

 

Lubbock Pipeline

 

Natural gas pipeline

 

West Texas

 

12.2

 

September 2, 2003

 

 

 

 

 

 

 

 

 

 

 

Pinnacle

 

Natural gas pipelines and
gathering systems

 

East Texas

 

39.9

 

March 28, 2003

 

 

 

11





(1)   Consideration includes $35.5 million in cash.
(2)   Represents a 50% non-controlling interest.

Our Relationship with MarkWest Hydrocarbon, Inc.

We were formed by MarkWest Hydrocarbon in 2002 to acquire most of its natural gas gathering and processing assets and NGL transportation, fractionation and storage assets. MarkWest Hydrocarbon remains one of our largest customers. We expect to continue deriving a portion of our revenues from the services we provide under our contracts with MarkWest Hydrocarbon; however, the percentage of our revenues and net operating margins will likely continue to decline as our other businesses grow. For the year ended December 31, 2006, it accounted for 13% of our revenues compared to 13% of our revenues for the year ended December 31, 2005. As of December 31, 2006, MarkWest Hydrocarbon and its subsidiaries, in the aggregate, owned a 17% interest in the Partnership, consisting of 1,200,000 subordinated units, 3,738,992 common units and a 2% general partner interest.

Neither we nor our General Partner have any employees.  However, under a Services Agreement entered into between our General Partner and MarkWest Hydrocarbon, Inc., MarkWest Hydrocarbon acts in a management capacity rendering day-to-day operational, business and asset management, accounting, information services, personnel and related administrative services to the Partnership. In return, the Partnership reimburses MarkWest Hydrocarbon for all documented expenses incurred on behalf of the Partnership and which are expressly designated as reasonably necessary for the performance of the prescribed duties and specified functions.  General corporate expenses and costs that are not specifically linked to either MarkWest Hydrocarbon or us are allocated in accordance with an approved allocation methodology which is designed to ensure that neither entity bears a disproportionate or unfair burden of the other company’s costs and expenses, and is reflective of respective income statements.  Additionally, at the time of our IPO we entered into the following agreements with MarkWest Hydrocarbon:

 

·              an Omnibus Agreement  governing potential competition and indemnification obligations among us and the other parties to the agreement;

 

·              a Gas Processing Agreement governing our obligations with respect to the processing of natural gas at our Kenova, Boldman and Cobb processing plants;

 

·              a Pipeline Liquids Transportation Agreement governing our obligations with respect to the transportation of mixed NGLs to our Siloam fractionation facility;

 

·              a Fractionation, Storage and Loading Agreement governing our obligations with respect to the unloading and fractionation of NGLs and the storage of the NGL products at our Siloam facility; and

 

·              a Natural Gas Liquids Purchase Agreement which governs our obligations with respect to the sale and purchase of NGL products we acquire under the Gas-Processing (Maytown) Agreement between a third party producer and MarkWest Hydrocarbon, which were assigned to us, as well as any other NGL products we acquire.

 

For a more detailed description of these agreements, see “Part III, Item 13—Certain Relationships and Related Transactions.”

Segment Reporting

Segments. As described below, we have six segments, based on geographic areas of operations. For further information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” included in Item 7 of this Form 10-K, and “Financial Statements and Supplementary Data,” included in Item 8 of this report on Form 10-K.

Southwest Business Unit

·        East Texas. We own the East Texas System, consisting of natural gas gathering system pipelines, centralized compressor stations, and a natural gas processing facility and NGL pipeline. The East Texas System is located in Panola, Harrison and Rusk Counties and services the Carthage Field, one of Texas’ largest onshore natural gas fields. Producing formations in Panola County consist of the Cotton Valley, Pettit and Travis Peak formations, which together form one of the largest natural gas producing regions in the United States.

12




·        Oklahoma. We own the Foss Lake gathering system and the Arapaho gas processing plant, located in Roger Mills, Custer and Ellis counties of western Oklahoma. The gathering portion consists of a pipeline system that is connected to natural gas wells and associated compression facilities. All of the gathered gas ultimately is compressed and delivered to the processing plant. After processing, the residue gas is delivered to a third-party pipeline and natural gas liquids are sold to a single customer.  We also own a gathering system in the Woodford Shale play in the Arkoma Basin of southeastern Oklahoma, and we own the Grimes gathering system, which is located in Roger Mills and Beckham counties in western Oklahoma.

·        Other Southwest. We own a number of 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. We gather a significant portion of the gas produced from fields adjacent to our gathering systems. In many areas we are the primary gatherer, and in some of the areas served by our smaller systems we are the sole gatherer. We also own four lateral pipelines in Texas and New Mexico.

Northeast Business Unit

·        Appalachia. We are the largest 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. Our Appalachian assets include the Kenova, Boldman, Maytown, Cobb and Kermit natural gas processing plants, an NGL pipeline, an NGL fractionation plant and two caverns for storing propane.

·        Michigan. We own a common carrier crude oil gathering pipeline in Michigan. We refer to this system as the Michigan Crude Pipeline. We also own a natural gas gathering system and the Fisk processing plant in Manistee County, Michigan.

Gulf Coast Business Unit

·        Javelina. On November 1, 2005, we acquired 100% of the equity interests in Javelina Company, Javelina Pipeline Company and Javelina Land Company, L.L.C., which were owned 40%, 40% and 20%, respectively, by subsidiaries of El Paso Corporation, Kerr-McGee Corporation, and Valero Energy Corporation. The Javelina entities own and operate a natural gas processing facility in Corpus Christi, Texas, which treats and processes off-gas from six local refineries. The facility was constructed to recover hydrogen and up to 28,000 barrels per day of NGLs, including olefins (ethylene and propylene), ethane, propane, mixed butane and pentanes. The facility processes approximately 125 to 130 MMcf/d of inlet gas and produces approximately 25,400 Bbl/d of NGLs.

We own a 50% non-operating membership interest in Starfish, whose assets are located in the Gulf of Mexico and southwestern Louisiana. The Starfish interest is part of a joint venture with Enbridge Offshore Pipelines LLC, which is accounted for using the equity method; the financial results for Starfish are included in equity from earnings from unconsolidated affiliates and are not included in the Gulf Coast Business Unit results.

The following summarizes the percentage of our revenue and net operating margin (a non-GAAP financial measure, see Item1.Business — Our Contracts) generated by our assets, by geographic region, for the year ended December 31, 2006:

 

 

East Texas

 

Oklahoma

 

Other 
Southwest

 

Appalachia

 

Michigan

 

Gulf Coast

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenue

 

21

%

36

%

16

%

13

%

2

%

12

%

100

%

Net operating margin

 

33

%

15

%

7

%

13

%

4

%

28

%

100

%

 

Regulatory Matters

 Our operations are subject to extensive regulations. The failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on our operations increases our cost of doing business and, consequently, affects our profitability. However, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors. Due to the myriad of complex federal, state, provincial and local regulations that may affect us, directly or indirectly, reliance on the following discussion of certain laws and regulations should not be considered an exhaustive review of all regulatory considerations affecting our operations.

13




Pipeline and Gathering Regulation

Interstate Gas Pipelines.     Our natural gas pipeline operations are subject to federal, state and local regulatory authorities. Specifically, our Hobbs, New Mexico natural gas pipeline and our Michigan crude oil pipeline facilities and related assets are subject to regulation by the FERC.  Federal regulation extends to such matters as:

                 rate structures;

                 rates of return on equity;

                 recovery of costs;

                 the services that our regulated assets are permitted to perform;

                 the acquisition, construction and disposition of assets; and

                 to an extent, the level of competition in that regulated industry.

Under the Natural Gas Act, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Its authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services, and various other matters. Natural gas companies may not charge rates that have been determined not to be just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service. The rates and terms and conditions for our service will be found in FERC-approved tariffs. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. We cannot assure you that FERC will continue to pursue its approach of procompetitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity, and transportation facilities. Any successful complaint or protest against our rates, or loss of market-based rate authority by FERC could have an adverse impact on our revenues associated with providing interstate gas transportation services.

Should our FERC regulated pipeline operations fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1,000,000 per day for each violation.

Gathering and Intrastate Pipeline Regulation.   Section 1(b) of the Natural Gas Act exempts natural gas gathering facilities from the jurisdiction of FERC.  We own a number of facilities that we believe meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In the states in which we operate, regulation of gathering facilities and intrastate pipeline facilities generally includes various safety, environmental and, in some circumstances, open access, nondiscriminatory take requirement and complaint-based rate regulation. For example, some of our natural gas gathering facilities are subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling.  Similarly, common purchaser statutes generally require gatherers to purchase gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply.  These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a less stringent approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Our intrastate gas pipeline facilities are subject to various state laws and regulation that affect the rates we charge and terms of service. Although state regulation is typically less onerous than at FERC, state regulation typically requires

14




pipelines to charge just and reasonable rates and to provide service on a non-discriminatory basis. The rates and service of an intrastate pipeline generally are subject to challenge by complaint.

Our Appalachian pipeline carries NGLs across state lines. The primary shipper on the pipeline is MarkWest Hydrocarbon, which has entered into agreements with us providing for a fixed transportation charge for the term of the agreements. They expire on December 31, 2015. We are the only other shipper on the pipeline. We neither operate our Appalachian pipeline as a common carrier, nor hold it 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. The likelihood of other entities seeking to utilize our Appalachian pipeline is remote, so it should not be subject to regulation by the FERC in the future. We cannot provide assurance, however, that FERC will not at some point determine that such transportation is within its jurisdiction, or that such an assertion would not adversely affect our results of operations. In such a case, we would be required to file a tariff with FERC and provide a cost justification for the transportation charge. Regardless of any FERC action, however, MarkWest Hydrocarbon has agreed to not challenge the status of our Appalachian pipeline or the transportation charge during the term of our agreements.

Crude Common Carrier Pipeline Operations.     Our Michigan Crude Pipeline is a crude oil pipeline that is a common carrier and subject to regulation by the FERC under the October 1, 1977 version of the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992 (“EPAct 1992”). The ICA and its implementing regulations give the FERC authority to regulate the rates charged for service on the interstate common carrier liquids pipelines and generally require the rates and practices of interstate liquids pipelines to be just and reasonable and nondiscriminatory. The ICA also requires tariffs to be maintained on file with the FERC that set forth the rates it charges for providing transportation services on its interstate common carrier liquids pipelines as well as the rules and regulations governing these services. EPAct 1992 and its implementing regulations allow interstate common carrier oil pipelines to annually index their rates up to a prescribed ceiling level. In addition, the FERC retains cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach.

With respect to our Michigan Crude Pipeline, we filed a tariff establishing a cost-of-service rate structure to be effective starting January 1, 2006. Two shippers and a producer protested the filing. On December 29, 2005, the Commission accepted our filing and permitted the rates to go into effect subject to refund. The Commission established hearing procedures but first referred the parties to settlement discussions before a FERC-appointed settlement judge. On January 31, 2006, the parties submitted a settlement to the FERC that re-established the pre-existing Michigan intrastate pipeline rates with minor modifications and place a moratorium on rate changes or challenges for a three-year period, with limited exceptions. On March 7, 2006, the FERC settlement judge certified the settlement to the FERC as uncontested and fair, reasonable, and in the public interest.

Environmental Matters

General.

Our processing and fractionation plants, pipelines, and associated facilities are subject to multiple environmental obligations and potential liabilities under a variety of stringent and comprehensive federal, state and local laws and regulations. Such laws and regulations affect many aspects of our present and future operations, and generally require us 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, and solid and hazardous waste management. Failure to comply with these stringent and comprehensive requirements may expose us to fines, penalties and/or interruptions in our operations that could influence our results of operations.

We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations, and that the cost of continued compliance with such laws and regulations will not have a material adverse effect on our results of operations or financial condition. We cannot ensure, however, that existing environmental laws and regulations will not be revised or that new laws and regulations will not be adopted or become applicable to us. The clear trend in environmental law 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 we currently anticipate. Revised or additional environmental requirements that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have material adverse effect on our business, financial condition, results of operations and cash flow.

Hazardous Substance and Waste.

15




To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control environmental pollution of the environment. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, as amended, or CERCLA, also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to a release of “hazardous substance” into the environment. These persons include the owner or operator of a site where a release occurred, both current and past, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, liability is imposed upon persons under a strict liability theory, that is without regard to intent or fault, and these persons may be subject to joint and several liability for the costs of removing or remediating hazardous substances that have been released into the environment, for restoration and damages to natural resources, and for the costs of certain health studies. Additionally, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. While we generate materials in the course of our operations that are regulated as hazardous substances, we have not received any notification that we may be potentially responsible for cleanup costs under CERCLA. We also may incur liability under the Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes, which impose requirements relating to the handling and disposal of hazardous wastes and nonhazardous solid wastes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes. However, it is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements.

We currently own or lease, and have in the past owned or leased, properties that have been used over the years for natural gas gathering and processing, for NGL fractionation, transportation and storage and for the storage and gathering and transportation of crude oil. Although solid waste disposal practices within the NGL industry and other oil and natural gas related industries have improved over the years, a possibility exists that hydrocarbons and other solid wastes or hazardous wastes may have been disposed of on or under various properties owned or leased by us during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, we 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. We do not believe that there presently exists significant surface and subsurface contamination of our properties by hydrocarbons or other solid wastes for which we are currently responsible.

Ongoing Remediation and Indemnification from a Third Party.

The previous owner/operator of our Boldman and Cobb facilities has been, or is currently involved in, investigatory or remedial activities with respect to the real property underlying these facilities. These arise out of a September 1994 “Administrative Order by Consent for Removal Actions” with EPA Regions II, III, IV, and V; and an “Agreed Order” entered into with the Kentucky Natural Resources and Environmental Protection Cabinet in October 1994. The previous owner/operator has accepted sole liability and responsibility for, and indemnifies 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 lease or purchase of the real property. In addition, the previous owner/operator has agreed to perform all the required response actions at its expense in a manner that minimizes interference with MarkWest Hydrocarbon’s use of the properties. On May 24, 2002, MarkWest Hydrocarbon assigned to us 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.

Air.

The Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including processing plants and compressor stations. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. While we may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing other air emission-related issues, we do not believe that such requirements will have a material adverse affect on our operations.

Water.

16




The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” and analogous state laws impose restrictions and controls on the discharge of pollutants into federal and state waters. Such discharges are prohibited, except in accord with the terms of a permit issued by the EPA or the state. Any unpermitted release of pollutants, including natural gas liquids or condensates, could result in penalties, as well as significant remedial obligations. We believe that we are in substantial compliance with the Clean Water Act.

Pipeline Safety Regulations

Our pipelines are subject to regulation by the U.S. Department of Transportation (“DOT”) under the Pipeline Safety Act of 1992, as amended, and the newly enacted Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, (collectively the “Pipeline Safety Acts”), and the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”), as amended; and the Pipeline Integrity Management (“PIM”) in High Consequence Areas (Gas Transmission Pipelines) amendment to 49 CFR Part 192, effective February 14, 2004, relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The Pipeline Safety Act of 1992 required the Research and Special Programs Administration of the DOT to consider environmental impacts, as well as its traditional public safety mandate, when developing pipeline safety regulations. The DOT’s pipeline operator qualification rules require minimum qualification requirements for personnel performing operations and maintenance activities on hazardous liquid pipelines. 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 HLPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. The Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) amendment to 49 CFR Part 192 (PIM) requires operators of gas transmission pipelines to ensure the integrity of their pipelines through hydrostatic pressure testing, the use of in-line inspection tools or through risk-based direct assessment techniques. The Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 expands the DOT’s authority and calls for additional studies and additional regulations to be promulgated in many areas, including integrity management, corrosion control, incident reporting, inspection and enforcement orders.  While we believe that our pipeline operations are in substantial compliance with applicable requirements, due to the possibility of new or amended laws and regulations, or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with the requirements will not have a material adverse effect on our results of operations or financial position.

Our affiliate MarkWest Energy Appalachia, L.L.C. (“MEA”) operates the Appalachia Liquids Pipeline System (“ALPS”) pipeline to transport NGLs from our Maytown gas processing plant to our Siloam fractionator. This pipeline is owned by Equitable Production Company, and is leased and operated by MEA.  On November 8, 2004, a leak and an ensuing fire occurred on the line in the area of Ivel, Kentucky, and the line was taken out of service pending investigation and repair.  In accordance with an Office of Pipeline Safety (“OPS”) Corrective Action Order, MEA successfully conducted a hydrostatic test of the affected portion of the ALPS pipeline in 2005 and OPS authorized a partial return to service of the affected pipeline in October 2005.  As part of its ongoing operation of the ALPS pipeline, MEA continued to perform pipeline integrity assessments and implement an in-line inspection program on the ALPS pipeline.  Preliminary data from a four mile section of its in-line inspection program identified areas for investigation and corrective action.  In November 2006, MEA temporarily idled the line while additional assessment and appropriate investigation was undertaken to address these concerns.  In late January 2007, MEA received the completed report from its in-line inspection operator and consultant.  This report indicated areas of significant external corrosion or other defects in the four mile section of pipeline in which the in-line inspection was conducted.  The assessment of this completed report, coupled with other information MEA has gathered, will continue to be reviewed and MEA will work with Equitable to determine what the most appropriate corrective action may be.  In the interim, the pipeline will be maintained in idle status.  MEA is trucking the NGLs produced from our Maytown plant to the Siloam fractionation facility while MEA is maintaining the pipeline in idle status, and as a result, operations have not been interrupted.  The additional transportation costs associated with the trucking are not expected to have material adverse effect on our results of operations or financial positions.

Employee Safety

The workplaces associated with the processing and storage facilities and the pipelines we operate are also subject to oversight from the federal Occupational Safety and Health Administration, (“OSHA”), as well as comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard-communication standard requires that we maintain information about hazardous materials used or produced in 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, resulting in increased compliance expenditures. While these expenditures cannot be accurately estimated at this time, we do not expect such

17




expenditures will have a material adverse effect on our results of operations.

Employees

We do not have any employees. Our general partner, or its affiliates, employs approximately 318 individuals to operate our facilities and provide general and administrative services, as our agents. The Paper, Allied Industrial, Chemical and Energy Workers International Union Local 5-372 represents 14 employees at our Siloam fractionation facility in South Shore, Kentucky. The collective bargaining agreement with this union was renewed on July 11, 2005, for a term of three years. The agreement covers only hourly, non-supervisory employees. We consider labor relations to be satisfactory at this time.

Available Information

Our principal executive office is located at 1515 Arapahoe Street, Tower 2, Suite 700, Denver, Colorado 80202-2126. Our telephone number is 303-925-9200. Our common units trade on the American Stock Exchange under the symbol “MWE.”  You can find more information about us at our Internet website, 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 reasonably practicable after we electronically file or furnish such material with the Securities & Exchange Commission.

18




ITEM 1A.               Risk Factors

In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider the following factors when evaluating MarkWest Energy Partners.

Risks Inherent in Our Business

We may not have sufficient cash after the establishment of cash reserves and payment of our general partner’s fees and expenses to enable us to pay distributions at the current level.

The amount of cash we can distribute on our units depends principally on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

·        the fees we charge and the margins we realize for our services and sales;

·        the prices of, level of production of, and demand for natural gas and NGLs;

·        the volumes of natural gas we gather, process and transport;

·        the level of our operating costs, including reimbursement of fees and expenses of our general partner; and

·        prevailing economic conditions.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

·        our debt service requirements;

·        fluctuations in our working capital needs;

·        our ability to borrow funds and access capital markets;

·        restrictions contained in our debt agreements;

·        the level of capital expenditures we make, including capital expenditures incurred in connection with our enhancement projects;

·        the cost of acquisitions, if any; and

·        the amount of cash reserves established by our general partner.

Unitholders should be aware that the amount of cash we have available for distribution depends primarily on our cash flow and not solely on profitability, which is affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

If we do not make acquisitions on economically acceptable terms, our future growth will be limited.

Our ability to grow depends in part on our ability to make acquisitions that result in an increase in the cash generated from operations per unit. If we are unable to make these accretive acquisitions because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms, or (3) outbid by competitors, then our future growth and ability to increase distributions will be limited.

If we are unable to successfully integrate our future acquisitions, our future financial performance may suffer.

Our future growth will depend in part on our ability to integrate our future acquisitions. We cannot guarantee that we will successfully integrate any acquisitions into our existing operations, or that we will achieve the desired profitability and anticipated results from such acquisitions. Failure to achieve such planned results could adversely affect our financial condition and results of operations.

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

·        operating a significantly larger combined organization and integrating additional midstream operations into our existing operations;

19




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

·        the loss of customers or key employees from the acquired businesses;

·        the diversion of management’s attention from other existing business concerns;

·        the failure to realize expected synergies and cost savings;

·        coordinating geographically disparate organizations, systems and facilities;

·        integrating personnel from diverse business backgrounds and organizational cultures; and

·        consolidating corporate and administrative functions.

Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Following an acquisition, we may discover previously unknown liabilities including those under the same stringent environmental laws and regulations relating to releases of pollutants into the environment and environmental protection as applicable to our existing plants, pipelines and facilities. If so, our operation of these new assets could cause us to incur increased costs to address these liabilities or to attain or maintain compliance with such requirements. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

Our acquisition strategy is based in part on our expectation of ongoing divestitures of assets within the midstream petroleum and natural gas industry. A material decrease in such divestitures could limit our opportunities for future acquisitions, and could adversely affect our operations and cash flows available for distribution to our unitholders.

Growing our business by constructing new pipelines and processing and treating facilities subjects us to construction risks and risks that natural gas supplies will not be available upon completion of the facilities.

One of the ways we intend to grow our business is through the construction of additions to our existing gathering systems and construction of new gathering, processing and treating facilities. The construction of gathering, processing and treating facilities requires the expenditure of significant amounts of capital, which may exceed our expectations, and involves numerous regulatory, environmental, political and legal uncertainties. If we undertake these projects, we may not be able to complete them on schedule or at all or at the budgeted cost. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until after completion of the project.

Furthermore, we may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. We may also rely on estimates of proved reserves in our decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new facilities may not be able to attract enough natural gas to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

Our substantial debt and other financial obligations could impair our financial condition, results of operations and cash flows, and our ability to fulfill our debt obligations.

We have substantial indebtedness and other financial obligations. Subject to the restrictions governing our indebtedness and other financial obligations, and the indenture governing our outstanding notes, we may incur significant additional indebtedness and other financial obligations.

Our substantial indebtedness and other financial obligations could have important consequences. For example, they could:

·        make it more difficult for us to satisfy our obligations with respect to our existing debt;

·        impair our ability to obtain additional financings in the future for working capital, capital expenditures, acquisitions, or general partnership and other purposes;

·        have a material adverse effect on us if we fail to comply with financial and restrictive covenants in our debt agreements, and an event of default occurs as a result of that failure that is not cured or waived;

20




·        require us to dedicate a substantial portion of our cash flow to payments on our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, distributions and other general partnership requirements;

·        limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

·        place us at a competitive disadvantage compared to our competitors that have proportionately less debt.

Furthermore, these consequences could limit our ability, and the ability of our subsidiaries, to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general, conduct operations or otherwise take advantage of business opportunities that may arise. Our existing credit facility contains covenants requiring us to maintain specified financial ratios and satisfy other financial conditions, which may limit our ability to grant liens on our assets, make or own certain investments, enter into any swap contracts other than in the ordinary course of business, merge, consolidate, or sell assets, incur indebtedness senior to the credit facility, make distributions on equity investments, and declare or make, directly or indirectly, any distribution on our common units. Our obligations under the credit facility are secured by substantially all of our assets and guaranteed by us and all of our subsidiaries, other than our operating company, which is the borrower under the credit facility. In particular, we may be unable to meet those ratios and conditions. Any future breach of any of these covenants or our failure to meet any of these ratios or conditions could result in a default under the terms of our credit facility, which could result in acceleration of our debt and other financial obligations. If we were unable to repay those amounts, the lenders could initiate a bankruptcy or liquidation proceeding, or proceed against the collateral.

A significant decrease in natural gas production in our areas of operation would reduce our ability to make distributions to our unitholders.

Our gathering systems are connected to natural gas reserves and wells, from which the production will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our gathering systems and the utilization rate at our processing plants and our treating and fractionation facilities, we must continually obtain new natural gas supplies. Our ability to obtain additional sources of natural gas depends in part on the level of successful drilling activity near our gathering systems.

We have no control over the level of drilling activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations and the availability and cost of capital. Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. Natural gas prices reached historic highs in 2005 and early 2006 but have declined in the second half of 2006. These recent declines in natural gas prices are beginning to have a negative impact on production activity, and if sustained, could lead to a material decrease in such production activity and ultimately to exploration activity.

Because of these factors, even if new natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. If we are not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells due to reductions in drilling activity or competition, throughput on our pipelines and the utilization rates of our treating and processing facilities would decline, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders.

We depend on third parties for the natural gas and refinery off-gas we process, and the NGLs we fractionate at our facilities, and a reduction in these quantities could reduce our revenues and cash flow.

Although we obtain our supply of natural gas, refinery off-gas and NGLs from numerous third-party producers, a significant portion comes from a limited number of key producers/suppliers who are committed to us under processing contracts. According to these contracts or other supply arrangements, however, the producers are under no obligation to deliver a specific quantity of natural gas or NGLs to our facilities. If these key suppliers, or a significant number of other producers, were to decrease the supply of natural gas or NGLs to our systems and facilities for any reason, we could experience difficulty in replacing those lost volumes. Because our operating costs are primarily fixed, a reduction in the volumes of natural gas or NGLs delivered to us would result not only in a reduction of revenues, but also a decline in net income and cash flow of similar magnitude.

 

21




We derive a significant portion of our revenues from our gas processing, transportation, fractionation and storage agreements with MarkWest Hydrocarbon, and its failure to satisfy its payment or other obligations under these agreements could reduce our revenues and cash flow.

MarkWest Hydrocarbon accounts for a significant portion of our revenues and net operating margin. These revenues and margins are generated by the volumes of natural gas contractually committed to MarkWest Hydrocarbon by certain producers in the Appalachian region, as well as the fees generated from processing, transportation, fractionation and storage services provided to MarkWest Hydrocarbon. We expect to derive a significant portion of our revenues and net operating margin from the services we provide under our contracts with MarkWest Hydrocarbon for the foreseeable future. Any default or nonperformance by MarkWest Hydrocarbon could significantly reduce our revenues and cash flows. Thus, any factor or event adversely affecting MarkWest Hydrocarbon’s business, creditworthiness or its ability to perform under its contracts with us, or its other contracts related to our business, could also adversely affect us.

The fees charged to third parties under our gathering, processing, transmission, transportation, fractionation and storage agreements may not escalate sufficiently to cover increases in costs. The agreements may not be renewed or may be suspended in some circumstances.

Our costs may increase at a rate greater than the fees we charge to third parties. Furthermore, third parties may not renew their contracts with us. Additionally, some third parties’ obligations under their agreements with us may be permanently or temporarily reduced due to certain events, some of which are beyond our control, including force majeure events wherein the supply of either natural gas, NGLs or crude oil are curtailed or cut off. Force majeure events include (but are not limited to): revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of equipment or our facilities or facilities of third parties. If the escalation of fees is insufficient to cover increased costs, if third parties do not renew or extend their contracts with us or if any third party suspends or terminates its contracts with us, our financial results would suffer.

We are exposed to the credit risks of our key customers, and any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us.

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

The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including competition from other gatherers, processors, pipelines, fractionators, and the price of, and demand for, natural gas, NGLs and crude oil in the markets we serve. Our competitors include large oil, natural gas, refining and petrochemical companies, some of which have greater financial resources, more numerous or greater capacity pipelines, processing and other facilities, and greater access to natural gas and NGL supplies than we do. Additionally, our customers that gather gas through facilities that are not otherwise dedicated to us may develop their own processing and fractionation facilities in lieu of using our services. Certain of our competitors may also have advantages in competing for acquisitions, or other new business opportunities, because of their financial resources and synergies in operations.

As a consequence of the increase in competition in the industry, and the volatility of natural gas prices, end-users and utilities are reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternative fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis of price. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could affect our profitability. For more information regarding our competition, please read “Business — Industry Overview” in Item 1of Part 1 of this report.

Our profitability is affected by the volatility of NGL product and natural gas prices.

We are subject to significant risks associated with frequent and often substantial fluctuations in commodity prices. In the past, the prices of natural gas and NGLs have been volatile, and we expect this volatility to continue. The NYMEX daily

22




settlement price of natural gas for the prompt month contract in 2005 ranged from a high of $15.38 per MMBtu to a low of $5.79 per MMBtu in 2005. In 2006, the same index ranged from a high of $12.48 per MMBtu to a low of $4.20 per MMBtu. A composite of the weighted monthly average NGLs price at our Appalachian facilities based on our average NGLs composition in 2005 ranged from a high of approximately $1.25 per gallon to a low of $0.83 per gallon. In 2006, the same composite ranged from approximately $1.27 per gallon to approximately $1.03 per gallon. The markets and prices for natural gas and NGLs depend upon factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:

·              the level of domestic oil, natural gas and NGL production;

·              demand for natural gas and NGL products in localized markets;

·              imports of crude oil, natural gas and NGLs;

·              seasonality;

·              the condition of the U.S. economy;

·              political conditions in other oil-producing and natural gas-producing countries; and

·              domestic government regulation, legislation and policies.

Our net operating margins under various types of commodity-based contracts are directly affected by changes in NGL product prices and natural gas prices, thus are more sensitive to volatility in commodity prices than our fee-based contracts. Additionally, our purchase and resale of gas in the ordinary course of business exposes us to significant risk of volatility in gas prices due to the potential difference in the time of the purchases and sales, and the potential existence of a difference in the gas price associated with each transaction.

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

Our operations expose us to fluctuations in commodity prices. We utilize derivative financial instruments related to the future price of crude oil, natural gas and certain NGLs with the intent of reducing volatility in our cash flows due to fluctuations in commodity prices.

The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. We have a policy to enter into derivative transactions related to only a portion of the volume of our expected production or fuel requirements and, as a result, we will continue to have direct commodity price exposure to the unhedged portion. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — and Item 7A. Quantitative and Qualitative Disclosures about Market Risk” as set forth in this report. Our actual future production or fuel requirements may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our hedging activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our hedging policies and procedures are not properly followed. It is possible that the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. For further information about our risk management policies and procedures, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation — and Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk and Our Risk Management Policy” as set forth in this report.

We have found a material weakness in our internal controls that requires remediation and concluded, pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, that our internal controls over financial reporting at December 31, 2006, were not effective.

As we discuss in our Management’s Report on Internal Control over Financial Reporting in Part II, Item 9A, “Controls and Procedures,” of this Form 10-K, we have discovered deficiencies, including a material weakness, in our internal controls over financial reporting as of December 31, 2006. In particular, we identified, and Deloitte & Touche LLP’s audit report on management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting as of December 31, 2006 confirmed the presence of, the following material weakness:

·              Accounting for derivative financial instruments.

At December 31, 2006, management identified and Deloitte and Touche LLP confirmed in their opinion on internal controls, the existence of a continuing material weakness related to accounting for derivatives. Specifically, there was an issue related to our prior year material weakness that had not been fully remediated at year-end. As of year-end, management did not have a process for monitoring existing contracts in response to changes in SFAS No. 133 and had not conducted a comprehensive review of substantially all contracts entered into prior to 2006 for the purpose of ensuring that determinations about derivative implications and SFAS No. 133 issues were made appropriately and remained appropriate. A comprehensive review was deemed necessary because the determinations related to these historical contracts were originally made in an environment where material weaknesses are known to have existed. Inappropriate conclusions could lead to errors, the most significant of which would likely be in recognition of unrealized gains or losses.

23




In addition, we and Deloitte & Touche LLP identified material weaknesses in our control environment and our risk management and accounting for derivative financial instruments as of December 31, 2005. Additionally, we and KPMG LLP, our independent registered public accounting firm at that time, identified material weaknesses in our internal control over financial reporting as of December 31, 2004.

The full impact of our efforts to remediate the identified material weaknesses had not been realized as of December 31, 2006 and may not be sufficient to maintain effective internal controls in the future. We may not be able to implement and maintain adequate controls over our financial processes and reporting, which may require us to restate our financial statements in the future. In addition, we may discover additional past, ongoing or future material weaknesses or significant deficiencies in our financial reporting system in the future. Any failure to implement new controls, or difficulty encountered in their implementation, could cause us to fail to meet our reporting obligations or result in material misstatements in our financial statements. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could result in a lower trading price of our common units.

Transportation on certain of our pipelines may be subject to federal or state rate and service regulation, and the imposition and/or cost of compliance with such regulation could adversely affect our profitability.

Some of our gas, liquids and crude oil transmission operations are subject to rate and service regulations under FERC or various state regulatory bodies, depending upon jurisdiction. FERC generally regulates the transportation of natural gas and oil in interstate commerce, and FERC’s regulatory authority includes: facilities construction, acquisition, extension or abandonment of services or facilities; accounts and records; and depreciation and amortization policies. Intrastate natural gas pipeline operations and transportation on proprietary natural gas or petroleum products pipelines are generally not subject to regulation by FERC, and the Natural Gas Act (“NGA”) specifically exempts some gathering systems. Yet such operations may still be subject to regulation by various state agencies. The applicable statutes and regulations generally require that our 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. We cannot assure unitholders that FERC will not at some point determine that such gathering and transportation services are within its jurisdiction, and regulate such services. FERC rate cases can involve complex and expensive proceedings. For more information regarding regulatory matters that could affect our business, please read “Item 1. Business — Regulatory Matters” as set forth in this report.

If we are unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, then we may be unable to fully execute our growth strategy and our cash flows could be adversely affected.

The construction of additions to our existing gathering assets may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of obtaining new rights-of-way or renewing existing rights-of-way increases, then our cash flows could be adversely affected.

We are indemnified for liabilities arising from an ongoing remediation of property on which our facilities are located and our results of operation and our ability to make payments of principal and interest on our debt and distributions to our unitholders could be adversely affected if the indemnifying party fails to perform its indemnification obligation.

Columbia Gas is the previous or current owner of the property on which our Kenova, Boldman, Cobb and Kermit facilities are located and is the previous operator of our Boldman and Cobb facilities. Columbia Gas has been or is currently involved in investigatory or remedial activities with respect to the real property underlying the Boldman and Cobb facilities pursuant to an “Administrative Order by Consent for Removal Actions” entered into by Columbia Gas and the U.S. Environmental Protection Agency and, in the case of the Boldman facility, an “Agreed Order” with the Kentucky Natural Resources and Environmental Protection Cabinet.

Columbia Gas has agreed to retain sole liability and responsibility for, and to indemnify MarkWest Hydrocarbon against, any environmental liabilities associated with these regulatory orders or the real property underlying these facilities to the extent such liabilities arose prior to the effective date of the agreements pursuant to which such properties were acquired or leased from Columbia Gas. At the closing of our initial public offering, MarkWest Hydrocarbon assigned us the benefit of its indemnity from Columbia Gas with respect to the Cobb, Boldman and Kermit facilities. While we are not a party to the agreement under which Columbia Gas agreed to indemnify MarkWest Hydrocarbon with respect to the Kenova facility, MarkWest Hydrocarbon has agreed to provide to us the benefit of its indemnity, as well as any other third party environmental indemnity of which it is a beneficiary. MarkWest Hydrocarbon has also agreed to provide us an additional environmental indemnity pursuant to the terms of the Omnibus Agreement. Our results of operation and our ability to make cash distributions to our unitholders could be adversely affected if in the future either Columbia Gas or MarkWest Hydrocarbon fails to perform under the indemnification provisions of which we are the beneficiary.

24




Our business is subject to federal, state and local laws and regulations with respect to environmental, safety and other regulatory matters, and the violation of, or the cost of compliance with, such laws and regulations could adversely affect our profitability.

Numerous governmental agencies enforce comprehensive and stringent laws and regulations on a wide range of environmental, safety and other regulatory matters. We could be adversely affected by increased costs due to stricter pollution-control requirements or liabilities resulting from non-compliance with operating or other regulatory permits. New environmental laws and regulations might adversely influence our products and activities. Federal, state and local agencies also could impose additional safety requirements, any of which could affect our profitability. In addition, we face the risk of accidental releases or spills associated with our operations. These could result in material costs and liabilities, including those relating to claims for damages to property and persons. Our failure to comply with environmental or safety-related laws and regulations could result in administrative, civil and criminal penalties, the imposition of investigatory and remedial obligations and even injunctions that restrict or prohibit our operations. For more information regarding the environmental, safety and other regulatory matters that could affect our business, please read “Item 1. Business — Regulatory Matters,” “Item 1. Business — Environmental Matters,” and “Item 1. Business — Pipeline Safety Regulations” each as set forth in this report.

The amount of gas we process, gather and transmit, or the crude oil we gather and transport, may be reduced if the pipelines to which we deliver the natural gas or crude oil cannot, or will not, accept the gas or crude oil.

All of the natural gas we process, gather and transmit is delivered into pipelines for further delivery to end-users. If these pipelines cannot, or will not, accept delivery of the gas due to downstream constraints on the pipeline, we will be forced to limit or stop the flow of gas through our pipelines and processing systems. In addition, interruption of pipeline service upstream of our processing facilities would likewise limit or stop flow through our processing facilities. Likewise, if the pipelines into which we deliver crude oil are interrupted, we will be limited in, or prevented from conducting, our crude oil transportation operations. Any number of factors beyond our control could cause such interruptions or constraints on pipeline service, including necessary and scheduled maintenance, or unexpected damage to the pipeline. Because our revenues and net operating margins depend upon (1) the volumes of natural gas we process, gather and transmit, (2) the throughput of NGLs through our transportation, fractionation and storage facilities and (3) the volume of crude oil we gather and transport, any reduction of volumes could result in a material reduction in our net operating margin.

Our business would be adversely affected if operations at any of our facilities were interrupted.

Our operations depend upon the infrastructure that we have developed, including processing and fractionation plants, storage facilities, and various means of transportation. Any significant interruption at these facilities or pipelines, or our inability to transmit natural gas or NGLs, or transport crude oil to or from these facilities or pipelines for any reason, would adversely affect our results of operations. Operations at our facilities could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within our control, such as:

·                                          unscheduled turnarounds or catastrophic events at our physical plants;

·                                          labor difficulties that result in a work stoppage or slowdown; and

·                                          a disruption in the supply of crude oil to our crude oil pipeline, natural gas to our processing plants or gathering pipelines, or a disruption in the supply of NGLs to our transportation pipeline and fractionation facility.

Due to our lack of asset diversification, adverse developments in our gathering, processing, transportation, transmission, fractionation and storage businesses would reduce our ability to make distributions to our unitholders.

We rely exclusively on the revenues generated from our gathering, processing, transportation, transmission, fractionation and storage businesses. An adverse development in one of these businesses would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.

As a result of damage caused by Hurricanes Katrina and Rita in the Gulf of Mexico and Gulf Coast regions in 2005, insurance costs related to oil and gas assets in these regions have increased significantly. We may be unable to obtain insurance on our interest in Starfish at rates we consider reasonable.

During 2005, Hurricanes Katrina and Rita caused severe and widespread damage to oil and gas assets in the Gulf of Mexico and Gulf Coast regions. The loss to both offshore and onshore assets resulting from the hurricanes has led to substantial insurance claims within the oil and gas industry. Along with other industry participants, insurance costs have increased within this region as a result of these developments. We have renewed our insurance coverage relating to Starfish and mitigated a portion of the cost increase by reducing our coverage and broadening the self-insurance element of our overall coverage. In the future, we may be unable to obtain adequate insurance on our interest in Starfish at rates we consider reasonable and as a result may experience losses that are not insured or that exceed the maximum limits under our insurance policies. If a significant negative event that is not fully insured occurs with respect to Starfish, it could materially and adversely affect our financial condition and results of operations.

A shortage of skilled labor may make it difficult for us to maintain labor productivity at competitive costs and could adversely affect our profitability.

Our operations require skilled and experienced laborers with proficiency in multiple tasks. In recent years, a shortage of workers trained in various skills associated with the midstream energy business has caused us to conduct certain operations without full staff, which decreases our productivity and increases our costs. This shortage of trained workers is the result of the previous generation’s experienced workers reaching the age for retirement, combined with the difficulty of attracting new laborers to the midstream energy industry. Thus, this shortage of skilled labor could continue over an extended

25




period. If the shortage of experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our products and services, which could adversely affect our profitability.

Our business may suffer if any of our key senior executives discontinues employment with us or if we are unable to recruit and retain highly skilled accounting and finance staff.

Our future success depends to a large extent on the services of our key corporate employees. Our business depends on our continuing ability to recruit, train and retain highly qualified employees, particularly accounting, finance and other key back-office and mid-office personnel. The competition for these employees is intense, and the loss of these employees could harm our business. Further, our ability to successfully integrate acquired companies depends in part on our ability to retain key management and existing employees at the time of the acquisition.

Risks Related to Our Partnership Structure

Cost reimbursements and fees due our general partner may be substantial and reduce our cash available for distribution to unitholders.

Prior to making any distribution on the common units, we reimburse our general partner for all expenses it incurs on our behalf. Our general partner has sole discretion in determining the amount of these expenses. Our general partner and its affiliates also may provide us other services for which we will be charged fees.

MarkWest Hydrocarbon and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to the detriment of the unitholders.

MarkWest Hydrocarbon and its affiliates own and control our general partner. MarkWest Hydrocarbon and its affiliates also own a significant limited partner interest in us. A number of officers and employees of MarkWest Hydrocarbon and our general partner also own interests in us. Conflicts of interest may arise between MarkWest Hydrocarbon and its affiliates, including us and our general partner. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates including our general partner on the one hand, and us and our unitholders, on the other hand. These conflicts include, among others, the following situations:

·                                              Employees of MarkWest Hydrocarbon who provide services to us also devote significant time to the businesses of MarkWest Hydrocarbon and are compensated by MarkWest Hydrocarbon for these services.

·                                              Neither our Partnership Agreement nor any other agreement requires MarkWest Hydrocarbon to pursue a future business strategy that favors us or utilizes our assets for processing, transportation or fractionation services we provide. MarkWest Hydrocarbon’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of MarkWest Hydrocarbon.

·                                              Our general partner is allowed to take into account the interests of other parties, such as MarkWest Hydrocarbon, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.

·                                              Our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. As a result of purchasing units, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.

·                                              Our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including the processing, transportation and fractionation agreements with MarkWest Hydrocarbon.

·                                              Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

·                                              In some instances, our general partner may cause us to borrow funds in order to make cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units or to make incentive distributions or to hasten the conversion of subordinated units.

·                                              Our Partnership Agreement gives our general partner broad discretion in establishing financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution.

·                                              Our general partner may establish reserves for distribution on the subordinated units, but only if those reserves will not prevent us from distributing the full minimum quarterly distribution, plus any arrearages, on the common units for the following four quarters.

·                                              Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to our unitholders.

·                                              Our general partner determines which costs incurred by MarkWest Hydrocarbon and its affiliates are reimbursable by us.

·                                              Our Partnership Agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.

26




Unitholders have less ability to elect or remove management than holders of common stock in a corporation.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business, and therefore limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or its board of directors, and have no right to elect our general partner or its board of directors on an annual or other continuing basis.

MarkWest Hydrocarbon and its affiliates choose the board of directors of our general partner. The directors of our general partner also have a fiduciary duty to manage our general partner in a manner beneficial to its members, MarkWest Hydrocarbon and its affiliates.

Furthermore, if unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. First, our general partner generally may not be removed except upon the vote of the holders of at least 66 2/3% of the outstanding units voting together as a single class. Also, if our general partner is removed without cause during the subordination period, and units held by MarkWest Hydrocarbon and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units, and any existing arrearages on the common units will be extinguished. A removal under these circumstances would adversely affect the common unitholders by prematurely eliminating their contractual right to distributions over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud, gross negligence, or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholders’ dissatisfaction with its performance in managing our partnership will most likely result in the termination of the subordination period.

Unitholders’ voting rights are restricted by the Partnership Agreement provision. It states that any units held by a person who owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be voted on any matter. In addition, the Partnership Agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

These provisions may discourage a person or group from attempting to remove our general partner or otherwise change our management. As a result of these provisions, the price at which the common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

The control of our general partner may be transferred to a third party, and that party could replace our current management team, in each case without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger, or in a sale of all or substantially all of its assets, without the consent of the unitholders. Furthermore, there is no restriction in the Partnership Agreement on the ability of the owners of our general partner from transferring their ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices, and to control the decisions taken by the board of directors and officers.

Our general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.

Our Partnership Agreement requires our general partner to deduct from operating surplus cash reserves that, in its reasonable discretion, are necessary to fund our future operating expenditures. In addition, the Partnership Agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to our unitholders.

We do not have any employees and rely solely on employees of MarkWest Hydrocarbon and its affiliates who serve as our agents.

MarkWest Hydrocarbon and its affiliates conduct businesses and activities of their own in which we have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the employees who provide services to our general partner. If the employees of MarkWest Hydrocarbon and its affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer, and our ability to make distributions to our unitholders may be reduced.

We may issue additional common units without unitholder approval, which would dilute individual ownership interests.

During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 2,415,000 additional common units. Our general partner, without unitholder approval, may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, in several circumstances. These include:

27




·              the issuance of common units in connection with acquisitions or capital improvements that increase cash flow from operations per unit on a pro forma basis;

·                                              the conversion of subordinated units into common units;

·                                              the conversion of units of equal rank with the common units into common units under some circumstances;

·                                              the conversion of the general partner interest and the incentive distribution rights into common units as a result of the withdrawal of our general partner;

·                                              issuances of common units under our long-term incentive plan; or

·                                              issuances of common units to repay indebtedness, the cost of servicing which is greater than the distribution obligations associated with the units issued in connection with the debt’s retirement.

The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:

·                                              our unitholders’ proportionate ownership interest in us will decrease;

·                                              the amount of cash available for distribution on each unit may decrease;

·                                              because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

·                                              the relative voting strength of each previously outstanding unit may be diminished;

·                                              the market price of the common units may decline; and

·                                              the ratio of taxable income to distributions may increase.

After the end of the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our Partnership Agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time.

Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time more than 80% of the outstanding common units are owned by our general partner and its affiliates, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units.

Unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.

Under Delaware law, unitholders could be held liable for our obligations as a general partner if a court determined that the right or the exercise of the right by our unitholders as a group to remove or replace our general partner, to approve some amendments to the Partnership Agreement, or to take other action under our Partnership Agreement was considered participation in the “control” of our business.

Our general partner usually has unlimited liability for our obligations, such as its debts and environmental liabilities, except for those of our contractual obligations that are expressly made without recourse to our general partner.

In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by states. If the IRS were to treat us as a corporation or if we were to become subject to entity-level taxation for state tax purposes, then our cash flows would be substantially reduced.

The anticipated after-tax benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

28




If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash flows would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of the common units.

Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, our cash flows would be reduced. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be reduced to reflect the impact of that law on us.

ITEM 1B.               Unresolved Staff Comments

None.

 

29




ITEM 2.                    Properties

Gas Processing Facilities:

The locations, approximate capacity, and throughput of our gas-processing plants as of and for the year ended December 31, 2006, are as follows:

 

 

 

 

 

 

 

 

Year ended December 31, 2006

 

Facility

 

Location

 

Year of 
Initial
Construction

 

Design
Throughput
Capacity

 

Natural
Gas
Throughput

 

Utilization
of Design
Capacity

 

NGL
Throughput

 

 

 

 

 

 

 

(Mcf/d)

 

(Mcf/d)

 

 

 

(Gal/d)

 

East Texas:

 

 

 

 

 

 

 

 

 

 

 

 

 

East Texas processing plant

 

Panola County, TX

 

2005

 

200,000

 

161,300

 

81

%

NA

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oklahoma:

 

 

 

 

 

 

 

 

 

 

 

 

 

Arapaho processing plant

 

Custer County, OK

 

2000

 

90,000

 

87,500

 

97

%

217,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Appalachia:

 

 

 

 

 

 

 

 

 

 

 

 

 

Kenova processing plant (1)

 

Wayne County, WV

 

1996

 

160,000

 

133,000

 

83

%

NA

 

Boldman processing plant (1)

 

Pike County, KY

 

1991

 

70,000

 

41,000

 

59

%

NA

 

Maytown processing plant (1)

 

Floyd County, KY

 

2000

 

55,000

 

59,000

 

107

%

NA

 

Cobb processing plant

 

Kanawha County, WV

 

2005

 

25,000

 

28,000

 

112

%

NA

 

Kermit processing plant (1) (2)

 

Mingo County, WV

 

2001

 

32,000

 

NA

 

NA

 

NA

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Michigan:

 

 

 

 

 

 

 

 

 

 

 

 

 

Fisk processing plant

 

Manistee County, MI

 

1998

 

35,000

 

6,500

 

19

%

15,500

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gulf Coast:

 

 

 

 

 

 

 

 

 

 

 

 

 

Javelina processing plant (3)

 

Corpus Christi, TX

 

1989

 

142,000

 

124,000

 

87

%

1,098,483

 


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

(2)             The Kermit processing plant is operated by a third party solely to prevent liquids from condensing in the gathering and transmission pipelines upstream of MarkWest Energy Partners’ Kenova plant. The Partnership does not receive Kermit gas volume information but does receive all of the liquids produced at the Kermit facility.

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

Fractionation Facility:

The location, approximate capacity, and throughput of our fractionation facility as of and for the year ended December 31, 2006, is as follows:

 

 

 

 

 

 

 

 

Year ended
December 31, 2006

 

Pipeline

 

Location

 

Year of
Initial
Construction

 

Design
Throughput
Capacity (gal/d)

 

NGL
Throughput
(gal/day)

 

Utilization
of Design
Capacity

 

Appalachia:

 

 

 

 

 

 

 

 

 

 

 

Siloam Fractionation Plant

 

South Shore, KY

 

1957

 

600,000

 

455,000

 

76

%

 

Natural Gas Pipelines:

The name, approximate length in miles, geographical location, and throughput of our pipelines as of and for the year ended December 31, 2006, are as follows:

30




 

 

 

 

 

 

 

 

 

 

 

Year ended 
December 31, 2006

 

Facility

 

Location

 

Miles

 

Year of
Initial
Construction

 

Design
Throughput
Capacity

 

Natural
Gas
Throughput

 

Utilization
of Design
Capacity

 

 

 

 

 

 

 

 

 

(Mcf/d)

 

(Mcf/d)

 

 

 

East Texas:

 

 

 

 

 

 

 

 

 

 

 

 

 

East Texas gathering system

 

Panola County, TX

 

311

 

1990

 

410,000

 

378,000

 

92

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oklahoma:

 

 

 

 

 

 

 

 

 

 

 

 

 

Foss Lake gathering system

 

Roger Mills and Custer
 County, OK

 

240

 

1998

 

100,000

 

87,500

 

88

%

Grimes gathering system (4)

 

Beckham, Roger Mills
 Counties, OK

 

25

 

2005

 

25,000

 

NA

 

NA

 

Woodford Shale gathering system (5)

 

Hughes, Pittsburg and
 Coal Counties, OK

 

40

 

2006

 

45,000

 

34,000

 

76

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Southwest:

 

 

 

 

 

 

 

 

 

 

 

 

 

Appleby gathering system

 

Nacogdoches County, TX

 

139

 

1990

 

50,000

 

34,200

 

68

%

Other gathering systems (6)

 

Various

 

 

 

Various

 

52,570

 

18,300

 

35

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Michigan:

 

 

 

 

 

 

 

 

 

 

 

 

 

90-mile gas gathering pipeline

 

Manistee, Mason and
Oceana Counties, MI

 

90

 

1994-1998

 

35,000

 

6,500

 

19

%


(4)             MarkWest Energy Partners acquired the Grimes gathering system as part of its December 29, 2006 Santa Fe acquisition.

(5)             In late 2006 the Partnership began the construction and operation of the Woodford gathering system and compression system in a four-county region in the Arkoma Basin in eastern Oklahoma.  On December 1, 2006, the Partnership began gathering gas on that system.  The volume reported is the average daily rate for the month of December.

(6)             MarkWest Energy Partners acquired the Appleby gathering system, along with 20 other gathering systems, as part of its March 28, 2003 Pinnacle acquisition.

NGL Pipelines:

The name, approximate length in miles, geographical location, and throughput of our NGL pipelines as of and for the year ended December 31, 2006, are as follows:

 

 

 

 

 

 

 

 

 

 

Year ended
December 31, 2006

 

Pipeline

 

Location

 

Miles

 

Year of
Initial
Construction

 

Design
Throughput
Capacity

 

NGL
Throughput

 

Utilization 
of Design
Capacity

 

 

 

 

 

 

 

 

 

(Gal/d)

 

(Gal/d)

 

 

 

Appalachia:

 

 

 

 

 

 

 

 

 

 

 

 

 

Maytown to Institute (7)

 

Floyd County, KY to
Kanawha County, WV

 

100

 

1956

 

250,000

 

132,000

 

53

%

Ranger to Kenova (8)

 

Lincoln County, WV to
Wayne County, WV

 

40

 

1976

 

831,000

 

132,000

 

16

%

Kenova to Siloam

 

Wayne County, WV to
South Shore, KY

 

40

 

1957

 

831,000

 

389,000

 

47

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

East Texas:

 

 

 

 

 

 

 

 

 

 

 

 

 

East Texas liquidline

 

Panola County, Texas

 

37.5

 

2005

 

630,000

 

442,300

 

70

%


(7)             Represents a leased pipeline, of which the 40 miles extending from Ranger to Institute is currently unused.

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

Crude Oil Pipeline:

The name, approximate length in miles, geographical location, and throughput of MarkWest Energy Partners’ crude oil pipeline as of and for the year ended December 31, 2006, is as follows:

 

 

 

 

 

 

 

 

 

 

Year ended
December 31, 2006

 

Pipeline

 

Location

 

Miles

 

Year of
Initial
Construction

 

Design
Throughput
Capacity

 

NGL
Throughput

 

Utilization 
of Design
Capacity

 

 

 

 

 

 

 

 

 

(Gal/d)

 

(Gal/d)

 

 

 

Michigan:

 

 

 

 

 

 

 

 

 

 

 

 

 

Michigan crude pipeline

 

Manistee County, MI to
Crawford County, MI

 

250

 

1973

 

60,000

 

14,500

 

24

%

 

Title to Properties

Substantially all of our 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. We have obtained, where determined necessary, permits, leases, license agreements and franchise ordinances from public authorities to cross over or under, or to lay facilities in or along water courses, county

31




roads, municipal streets and state highways, as applicable. We also have obtained easements and license agreements from railroad companies to cross over or under railroad properties or rights-of-way. Many of these authorizations and grants are revocable at the election of the grantor. In some cases, property on which our pipelines were built was purchased in fee or held under long-term leases. Our Siloam fractionation plant and Kenova processing plant are on land that we own in fee.

Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that were transferred to us required the consent of the then-current landowner to transfer these rights, which in some instances was a governmental entity. We believe that we have obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business. We also believe we have satisfactory title or other right to all of our material land assets. Title to these properties is subject to encumbrances in some cases; however, we believe that none of these burdens will materially detract from the value of these properties or from our interest in these properties, or will materially interfere with their use in the operation of our business.

We have pledged substantially all of our assets to secure the debt of our subsidiary, MarkWest Energy Operating Company, L.L.C. (the “Operating Company”), as discussed in Note 11  of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

ITEM 3.                    Legal Proceedings

In the ordinary course of its business, MarkWest Energy Partners is subject to a variety of risks and disputes normal to its business and as a party to various legal proceedings. We maintain insurance policies in amounts and with coverage and deductibles as we believe are reasonable and prudent. However, we cannot assure either that the insurance companies will promptly honor their policy obligations or that the coverage or levels of insurance will be adequate to protect us from all material expenses related to future claims for property loss or business interruption to the Partnership; or for third-party claims of personal and property damage; or that the coverages or levels of insurance it currently has will be available in the future at economical prices.

In 2005 MarkWest Hydrocarbon, the Partnership, several of its affiliates, and an unrelated co-defendant, were served with three lawsuits, which in 2006 were consolidated into a single action captioned Ricky J. Conn, et al. v. MarkWest Hydrocarbon, Inc. et al., Floyd Circuit Court, Commonwealth of Kentucky, and Civil Action No. 05-CI-00137 (consolidated March 27, 2006 of three cases originally filed February, 2005).  These actions involved third-party claims of property and personal injury damages sustained as a consequence of an NGL pipeline leak and an ensuing explosion and fire that occurred on November 8, 2004 in Ivel, Kentucky. The pipeline was owned by an unrelated business entity, Equitable Production Company, and leased and operated by the Partnership’s subsidiary, MEA. MEA transports NGLs from the Maytown gas processing plant to MEA’s Siloam fractionator. The explosion and fire from the leaked vapors resulted in property damage to several residential structures and injuries to some of the residents.

The Partnership notified its general liability insurance carriers of the incident and the lawsuits in a timely manner and coordinated its legal defense with the insurers. As of February 1, 2007, all of the claims in the litigation were fully settled, with MarkWest’s insurance carrier and its co-defendant and its separate insurance carrier, funding the settlements.

Related to the above referenced pipeline incident, MarkWest Hydrocarbon and the Partnership have filed an independent action captioned MarkWest Hydrocarbon, Inc., et al. v. Liberty Mutual Ins. Co., et al. (District Court, Arapahoe County, Colorado, Case No. 05CV3953 filed August 12, 2005), as removed to the U.S. District Court for the District of Colorado, (Civil Action No. 1:05-CV-1948, on October 7, 2005) against its All-Risks Property and Business Interruption insurance carriers as a result of the insurance companies’ refusal to honor their insurance coverage obligation to pay the Partnership for certain expenses related to the pipeline incident. These include the Partnership’s internal expenses and costs incurred for damage to, and loss of use of the pipeline, equipment and products; the extra transportation costs incurred for transporting the liquids while the pipeline was out of service; the reduced volumes of liquids that could be processed; and the costs of complying with the OPS Corrective Action Order (hydrostatic testing, repair/replacement and other pipeline integrity assurance measures). These expenses and costs have been expensed as incurred and any potential recovery from the All-Risks Property and Business Interruption insurance carriers will be treated as “other income” if and when it is received. Following initial discovery, the Partnership was granted leave of the Court to amend its complaint to add a bad faith claim, and a claim for punitive damages.  The Partnership has not provided for a receivable for any of the claims in this action because of the uncertainty as to whether and how much the Partnership will ultimately recover under the policies. Discovery in the action is continuing.  The Partnership has also asserted that the cost of pipeline testing, replacement and repair are subject to an equitable sharing arrangement with the pipeline owner, pursuant to the terms of the pipeline lease agreement.

In June 2006, a Notice of Probable Violation and Proposed Civil Penalty (NOPV) (CPF No. 2-2006-5001) was issued by OPS to both MarkWest Hydrocarbon and Equitable Production Company, the owner of the pipeline, asserting six counts of

32




violations of applicable regulations, and a proposed civil penalty in the aggregate amount of $1,070,000. An administrative hearing on the matter is presently set for the last week of March, 2007.  One of the counts of violations, which count involves $825,000 of the $1,070,000 proposed penalty, concerns alleged activity in 1982 and 1987, which dates predate MarkWest’s leasing and operation of the pipeline.  MarkWest believes it has viable defenses to the remaining counts and will vigorously defend all applicable assertions of violations at the hearing.

The Partnership received notice from one of our customers of a potential gas measurement discrepancy and invoice errors, claiming it is owed several hundred thousand MMBtus as a result. The Partnership generally disputes the claims under the facts and under the terms of the contract with the customer, but is in discussions with the customer to evaluate and resolve all issues, and it appears at this time that this claim should not have a material adverse impact on the Partnership.

With regard to the Partnership’s Javelina facility, MarkWest Javelina is a party with numerous other defendants to several lawsuits brought by various plaintiffs who had residences or businesses located near the Corpus Christi industrial area, an area which included the Javelina gas processing plant, and several petroleum, petrochemical and metal processing and refining operations. These suits, Victor Huff v. ASARCO Incorporated, et al. (Cause No. 98-01057-F, 214th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in March 3, 1998); Hipolito Gonzales et al. v. ASARCO Incorporated, et al., (Cause No. 98-1055-F, 214th Judicial Dist. Ct., County of Nueces, Texas, original petition filed in 1998); Jason and Dianne Gutierrez, individually and as representative of the estate of Sarina Galan Gutierrez (Cause No. 05-2470-A, 28TH Judicial District, severed May 18, 2005, from the Gonzales case cited above); and Esmerejilda G. Valasquez, et al. v. Occidental Chemical Corp., et al., Case No. A-060352-C, 128th Judicial District, Orange County, Texas, original petition filed July 10, 2006; as refiled from previously dismissed petition captioned Jesus Villarreal v. Koch Refining Co. et al., Cause No. 05-01977-F, 214th Judicial Dist. Ct., County of Nueces, Texas, originally filed April 27, 2005), set forth claims for wrongful death, personal injury or property damage, harm to business operations and nuisance type claims, allegedly incurred as a result of operations and emissions from the various industrial operations in the area or from products Defendants allegedly manufactured, processed, used, or distributed. The Gonzales action was settled in early 2006 pursuant to a mediation held December 9, 2005. The other actions have been and are being vigorously defended and, based on initial evaluation and consultations; it appears at this time that these actions should not have a material adverse impact on the Partnership.

In the ordinary course of business, the Partnership is a party to various other legal actions. While it is not possible to predict the outcome of the legal actions with certainty, management is of the opinion that appropriate provision and accruals for potential losses associated with all legal actions have been made in the financial statements. In the opinion of management, none of these actions, either individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition, liquidity or results of operations.

ITEM 4.                    Submission of Matters to a Vote of Security Holders.

No matter was submitted to a vote of the holders of our common units during the fourth quarter of the fiscal year ended December 31, 2006.

33




PART II

ITEM 5.                    Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities.

Our common units have been listed on the American Stock Exchange (“AMEX”), under the symbol “MWE,” since May 24, 2002. Prior to May 24, 2002, our equity securities were not listed on any exchange, or traded on any public trading market. The following table sets forth the high and low sales prices of the common units as reported by AMEX, as well as the amount of cash distributions paid per quarter for 2006 and 2005.

On January 25, 2007, the board of directors of the general partner of the Partnership declared a two-for-one unit split, which became effective February 28, 2007.  For all periods presented, all references to the number of units and per unit net income and distribution amounts included in this report have been adjusted to give the effect for the unit split.

Quarter Ended

 

High

 

Low

 

Distributions
Per
Common
Unit

 

Distributions
Per
Subordinated
Unit

 

Record Date

 

Payment Date

 

December 31, 2006

 

$

29.95

 

$

23.38

 

$

0.500

 

$

0.500

 

February 8, 2007

 

February 14, 2007

 

September 30, 2006

 

$

24.75

 

$

20.50

 

$

0.485

 

$

0.485

 

November 3, 2006

 

November 14, 2006

 

June 30, 2006

 

$

23.33

 

$

19.75

 

$

0.460

 

$

0.460

 

August 7, 2006

 

August 14, 2006

 

March 31, 2006

 

$

23.33

 

$

21.76

 

$

0.435

 

$

0.435

 

May 5, 2006

 

May 15, 2006

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2005

 

$

25.48

 

$

21.01

 

$

0.410

 

$

0.410

 

February 8, 2006

 

February 14, 2006

 

September 30, 2005

 

$

26.75

 

$

23.59

 

$

0.410

 

$

0.410

 

November 8, 2005

 

November 14, 2005

 

June 30, 2005

 

$

25.77

 

$

23.26

 

$

0.400

 

$

0.400

 

August 9, 2005

 

August 15, 2005

 

March 31, 2005

 

$

26.25

 

$

22.63

 

$

0.400

 

$

0.400

 

May 10, 2005

 

May 16, 2005

 

 

As of March 1, 2007, there were 154 holders of record of our common units.

The Partnership has also issued 6,000,000 subordinated units, for which there is no established public-trading market. Pursuant to the terms of the partnership agreement, 2,400,000 of these units were converted into common units in each of 2005 and 2006, and 1,200,000 subordinated units were outstanding as of December 31, 2006. There was 1 unit holder of record of our subordinated units as of March 1, 2007.

Distributions of Available Cash

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

Distributions of Available Cash During the Subordination Period

During the subordination period (as defined in the Partnership Agreement and discussed further below), our quarterly distributions of available cash will be made in the following manner (reflects the two-for-one unit split on February 28, 2007):

·                  First, 98% to the common unitholders and 2% to our general partner, until each common unitholder has received a minimum quarterly distribution of $0.25, plus any arrearages from prior quarters.

·                  Second, 98% to the subordinated unitholders and 2% to our general partner, until each subordinated unitholder has received a minimum quarterly distribution of $0.25, plus any arrearages from prior quarters.

·                  Third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unitholder has received a distribution of $0.275 per quarter.

·                  Thereafter, in the manner described in “Incentive Distribution Rights” below.

Distributions of Available Cash After the Subordination Period

We will make distributions of available cash for any quarter after the subordination period in the following manner:

·                  First, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding unit an

34




amount equal to the minimum quarterly distribution for that quarter; and

·                  Thereafter, in the manner described in “Incentive Distribution Rights” below.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash after the minimum quarterly distribution and the target distribution levels, as described below, have been achieved. Our general partner holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the Partnership Agreement.

If for any quarter:

·                  We have distributed available cash to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

·                  We have distributed available cash on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

we will then distribute any additional available cash for that quarter among the unitholders and our general partner in the following manner:

·                  First, 98% to all unitholders, pro rata, and 2% to our general partner until each unitholder receives a total of $0.275 per unit for that quarter (the “first target distribution”);

·                  Second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives a total of $0.3125 per unit for that quarter (the “second target distribution”);

·                  Third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives a total of $0.375 per unit for that quarter (the “third target distribution”); and

·                  Thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders, to eliminate any cumulative arrearages in payment of the minimum quarterly distribution. We are currently distributing in excess of $0.375 per unit per quarter.

There is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter, and we are prohibited from making any distributions to unitholders if it would cause an event of default under our credit facility. The subordination period generally will not end earlier than June 30, 2007. A portion of the subordinated units, however, may be converted into common units at an earlier date on a one-for-one basis based upon the achievement of certain financial goals (defined in the Partnership Agreement). As a result of achieving those goals, 4,800,000 subordinated units converted into common units.  The following table reflects the effects of the two-for-one unit split on February 28, 2007. The conversion of the subordinated units occurred as follows:

 

Subordinated
Units

 

Subordinated units outstanding at December 31, 2004

 

6,000,000

 

Conversion—August 15, 2005

 

(1,200,000

)

Conversion—November 15, 2005

 

(1,200,000

)

Subordinated units outstanding at December 31, 2005

 

3,600,000

 

Conversion—August 15, 2006

 

(1,200,000

)

Conversion—November 15, 2006

 

(1,200,000

)

Subordinated units outstanding at December 31, 2006

 

1,200,000

 

 

Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information, as of December 31, 2006, regarding our common units that may be issued upon conversion of outstanding restricted units granted under our Long-Term Incentive Plan to employees and directors of our general partner and employees of its affiliates who perform services for us. For more information about this plan, which did not require approval by the Partnership’s limited partners, you should read Note 13 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

35




 

 

 

Number of securities
to be issued upon 
exercise of outstanding
options, warrants
and rights

 

Weighted-average 
exercise price of
outstanding options,
warrants and rights (1)

 

Number of securities
remaining available
for future issuance 
under equity
compensation plans

 

Equity compensation plans approved by security holders

 

 

 

 

Equity compensation plans not approved by security holders:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-Term Incentive Plan - (restricted units)

 

125,200

 

 

128,242

 

Long-Term Incentive Plan - (unit options)

 

 

 

600,000

 

Total

 

125,200

 

 

728,242

 


(1)             Restricted units are granted with no exercise price.

ITEM 6.                    Selected Financial Data

The following table sets forth selected consolidated historical financial and operating data for MarkWest Energy Partners.  We have derived the summary selected historical financial data from our current and historical audited consolidated financial statements and related notes.  All earnings per share and dividend information have been updated to reflect the February 2007 two-for-one unit split. The selected financial data should be read in conjunction with the combined and consolidated financial statements, including the notes thereto, and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.

 

 

Year Ended December 31,

 

 

 

2006

 

2005 (1)

 

2004 (2)

 

2003 (3)

 

2002

 

 

 

(in thousands, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

 

 

Statement of Operations:

 

 

 

 

 

 

 

 

 

 

 

Revenues:

 

$

575,952

 

$

499,084

 

$

301,314

 

$

117,430

 

$

70,246

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

Purchased product costs

 

322,278

 

366,878

 

211,534

 

70,832

 

38,906

 

Facility expenses

 

60,112

 

47,972

 

29,911

 

20,463

 

15,101

 

Selling, general and administrative expenses

 

44,185

 

21,573

 

16,133

 

8,598

 

5,411

 

Depreciation

 

29,993

 

19,534

 

15,556

 

7,548

 

4,980

 

Amortization of intangible assets

 

16,047

 

9,656

 

3,640

 

 

 

Accretion of asset retirement obligations

 

102

 

159

 

13

 

 

 

Impairments

 

 

 

130

 

1,148

 

 

Total operating expenses

 

472,717

 

465,772

 

276,917

 

108,589

 

64,398

 

Income from operations

 

103,235

 

33,312

 

24,397

 

8,841

 

5,848

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings (losses) from unconsolidated affiliates

 

5,316

 

(2,153

)

(65

)

 

 

Interest income

 

962

 

367

 

87

 

14

 

5

 

Interest expense

 

(40,666

)

(22,469

)

(9,236

)

(3,087

)

(1,128

)

Amortization of deferred financing costs and original issue discount (a component of interest expense)

 

(9,094

)

(6,780

)

(5,236

)

(984

)

(291

)

Miscellaneous income (expense)

 

11,100

 

78

 

15

 

(25

)

52

 

Income before income taxes

 

70,853

 

2,355

 

9,962

 

4,759

 

4,486

 

 

 

 

 

 

 

 

 

 

 

 

 

Income tax benefit (expense)

 

(769

)

 

 

 

17,175

 

Net income

 

$

70,084

 

$

2,355

 

$

9,962

 

$

4,759

 

$

21,661

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income per limited partner unit (see Item 8.— Note 12):

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

2.45

 

$

0.01

 

$

0.66

 

$

0.47

 

$

2.43

 

Diluted

 

$

2.44

 

$

0.01

 

$

0.65

 

$

0.47

 

$

2.41

 

Cash distributions declared per limited partner unit

 

$

1.79

 

$

1.60

 

$

1.43

 

$

1.16

 

$

0.36

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet Data (at December 31):

 

 

 

 

 

 

 

 

 

 

 

Working capital

 

$

4,258

 

$

11,944

 

$

10,547

 

$

2,457

 

$

1,762

 

Property, plant and equipment, net

 

550,886

 

492,961

 

280,635

 

184,214

 

79,824

 

Total assets

 

1,114,780

 

1,046,093

 

529,422

 

212,871

 

87,709

 

Total long-term debt, including debt due to parent

 

526,865

 

601,262

 

225,000

 

126,200

 

21,400

 

Partners’ capital

 

452,649

 

307,175

 

241,142

 

64,944

 

60,863

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Flow Data:

 

 

 

 

 

 

 

 

 

 

 

Net cash flow provided by (used in):

 

 

 

 

 

 

 

 

 

 

 

Operating activities

 

$

150,977

 

$

42,090

 

$

42,275

 

$

21,229

 

$

33,502