Item 1. Business General MarkWest Hydrocarbon was founded in 1988 as a partnership and later incorporated in Delaware. We completed our initial public offering of common shares in 1996.
MarkWest Hydrocarbon is an energy company primarily focused on marketing natural gas liquids (NGLs) and increasing shareholder value by growing MarkWest Energy Partners, L.P. (“MarkWest Energy” or “MarkWest Energy Partners” or the “Partnership”), our consolidated subsidiary and a publicly-traded master limited partnership. MarkWest Energy Partners is engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids; and the gathering and transportation of crude oil.
MarkWest Hydrocarbon’s assets consist primarily of partnership interests in MarkWest Energy Partners and certain processing agreements in Appalachia. As of December 31, 2006, the Company owned a 17% interest in the Partnership, consisting of the following (all unit information has been adjusted for the February 2007 unit split; see Note 2 to the Consolidated Financial Statements):
· 3,738,992 common units and 1,200,000 subordinated units, representing a combined 15% limited partner interest in the Partnership; and
· an 89.7% ownership interest in MarkWest Energy GP, L.L.C., the general partner of the Partnership, which in turn owns a 2% general partner interest and all of the incentive distribution rights in the Partnership.
Industry Overview
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 by product of refining crude oil.
MarkWest Energy Partners 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 Partnership’s Javelina Facility:
Natural gas processing and treating involves the separation of raw natural gas into pipeline-quality or fuel-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 the Partnership’s Javelina facilities, the natural gas delivered to its 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. At the Javelina facility, the Partnership also produces 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 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 three other 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.
· Ethylene and propylene are principally used as petrochemical feedstock.
· Hydrogen is principally used in the refining process to assist in the production of low sulfur products.
Competition
MarkWest Hydrocarbon faces competition for marketing NGL products and purchasing natural gas supplies. Competition for customers and purchases of natural gas are based primarily on price, delivery capabilities, flexibility and maintenance of quality customer relationships.
The Partnership faces competition for natural gas and crude oil transportation; 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 the Partnership’s fractionation services include availability of capacity, proximity to supply and industry marketing centers, cost efficiency and reliability of service, and, in the case of Javelina, the value of the recovered products compared to their equivalent value when consumed at the refineries as fuel. Competition for customers is based primarily on price, delivery capabilities, flexibility, and maintenance of high-quality customer relationships.
The Partnership’s 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.
We believe the Partnership’s competitive strengths include:
· Location and efficiency of facilities. In many locations, the Partnership’s facilities were installed more recently and are more efficient than those of its competitors. This provides the Partnership with a significant competitive advantage over its competitors. In other locations, there are no other viable facilities to provide similar services as the Partnership provides.
· Strategic and growing position with high-quality assets in the Southwest and the Gulf Coast. The Partnership’s acquisitions and internal growth projects have allowed it to establish and expand its presence in several long-lived natural gas supply basins in the Southwest, particularly in Texas, Oklahoma and the Gulf Coast. In 2006 the Partnership expanded this strategy through its Newfield agreement by building the largest gathering system to date in the newly emerging Woodford Shale play in southeastern Oklahoma. All of the Partnership’s 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;
· ready access to markets; and
· close proximity to other acquisition or expansion opportunities.
Specifically, the Partnership’s East Texas and Appleby gathering systems are located in the East Texas basin producing from both the Cotton Valley and Travis Peak reservoirs. The Partnership’s Foss Lake gathering system and the associated Arapaho gas processing plant, which it refers to as its western Oklahoma assets, are located in the Anadarko basin in Oklahoma. Additionally, as mentioned above, the Partnership’s Woodford gathering system is located in the rapidly growing Woodford Shale reservoir. Finally, the Partnership’s Starfish asset gathers gas from multiple reservoirs in the Gulf of Mexico. Each of these basins is highly prolific with long lived reserves and significant growth potential. The Partnership’s gathering systems are relatively new and provide producers with low-pressure and fuel-efficient service, a significant competitive advantage for it over many competing gathering systems in those areas. The Partnership believes this competitive advantage is evidenced by its growing throughput volumes on its East Texas, Appleby, western and southeastern Oklahoma operations.
· Long-term contracts. We believe MarkWest Energy Partners’ long-term contracts, which we define as contracts with remaining terms of five years or more, lend greater stability to its cash-flow profile. For the year ended December 31, 2006, approximately 67% of the Partnership’s inlet volumes were tied to long-term contracts.
· Experienced management with operational, technical and acquisition expertise. Each member of our executive management team has substantial experience in the energy industry. The Partnership’s facility managers have extensive experience operating their facilities. The Partnership’s operational and technical expertise has enabled it to upgrade its existing facilities, as well as to design and build new ones, specifically the Carthage gas processing plant. Since the Partnership’s initial public offering in May 2002, its management team has utilized a disciplined approach to analyze and evaluate numerous acquisition opportunities, and has
completed nine acquisitions. The Partnership intends to continue to use its management’s experience and disciplined approach in evaluating and acquiring assets to grow through accretive acquisitions. The acquisitions are expected to increase throughput volumes and ultimately increase cash flow distributable to the Partnership’s unitholders.
To better understand our business and 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, it is important to have an understanding of three factors:
· The nature of our relationship with MarkWest Energy Partners;
· The nature of the contracts from which we derive our revenues and from which MarkWest Energy Partners derives its revenues; and
· The lack of comparability within our results of operations across periods because of MarkWest Energy Partners’ significant acquisition activity.
Our Relationship with MarkWest Energy Partners
We spun off the majority of our then-existing natural gas gathering and processing and NGL transportation, fractionation and storage assets into MarkWest Energy Partners in May 2002, just before the Partnership completed its initial public offering. At the time of its formation and initial public offering, we entered into four contracts with MarkWest Energy Partners whereby MarkWest Energy Partners provides midstream services in Appalachia to us for a fee. Additionally, MarkWest Energy Partners receives 100% of all fee and percent-of-proceeds consideration for the first 10 MMcf/d that it gathers and processes in Michigan. MarkWest Hydrocarbon retains a 70% net profit interest in the gathering and processing income earned on quarterly pipeline throughput in excess of 10 MMcf/d. In accordance with accounting principles generally accepted in the United States (“GAAP”), MarkWest Energy Partners’ financial results are included in our consolidated financial statements. All intercompany accounts and transactions are eliminated during consolidation.
As a result of the contracts mentioned above, the Company is one of the Partnership’s largest customers. For the year ended December 31, 2006, we accounted for 13% of the Partnership’s revenues and 12% of its net operating margin (a non-GAAP financial measure, see Item 1. Business - Contracts), compared to 13% of revenues and 20% of net operating margin for the year ending December 31, 2005. We expect we will account for less of the Partnership’s business in the future as it continues to acquire assets and increase its customer base and diversify its business.
We control and operate MarkWest Energy Partners through our majority ownership in the Partnership’s general partner. Our employees are responsible for conducting the Partnership’s business and operating its assets pursuant to a Services Agreement, which was formalized and made effective January 1, 2004.
Contracts
MarkWest Hydrocarbon Excluding the revenues derived from MarkWest Energy Partners, we generate the majority of our revenues and net operating margin from the Appalachia processing agreements. We outsource these services to the Partnership and pay the Partnership a fee for providing processing and fractionation services. As compensation for providing processing services to our Appalachian producers, we earn a fee and receive title to the NGLs produced. In return, we are required to replace, in dry natural gas, the Btu content of the NGLs extracted. This Btu replacement obligation is referred to in the industry as a “keep-whole” arrangement. In keep-whole arrangements, our principal cost is purchasing and delivering dry gas of an equivalent Btu content to replace the Btus extracted from the gas stream in the form of NGLs, or consumed as fuel during processing. The spread between the NGL product sales price and the purchase price of natural gas with an equivalent Btu content is called the “frac spread.” Generally, the frac spread is positive and offsets all or a portion of the fees that we pay the Partnership. In the event natural gas becomes more expensive on a Btu equivalent basis than NGL products and the associated fees that we pay the Partnership, the net operating margin associated with the Appalachian processing agreements results in operating losses.
In Appalachia, we have entered into various operating agreements with one customer related to the delivery of natural gas into its transmission facilities, located upstream of MarkWest Energy’s Kenova, Boldman and Cobb facilities. Under the terms of these operating agreements, the customer has agreed to use reasonable, diligent efforts to supply these facilities with consistent volumes of natural gas it ships on behalf of the Appalachian producers. The initial terms of our agreements with this customer run through February 9, 2015, with annual renewals thereafter.
In September 2004 we entered into several new and amended agreements with this customer mentioned above in the Appalachia region. These agreements, which expire in 2015 assuming renewals we deem likely, will allow us to significantly reduce our exposure
to commodity price risk, for approximately 25% of our keep-whole gas volumes. Under these agreements, the Company’s exposure to the keep-whole natural gas is limited in the event natural gas becomes more expensive than the NGL product sales price, thereby mitigating the risk of incurring operating losses.
At the closing of MarkWest Energy Partners’ initial public offering on May 24, 2002, we outsourced our midstream services to the Partnership. Pursuant to the terms of the operating agreements, we retained all the benefits and associated risks of the keep-whole contracts. We also retained our NGL marketing and natural gas supply operations and did not contribute them to MarkWest Energy Partners.
The keep-whole contracts expose us to commodity price risk, both on the sales side (of NGLs) and on the purchase side (of natural gas), which, in turn, may increase the volatility of our standalone results and cash flows. We attempt to mitigate our commodity price risk through our commodity price risk management program (see Item 7A. Quantitative and Qualitative Disclosures about Market Risk for further details about our commodity price risk management program).
MarkWest Energy Partners
The Partnership generates the majority of its revenue and net operating margin from natural gas gathering, processing and transmission, NGL transportation, fractionation and storage; and crude oil gathering and transportation. In many cases, the Partnership provides services under contracts that contain a combination of more than one of the arrangements described below. While all of these services constitute midstream energy operations, the Partnership provides services under the following different types of arrangements:
· Fee-based arrangements. The Partnership receives 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 the Partnership earns from these arrangements is directly related to the volume of natural gas, NGLs or crude oil that flows through our systems and facilities and is not directly dependent on commodity prices. In certain cases, these arrangements provide for minimum annual payments. If a sustained decline in commodity prices were to result in a decline in volumes, the Partnership’s revenues from these arrangements would be reduced.
· Percent-of-proceeds arrangements. The Partnership gathers and processes natural gas on behalf of producers, sells the resulting residue gas, condensate and NGLs at market prices, and remits to producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments, the Partnership delivers an agreed-upon percentage of the residue gas and NGLs to the producer, and sells the volumes it keeps to third parties at market prices. Generally, under these types of arrangements its revenues and net operating margins increase as natural gas, condensate and NGL prices increase, and its revenues and net operating margins decrease as natural gas and NGL prices decrease
· Percent-of-index arrangements. The Partnership generally purchases 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. It then gathers and delivers the natural gas to pipelines, where it resells the natural gas at the index price, or at a different percentage discount to the index price. The net operating margins the Partnership realizes under these arrangements decrease in periods of low natural gas prices, because these net operating margins are based on a percentage of the index price. Conversely, their net operating margins increase during periods of high natural gas prices.
· Keep-whole arrangements. The Partnership gathers natural gas from the producer, processes the natural gas, and sells 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, the Partnership 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 the Partnership’s revenues and net operating margins increase as the price of condensate and NGLs increases relative to the price of natural gas, and decreases as the price of natural gas increases relative to the price of condensate and NGLs.
· Settlement margin. Typically, the Partnership is allowed to retain a fixed percentage of the volume gathered to cover the compression fuel charges and deemed line losses. To the extent the gathering system is operated more efficiently than specified per contract allowance, the Partnership is entitled to retain the difference for its own account.
The terms of the Partnership’s contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements. The Partnership’s contract mix and, accordingly, its exposure to natural gas and NGL prices, may change as a result of changes in producer preferences, its expansion in regions where some types of contracts are more common and other market factors. Any change in mix will influence the Partnership’s financial results.
Management evaluates performance on the basis of net operating margin (a non-GAAP financial measure), which is defined as income (loss) from operations, excluding facility cost, selling, general and administrative expense, depreciation, amortization, impairments and accretion of asset retirement. These charges have been excluded for the purpose of 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 of excluding certain charges is not necessarily an indication of the results of operations expected in the future. The following table represents reconciliation to the most comparable GAAP financial measure of this non-GAAP financial measure (in thousands):
For the year ended December 31, 2006, MarkWest Energy Partners calculated the following approximate percentages of its revenues and net operating margin from the following types of contracts, exclusive of the impact of commodity derivatives:
(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.
Impact of Recent Acquisitions on Comparability of Financial Results
MarkWest Energy Partners
In reading the discussion of our historical results of operations, you should be aware of the impact of the Partnership’s recent acquisitions, which fundamentally affect the comparability of our results of operations over the periods discussed.
Since the Partnership’s initial public offering, it has completed nine acquisitions for an aggregate purchase price of approximately $810 million, net of working capital. The following table contains information regarding each of these acquisitions (in millions):
(1) Consideration includes $35.5 million in cash.
(2) Represents a 50% non-controlling interest.
Segment Reporting
The Company’s financial statements include two reportable segments; MarkWest Hydrocarbon Standalone and MarkWest Energy Partners. For further information regarding our segments, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation and Item 8. Financial Statements and Supplementary Data included in this Form 10-K.
For the year ended December 31, 2006, the MarkWest Hydrocarbon Standalone segment had two significant customers while the MarkWest Energy Partners’ segment had three. Of these five significant customers, only one, Targa Resources Partners, L.P., had a significant impact on the Company’s consolidated financial statements, accounting for 10% of consolidated revenue.
MarkWest Hydrocarbon Standalone
Our marketing group markets NGL production in Appalachia. In 2006, we sold approximately 162 million gallons of NGLs extracted at the Partnership’s Siloam facility. This includes approximately 43 million gallons sold on behalf of the Partnership at no mark-up in the standalone segment. We ship NGL products from Siloam by truck, rail and barge. Our marketing customers include propane retailers, refineries, petrochemical plants and NGL product resellers. Most marketing sales contracts have terms of one year or less, are made on best-efforts basis and are priced in reference to Mt. Belvieu index prices or plant posting prices. In addition to our NGL product sales, our marketing operations also purchase natural gas for delivery to the account of producers, pursuant to our keep-whole processing contracts.
We strive to maximize the value of our NGL output by marketing directly to our customers. We minimize the use of third-party brokers, preferring instead to support a direct marketing staff focused on multi-state and independent dealers. Additionally, we use our own trailer and railcar fleet, our own terminal, and owned and leased storage facilities, all of which serve to enhance supply reliability to our customers. These efforts have allowed us to generally maintain premium pricing for the majority of our NGL products.
In Appalachia, we have entered into various operating agreements with one customer related to the delivery of natural gas into its transmission facilities, located upstream of MarkWest Energy’s Kenova, Boldman and Cobb facilities. Under the terms of these operating agreements, the customer has agreed to use reasonable, diligent efforts to supply these facilities with consistent volumes of natural gas it ships on behalf of the Appalachian producers. The initial terms of our agreements with this customer run through February 9, 2015, with annual renewals thereafter.
Consistent with the Partnership’s operating agreements with this same customer, the Partnership enters into contracts with natural gas producers for production to occur in the Partnership’s Kenova, Boldman and Cobb facilities, before delivery of the producer’s natural gas to the customer’s transmission facilities. We have contractual commitments with over 250 such producers in Appalachia. Under the provisions of our contracts with the Appalachian producers, the producers have committed all of the natural gas they deliver into the customer’s transmission facilities upstream of MarkWest Energy’s Kenova, Boldman and Cobb facilities for processing.
As compensation for providing processing services to our Appalachian producers (we have since outsourced these services to MarkWest Energy Partners as discussed below), we earn a fee and also retain the NGLs produced under keep-
whole agreements. In return, we are required to replace, in dry natural gas, the Btu content of the NGLs extracted.
In September 2004 we entered into several new and amended agreements with one of the largest producers in the Appalachia region. These agreements, which expire in 2015 assuming renewals we deem likely, will allow us to significantly reduce our exposure to commodity price risk, for approximately 25% of our keep-whole gas volumes. Under these agreements, the Company’s exposure to the keep-whole natural gas is limited in the event natural gas becomes more expensive than the NGL product sales price, thereby mitigating the risk of incurring operating losses.
Our natural gas marketing group markets natural gas for the Partnership, purchases the necessary replacement Btu gas requirements and assists with business development efforts. From February 2004 through June 2006, the Company engaged in the wholesale propane marketing business through a third party agency agreement. The Company completed the terms of the termination agreement with the third party agency in February 2007. MarkWest Hydrocarbon also enters into future sale agreements that, as derivative instruments, are marked to market.
MarkWest Energy Partners
MarkWest Energy Partners’ assets and operations may be summarized as follows:
Southwest Business Unit
· East Texas. MarkWest Energy Partners owns 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 the largest onshore natural gas fields in Texas. 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
· Oklahoma. MarkWest Energy Partners owns 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. The Partnership also owns a gathering system in the Woodford Shale Play in the Arkoma Basin of southeastern Oklahoma, and owns the Grimes Gathering System, which is located in Roger Mills and Beckham counties in western Oklahoma
· Other Southwest. MarkWest Energy Partners owns 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. The Partnership gathers a significant portion of the gas produced from fields adjacent to its gathering systems. In many areas the Partnership is the primary gatherer, and in some of the areas served by its smaller systems, they are the sole gatherer. The Partnership also owns four lateral pipelines in Texas and New Mexico.
Northeast Business Unit
· Appalachia. MarkWest Energy Partners is 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. The Partnership’s Appalachian assets include the Kenova, Boldman, Maytown, Cobb and Kermit natural gas-processing plants, a NGL pipeline, a NGL fractionation plant and two caverns for storing propane
· Michigan. MarkWest Energy Partners owns a common carrier crude oil gathering pipeline in Michigan which is subject to regulation by the Federal Energy Regulatory Commission (“FERC”). They refer to this pipeline as the Michigan crude pipeline. The Partnership also owns the Fisk processing plant in Manistee County, Michigan.
Gulf Coast Business Unit
· Javelina. The Partnership owns and operates 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 Partnership also owns a 50% non-operating membership interest in Starfish Pipeline Company, LLC, 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.
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, you should not rely on the following discussion of certain laws and regulations as an exhaustive review of all regulatory considerations affecting our operations.
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 pro-competitive 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 have 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 requirements and complaint-based rate regulations. 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 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.
The Partnership’s Appalachian pipeline carries NGLs across state lines. The primary shipper on the pipeline is MarkWest Hydrocarbon, which has entered into agreements with the Partnership providing for a fixed transportation charge for the term of the agreements. They expire on December 31, 2015. The Partnership is the only other shipper on the pipeline. As the Company neither operates the Appalachian pipeline as a common carrier, nor holds 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 the 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 the Partnership’s 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 the Appalachian pipeline or the transportation charge during the term of its 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 MarkWest Hydrocarbon
We are subject to environmental risks normally incidental to our operations and construction activities including, but not limited to, uncontrollable flows of natural gas, fluids and other substances into the environment, explosions, fires, pollution and other environmental and safety risks. Our business is subject to comprehensive state and federal environmental regulations. For example, we, without regard to fault, could incur liability under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (also known as Superfund), or state counterparts, in connection with the disposal or other releases of hazardous substances, including sour gas, and for natural resource damages. Further, the recent trend in environmental legislation and regulations is toward stricter standards, and this will likely continue in the future.
Our activities are subject to environmental and safety regulation by federal and state authorities, including, without
limitation, the state environmental agencies and the federal Environmental Protection Agency, which can increase the costs of designing, installing and operating our facilities. In most instances, the regulatory requirements relate to the discharge of substances into the environment and include measures to control water and air pollution.
Laws and regulations may require us to obtain a permit or other authorization before we may conduct certain activities or we may be subject to fines and penalties for non-compliance. Further, these rules may limit or prohibit our activities within wilderness areas, wetlands, and areas providing habitat for certain species or other protected areas. We are also subject to other federal, state and local laws covering the handling, storage or discharge of materials used by us. We believe that we are in material compliance with all applicable laws and regulations.
MarkWest Energy Partners
General
The Partnership’s 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 the Partnership’s present and future operations, and generally require it 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 the Partnership to fines, penalties and/or interruptions in its operations that could influence future results of operations.
The Partnership believes that its 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 its results of operations or financial condition. The Partnership 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 it. 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 the Partnership currently anticipates. Revised or additional environmental requirements that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from the Partnership’s customers, could have material adverse effect on its business, financial condition, results of operations and cash flow.
Hazardous Substance and Waste
To a large extent, the environmental laws and regulations affecting the Partnership’s operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control environmental pollution of the environment. 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 the Partnership generates materials in the course of its operations that are regulated as hazardous substances, they have not received any notification that they may be potentially responsible for cleanup costs under CERCLA. The Partnership may also incur a 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 non-hazardous solid wastes. The Partnership is not currently required to comply with a substantial portion of the RCRA requirements because its operations generate minimal quantities of hazardous wastes. However, it is possible that some wastes generated by the Partnership that are currently classified as non-hazardous may, in the future, be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements.
The Partnership currently owns or leases, 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 the Partnership 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 the Partnership’s control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, the Partnership could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination or to perform remedial operations to prevent future contamination. The Partnership does not believe that there presently exists significant surface and subsurface contamination of its properties by hydrocarbons or other solid wastes for which it is currently responsible.
Ongoing Remediation and Indemnification from a Third Party
The previous owner/operator of the Partnership’s Boldman and Cobb facilities has been, or is currently involved in, investigatory or remedial activities with respect to the real property underlying these facilities. 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 the Partnership’s 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 the Partnership 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 the Partnership 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, it does not believe that such requirements will have a material adverse affect on its operations.
Water
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. The Partnership believes that it is 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 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.
The Partnership’s affiliate MarkWest Energy Appalachia, L.L.C. (“MEA”) operates the Appalachia Liquids Pipeline System (“ALPS”) pipeline to transport NGLs from its Maytown gas processing plant to its 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 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. Even though we cannot accurately estimate these expenditures at this time, we do not expect that they will have a material adverse effect on our results of operations.
Employees
As of December 31, 2006, we had 318 employees, who operate the Company’s facilities and provide general and administrative services. The Paper, Allied Industrial, Chemical and Energy Workers International Union Local 5-372 represents 14 employees at the Partnership’s 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 stock trades on the American Stock Exchange under the symbol “MWP.” 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.
Item 1A.
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 Hydrocarbon.
Risks Inherent in Our Business
We are highly dependent upon the earnings and distributions of MarkWest Energy Partners.
A significant decline in MarkWest Energy Partners’ earnings and/or cash distributions would have a corresponding negative impact on us. For more information on these earnings and cash distributions, please see MarkWest Energy Partners’ 2006 Annual Report on Form 10-K.
If we are unable to successfully integrate the Partnership’s recent or future acquisitions, our future financial performance may be negatively impacted.
Our future growth will depend in part on our ability to integrate the Partnership’s future acquisitions. We cannot guarantee that the Partnership will successfully integrate any acquisitions into its operations or that the Partnership will achieve the desired profitability and anticipated results from such acquisitions. Failure to achieve such planed 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 to our existing operations;
· 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 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, the Partnership may discover previously unknown liabilities subject to the same stringent environmental laws and regulations relating to releases of pollutants into the environment and environmental protection as the Partnership’s existing plants, pipelines and facilities. If so, the Partnership’s operation of these new assets could cause us to incur increased costs to attain or maintain compliance with such requirements. If the Partnership consummates any future acquisition, its capitalization and results of operation may change significantly, and shareholders 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.
The Partnership’s 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 the Partnership’s opportunities for future acquisitions, and could adversely affect its operations and cash flows available for distribution to its unitholders.
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. 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. Our operations expose us to fluctuations in commodity prices. We utilize derivative financial instruments related to the future price of natural gas and certain NGLs with the intent of reducing volatility in our cash flows due to fluctuations in commodity prices. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation and Item 7A. Quantitative and Qualitative Disclosures About Market Risk as set forth in this report for more information about our risk management policies and procedures.
Our management has discretion in conducting our risk management activities and may not accurately predict future price fluctuations and therefore expose us to financial risks and reduce our opportunity to benefit from price increases.
We evaluate our exposure to commodity price risk from an overall portfolio basis. Our management has discretion in determining whether and how to manage the commodity price risk associated with our physical and derivative positions.
To the extent that we do not manage the commodity price risk relating to a position that is subject to commodity price risk, and commodity prices move adversely, we could suffer losses. Such losses could be substantial, and could adversely affect our financial condition and results of operations.
Changes in commodity prices subject us to margin calls, which may adversely affect our liquidity.
Unfavorable commodity price changes may subject us to margin calls that require us to provide cash collateral to our counterparties in amounts that may be material. Such funding requirements could exceed our ability to access our credit line or other sources of capital. If we are unable to meet these margin calls with borrowings or cash on hand, we would be forced to sell product to meet the margin calls, or to terminate the corresponding futures contracts. If we are forced to sell product to meet margin calls, we may have to sell product at prices that are not advantageous, which could adversely affect our financial condition, results of operations and cash flows.
The Partnership’s 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.
The Partnership has substantial indebtedness and other financial obligations. Subject to the restrictions governing the Partnership’s indebtedness and other financial obligations, and the indenture governing their outstanding notes, the Partnership may incur significant additional indebtedness and other financial obligations.
The Partnership’s substantial indebtedness and other financial obligations could have important consequences. For example, they could:
· make it more difficult for the Partnership to satisfy its obligations with respect to its existing debt;
· impair the Partnership’s ability to obtain additional financings in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes;
· have a material adverse effect on the Partnership if it fails to comply with financial and restrictive covenants in their debt agreements, and an event of default occurs as a result of that failure that is not cured or waived;
· require the Partnership to dedicate a substantial portion of its cash flow to payments on its indebtedness and other financial obligations, thereby reducing the availability of the Partnership’s cash flow to fund working capital, capital expenditures, distributions and other general partnership requirements;
· limit the Partnership’s flexibility in planning for, or reacting to, changes in its business and the industry in which it operates; and
· place the Partnership at a competitive disadvantage compared to its competitors that have proportionately less debt.
Furthermore, these consequences could limit the Partnership’s ability, and the ability of the its subsidiaries, to obtain future financings, make needed capital expenditures, withstand a future downturn in the its business or the economy in general, conduct operations or otherwise take advantage of business opportunities that may arise. The Partnership’s 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 its 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 the Partnership common units. The Partnership obligations under the credit facility are secured by substantially all of its assets and guaranteed by them and all of
their subsidiaries, other than the Partnership’s operating company, which is the borrower under the credit facility. In particular, the Partnership may be unable to meet those ratios and conditions. Any future breach of any of these covenants or the Partnership’s failure to meet any of these ratios or conditions could result in a default under the terms of their credit facility, which could result in acceleration of the Partnership’s debt and other financial obligations. If the Partnership 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 the Partnership’s areas of operation would reduce their ability to make distributions.
The Partnership’s gathering systems are connected to natural gas reserves and wells, from which the production will naturally decline over time, which means that the cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on the partnership’s gathering systems and the utilization rate at its processing plants and it’s treating and fractionation facilities, they must continually obtain new natural gas supplies. The Partnership’s ability to obtain additional sources of natural gas depends in part on the level of successful drilling activity near its gathering systems.
The Partnership has no control over the level of drilling activity in the areas of its operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, they 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 the Partnership’s assets, producers may choose not to develop those reserves. If the Partnership is 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 its pipelines and the utilization rates of its treating and processing facilities would decline, which could have a material adverse effect on its business, results of operations, financial condition and ability to make cash distributions.
We are exposed to the credit risk of our customers and counterparties, and a general increase in the nonpayment and nonperformance by our customers could reduce our revenues and cash flow.
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.
The Partnership may not be able to retain existing customers or acquire new customers, which would reduce its revenues and limit its future profitability.
The renewal or replacement of existing contracts with the Partnership’s customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond its 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. The Partnership’s 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 the Partnership does. Additionally, the Partnership’s customers that gather gas through facilities that are not otherwise dedicated to the Partnership may develop their own processing and fractionation facilities in lieu of using the Partnership’s services. Certain of the Partnership’s 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 the Partnership in the marketing of natural gas, the Partnership often competes in the end-user and utilities markets primarily on the basis of price. The inability of the Partnership’s management to renew or replace its current contracts as they expire and to respond appropriately to changing market conditions could affect its profitability.
Relative changes in NGL product and natural gas prices may adversely impact our results due to frac spread, natural gas and liquids exposure.
We are exposed to frac spread risk. Under our keep-whole arrangements, our principal cost is delivering dry gas of an equivalent Btu content to replace Btus extracted from the gas stream in the form of NGLs, or consumed as fuel during processing. The spread between the NGL product sales price and the purchase price of natural gas with an equivalent Btu content is called the “frac spread.” Generally, the frac spread and, consequently, the net operating margins are positive under these contracts. In the event natural gas becomes more expensive on a Btu equivalent basis than NGL products, the cost of keeping the producer “whole” results in operating losses.
Due to timing of gas purchases and liquid sales, direct exposure to either gas or liquids can be created because there is no longer an offsetting purchase or sale that remains exposed to market pricing. Through our marketing and derivatives activity, direct exposure may occur naturally or we may choose direct exposure to either gas or liquids when we favor that exposure over frac spread risk. Given that we have positions, adverse movement in prices to the positions we have taken will negatively impact our results.
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 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.
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’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 & 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 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 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. 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.
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.
We are subject to operating and litigation risks that may not be covered by insurance.
Our industry is subject to numerous operating hazards and risks incidental to processing, transporting, fractionating and storing natural gas and NGLs and to transporting and storing crude oil. These include:
· damage to pipelines, plants, related equipment and surrounding properties caused by floods and other natural disasters;
· inadvertent damage from construction and farm equipment;
· leakage of crude oil, natural gas, NGLs and other hydrocarbons;
· fires and explosions; and
· other hazards, including those associated with high-sulfur content, or sour gas that could also result in personal injury and loss of life, pollution and suspension of operations.
As a result, we may be the defendants in various legal proceedings and litigation arising from our operations. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Market conditions could cause certain insurance premiums and deductibles to become unavailable, or available only for reduced amounts of coverage. For example, insurance carriers now require broad exclusions for losses due to war risk and terrorist acts. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position.
Transportation on certain of the Partnership’s 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 the Partnership’s 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 the Partnership’s rates and terms and conditions of service provide no more than a fair return on the aggregate value of the facilities used to render services. The Partnership cannot assure their 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, see Item 1. Business - Regulatory Matters
The Partnership is indemnified for liabilities arising from an ongoing remediation of property on which its facilities are located and its results of operation and its ability to make payments of principal and interest on its debt and distributions to its 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 the Partnership’s Kenova, Boldman, Cobb and Kermit facilities are located, and is the previous operator of its 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 the Partnership is 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 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 an additional environmental indemnity pursuant to the terms of the Omnibus Agreement. The Company’s results of operation and ability to make cash distributions could be adversely affected if, in the future, Columbia Gas fails to perform under the indemnification provisions of which the Company is the beneficiary.
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 complex 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, see Item 1 Business - Regulatory Matters and Environmental Matters.
MarkWest Energy Partners may not be able to successfully execute its business plan and may not be able to grow its business, which could adversely affect the value of our investment in the limited partner units and the general partnership interests in MarkWest Energy Partners.
MarkWest Energy Partners’ ability to successfully operate its business, generate sufficient cash to pay the minimum quarterly cash distributions to its unitholders, and to allow for growth, is subject to a number of risks and uncertainty. Similarly, MarkWest Energy Partners may not be able to successfully expand its business through acquiring or growing its assets, because of various factors, including economic and competitive factors beyond its control. If MarkWest Energy Partners is unable to grow its business, or execute on its business plan, the market price of the common units is likely to decline, causing the limited partner units and the general partner interest we hold in MarkWest Energy Partners to also decline in value.
Our cash flow would be adversely affected if operations at any of the Partnership’s facilities were interrupted.
The Partnership’s operations depend upon the infrastructure that it has developed, including processing and fractionation plants, storage facilities, and various means of transportation. Any significant interruption at these facilities or pipelines, or the Partnership’s 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 and cash flows. Operations at the Partnership’s facilities could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within its control, such as:
· unscheduled turnarounds or catastrophic events at our physical plants;
· labor difficulties that result in a work stoppage or slowdown; or
· a disruption in the supply of crude oil to the Partnership’s crude oil pipeline, natural gas to its processing plants or gathering pipelines, or a disruption in the supply of NGLs to the Partnership’s transportation pipeline and fractionation facility.
Due to the Partnership’s lack of asset diversification, adverse developments in the Partnership’s gathering, processing, transportation, transmission, fractionation and storage businesses would reduce the Partnership’s ability to make distributions to its unitholders.
We rely on the revenues generated from the Partnership’s 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.
The tax treatment of MarkWest Energy Partners depends upon its status as a partnership for federal income tax purposes, as well as it not being subject to entity-level taxation by states. If the Internal Revenue Service were to treat MarkWest Energy Partners as a corporation, or if it were to become subject to entity-level taxation for state tax purposes, then its cash available for distribution would be significantly reduced.
We own limited partner units representing approximately 15% of the limited partnership interests in MarkWest Energy Partners, in addition to a 2% general partnership interest. The anticipated after-tax benefit of an investment in the limited partner units of MarkWest Energy Partners depends largely on MarkWest Energy Partners being treated as a partnership for federal income tax purposes.
If MarkWest Energy Partners were treated as a corporation for federal income tax purposes, it would pay income tax on its earnings at the corporate tax rate, which is currently a maximum of 35%, plus any applicable state rates. Cash distributions to the holders of limited partnership interests, including the subordinated units we hold and the common units held by the public, would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to the holders of the limited partnership interests to shelter a substantial portion of such distributions from state and federal income taxes. If MarkWest Energy Partners was taxed as a corporation, its cash available for distribution to limited partners would be significantly reduced. Thus, treatment of MarkWest Energy Partners as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to its owners, including us, as a holder of the limited partner units, likely causing a significant reduction in the value of the market price of the common units.
A shortage of skilled labor may make it difficult for us to maintain labor productivity and competitive costs, and could adversely affect our profitability.
The Partnership’s 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 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.
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. 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.
Item 1B.
Item 1B. Unresolved Staff Comments None.
Item 2.
Item 2. Properties MarkWest Hydrocarbon Standalone
As of December 31, 2006, MarkWest Hydrocarbon Standalone did not own any materially important physical properties.
MarkWest Energy Partners’ Properties
Gas Processing Facilities
The locations and approximate throughput capacity of MarkWest Energy Partners’ gas processing facilities as of and for the year ended December 31, 2006, are as follows:
(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 MarkWest Energy Partners’ fractionation facility as of and for the year ended December 31, 2006, is as follows:
Natural Gas Gathering Systems and Pipelines
The name, approximate length in miles, geographical location, and throughput of MarkWest Energy Partners’ natural gas pipelines as of and for the year ended December 31, 2006, are as follows:
(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 MarkWest Energy Partners’ NGL pipelines as of and for the year ended December 31, 2006, are as follows:
(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:
Title to Properties
MarkWest Hydrocarbon Standalone
MarkWest Hydrocarbon Standalone believes that it has satisfactory title to all of its assets.
MarkWest Energy Partners
Substantially all of the Partnership’s pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. The Partnership has obtained, where 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 roads, municipal streets and state highways, as applicable. The Partnership has also 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 the Partnership’s pipelines were built was purchased in fee or held under long-term leases. The Partnership’s Siloam fractionation plant and Kenova processing plant are on land that it owns in fee.
Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that were transferred to the Partnership required the consent of the then-current landowner to transfer these rights, which in some instances was a governmental entity. The Partnership believes that they have obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for it to operate its business. The Partnership also believes they have satisfactory title or other right to all of its material land assets. Title to these properties is subject to encumbrances in some cases; however, the Partnership believes that none of these burdens will materially detract from the value of these properties or from its interests in these properties, or will materially interfere with their use in the operation of its business.
The Partnership has pledged substantially all of its assets to secure the debt of its subsidiary, MarkWest Energy Operating Company, L.L.C. (the “Operating Company”), as discussed in Note 12 of the accompanying consolidated financial statements.
Item 3.
Item 3. Legal Proceedings In the ordinary course of its business the Company 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 Company; 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 Company 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
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 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.
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 Company for certain expenses related to the pipeline incident. These include the Company’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 Company was granted leave of the Court to amend its complaint to add a bad faith claim, and a claim for punitive damages. The Company 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 Company will ultimately recover under the policies. Discovery in the action is continuing. The Company 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.
The Company just recently learned that a default judgment had been entered against it in May of 2006, in an action entitled Runyan v. Eclipse Realty LLC et al, (Arapahoe County District Court, Colorado, Case No. 06CV1054, filed February 2006). The Company was not aware of having ever received a summons and was not given any notification of a motion for default judgment. The Company is still investigating whether there ever was proper service of process. The action involves a personal injury claim by an individual who allegedly slipped and fell due to snowy conditions while approaching the office building in which the Company was one of several tenants. Eclipse Realty, the landlord of the building, was responsible for the maintenance and upkeep of the common areas of the office building. The Company is seeking to have the default judgment vacated, and then having the Company dismissed as an improper party to the action. The Company also has a contractual indemnification from Eclipse Realty, the landlord of the building, and we have demanded that Eclipse Realty
defend and indemnify the Company. We are unable to predict the outcome of our motion to vacate the default judgment or our indemnification claim, but the Company does not expect at this time that the matter should have a material adverse effect on our financial position.
The Partnership received notice from one of its 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 or us.
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 or us.
In the ordinary course of business, the Company 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 Company’s financial condition, liquidity or results of operations.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders No matters were submitted to a vote in the fourth quarter of 2006.
PART II Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Our common stock trades on the American Stock Exchange (“AMEX”) national market under the symbol “MWP.” As of February 15, 2007, there were 11,992,520 shares of common stock outstanding held by 83 holders of record. The following table sets forth quarterly high and low sales prices as reported by the American Stock Exchange as well as the amount of cash dividends paid per share per quarter for 2006 and 2005. All numbers have been retroactively restated to give effect to the May 2006 stock dividend.
Dividend Policy
The Company does not have a formal dividend policy. The Company’s objective, however, is to maintain a regular quarterly dividend. Payment of dividends in the future will depend on our earnings, financial condition and contractual restrictions, including those under our bank line of credit or imposed by law and other factors deemed relevant by our Board of Directors.
Stock Dividend
On April 27, 2006, MarkWest Hydrocarbon announced that its Board of Directors approved the issuance of one share of common stock for each ten shares of common stock held by common stockholders. The stock was issued on May 23, 2006, to the stockholders of record as of the close of business on May 11, 2006; the ex-dividend date was May 9, 2006.
Securities Authorized for Issuance under Equity Compensation Plans
The following table provides information as of December 31, 2006, about the shares of our common stock and units of the Partnership that may be issued upon the exercise of options, warrants and rights under all of the Company’s existing equity compensation plans.
All previously awarded MarkWest Hydrocarbon restricted stock, stock options and other compensation arrangements based on the market value of our common stock have been adjusted to reflect the May 2006 stock dividend. Furthermore, all previously awarded Partnership units have been adjusted to reflect the February 2007 two-for-one unit split (see Note 2 to the consolidated financial statements):
(1) Restricted stock and units are granted with no exercise or conversion price.
Item 6.
Item 6. Selected Financial Data
The following table sets forth selected consolidated historical financial and operating data for MarkWest Hydrocarbon. 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 May 2006 stock dividend. The selected financial data should be read in conjunction with the consolidated financial statements, including the notes thereto, and Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation Management’s Discussion and Analysis (“MD&A”) contains statements that are forward-looking and should be read in conjunction with “Selected Consolidated Financial Data” and our consolidated financial statements and accompanying notes included elsewhere in this report. These statements are based on current expectations and assumptions that are subject to risks and uncertainties. Actual results could differ materially from those expressed or implied in the forward-looking statements as a result of a number of factors.
Overview
MarkWest Hydrocarbon, Inc. is an energy company primarily focused on marketing natural gas liquids and increasing shareholder value by growing MarkWest Energy Partners, L.P., its consolidated subsidiary and a publicly-traded master limited partnership. The Partnership is engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids; and the gathering and transportation of crude oil.
Our assets consist primarily of partnership interests in the Partnership and certain processing agreements in Appalachia. As of December 31, 2006, the Company owned a 17% interest in the Partnership. This ownership consisted of 3,738,992 common units and 1,200,000 subordinated units, representing a combined 15% limited partner interest in the Partnership, and an 89.7% ownership interest in MarkWest Energy GP, L.L.C., the general partner of the Partnership, which in turn owns a 2% general partner interest and all of the incentive distribution rights in the Partnership. Since the formation of the Partnership in 2002, it has grown significantly as a result of construction and acquisition of gathering and transmission pipelines and treating and processing plants. Since its initial public offering, the Partnership has completed nine acquisitions for an aggregate purchase price of $810 million, net of working capital.
A large portion of our cash flows consist of the distributions we receive from the Partnership on the partnership interests we own. The Partnership is required by its partnership agreement to distribute available cash from operating surplus each quarter to pay the minimum quarterly distribution. The amount of cash the Partnership can distribute on its units depends principally on the amount of cash generated from its operations.
Incentive distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they entitle us to receive 13% of all cash distributed in a quarter after each unit has received $0.275 for that quarter; 23% of all cash distributed after each unit has received $0.3125 for that quarter; and 48% of all cash distributed after each unit has received $0.375 for that quarter.
Distributions by the Partnership have increased from $0.25 per unit for the quarter ended September 30, 2002 (its first full quarter of operation after its initial public offering), to $0.50 per unit for the quarter ended December 31, 2006. As a result, our distributions from the Partnership pursuant to our ownership of common and subordinated units have increased from $1.2 million for the quarter ended September 30, 2002 to $2.4 million for the quarter ended December 31, 2006; our distributions pursuant to our 2% general partner interest have increased from less than $0.1 million to approximately $0.4 million; and our distributions pursuant to our incentive distribution rights have increased from zero to $3.8 million. In total, our total distributions from our investment in the Partnership have increased from $1.3 million for the quarter ended September 30, 2002 to $6.6 million for the quarter ended December 31, 2006. As a result, we have increased our dividend from $0.02 per share for the quarter ended March 31, 2004 (our first dividend payout) to $0.30 per share for the quarter ended December 31, 2006.
A significant part of the Partnership’s business strategy includes acquiring additional businesses that will allow it to increase distributions to its unitholders. The Partnership regularly considers and enters into discussions regarding potential acquisitions. These transactions may be effectuated quickly, may occur at any time and may be significant in size relative to the Partnership’s existing assets and operations. The following is a brief summary of the Partnership’s acquisitions through December 31, 2006.
The Partnership completed the Santa Fe acquisition closed on December 29, 2006 for consideration of $15.0 million. Due to the timing of the acquisition, there is no associated activity reflected in the statement of operations in 2006.
The Partnership completed the following two acquisitions in 2005 which are included in the results of operations from their dates of acquisition:
· The Javelina acquisition closed on November 1, 2005, for consideration of $357.0 million, plus $41.8 million for net working capital.
· The Starfish acquisition closed on March 31, 2005, for consideration of $41.7 million.
The Partnership completed the following two acquisitions in 2004 which are included in the results of operations from their dates of acquisition:
· The East Texas acquisition closed on July 30, 2004, for consideration of $240.7 million.
· The Hobbs acquisition closed April 1, 2004, for consideration of $2.3 million.
Prior to 2004 the Partnership completed four additional acquisitions which are reflected in the results of operations from their respective acquisition dates.
Results of Operations
Management evaluates performance on the basis of net operating margin (a non-GAAP financial measure), which is defined as income (loss) from operations, excluding facility cost, selling, general and administrative expense, depreciation, amortization, impairments and accretion of asset retirement obligations. These charges have been excluded for the purpose of 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 our expected future results of operations, or that we will not, in fact, incur such charges in future periods.
Year ended December 31, 2006, compared to the year ended December 31,
The following reconciles this non-GAAP financial measure to the most comparable GAAP financial measure for the years ended December 31, 2006 and 2005 (in thousands):
MarkWest Hydrocarbon Standalone
Revenue. Revenue decreased $2.7 million, or 1%, for the year ended December 31, 2006, compared to the corresponding period in 2005. We realized a $14.5 million decrease in our gas marketing business due primarily to lower prices and volumes of $0.38/MMBtu ($2.0 million) and 4,200 MMBtu/d ($12.5 million), respectively. The $19.1 million decrease in revenues in our wholesale business can be attributed primarily to the expiration of a marketing arrangement that resulted in lower volumes of 61,000 Gal/d. This decrease was partially offset by a price increase of approximately $0.05/Gal. These decreases were partially offset by an increase in our frac spread NGL revenues of $19.8 million, an increase primarily the result of increases in prices ($0.13/Gal), offset slightly by a decrease in volumes (1,500/Gal/d). Additionally, the revaluation of our long-term shrink obligation increased revenue by $5.8 million in the year ended December 31, 2006, compared to a $5.3 million decrease in 2005, resulting in an $11.1 million increase for the period-over-period comparison.
Derivative gain (loss). Gains from derivative instruments increased $6.1 million during the year ended December 31, 2006, compared to the corresponding period in 2005. This increase in gains was primarily due to the mark-to-market adjustments resulting from our election not to adopt hedge accounting treatment on our derivative instruments. The mark-to-market adjustments resulted in a $4.1 million increase in unrealized gains, which are non-cash items, and a $2.0 million decrease in realized losses, when comparing 2006 to 2005 results.
Purchased product costs. Purchased product costs decreased $18.8 million, or 7%, for the year ended December 31, 2006, compared to the corresponding period in 2005. The decrease was primarily due to our natural gas marketing business which reflected a decrease of $14.3 million. This was primarily due to a decrease in prices and volumes of $0.41/MMBtu ($2.1 million) and 4,200 MMBtu/d ($12.2 million), respectively. Additionally, our wholesale business revenues decreased $18.6 million which was driven by decreased volumes of nearly 61,000 Gal/d, partially offset by increased prices of $0.06/Gal. These decreases were partially offset by increases in our frac spread purchase product costs of $8.3 million, resulting primarily from increased prices and an increase in our unrealized losses on our derivative mark-to-market adjustments of $5.8 million.
Facility expenses. Facility expenses increased $1.1 million, or 5%, during the year ended December 31, 2006, compared to the corresponding period of 2005. The primary reason for the increase was due to higher Siloam storage fees ($0.7 million), higher Kenova, Boldman and Cobb plant processing fees ($0.8 million), and higher ALPS transportation fees ($0.2 million). These increases were partially offset by reduced inventory losses ($0.6 million).
Selling, general and administrative expenses. Selling, general and administrative expenses increased by $7.1 million, or 60%, during the year ended December 31, 2006, compared to the corresponding period in 2005. This increase was primarily due to a $6.1 million non-cash increase to the participation plan compensation expense as a result of the Partnership’s increased market value and increased labor and benefit costs of $0.9 million.
Income taxes. Income tax expense increased by $6.9 million due to higher pre-tax book income for the year ended December 31, 2006, compared to the corresponding period of 2005. The 2006 estimated annual effective income tax rate varies from the statutory rate mostly due to a change in the valuation allowance associated with the state net operating losses.
MarkWest Energy Partners
Revenue. Revenue increased $69.4 million, or 14%, for the year ended December 31, 2006, compared to the corresponding period of 2005, mostly due to the Partnership’s Javelina acquisition in November 2005, which contributed $55.1 million. Additionally, the start-up of several new gathering system expansions in East Texas resulted in a $34.1 million increase in revenue. These increases were partially offset by a decrease in Other Southwest of $23.1 million, which is mostly attributable to lower natural gas sales.
Derivative gain (loss). Gains from derivative instruments increased $7.5 million during the year ended December 31, 2006, compared to the corresponding period in 2005. This increase in gains was primarily due to the mark-to-market adjustments resulting from our electing not to adopt hedge accounting treatment on our derivative instruments. The mark-to-market adjustments resulted in a $0.6 million decrease in unrealized losses, which are non-cash items, and a $6.9 million increase in realized gains, when comparing 2006 to 2005 results.
Purchased product costs. Purchased product costs decreased $44.6 million, or 12%, during the year ended December 31, 2006, compared to the corresponding period of 2005. This decrease was primarily due to a $23.6 million decrease in Oklahoma driven by an 18% decrease in purchase prices ($1.28/MMBtu); and a $25.3 million decrease in Other Southwest driven by lower natural gas sales. These decreases were partially offset by a $5.2 increase in Appalachia due to increases in both prices ($0.10/Gal) and volumes (5,000 Gal/d).
Facility expenses. Facility expenses increased approximately $12.1 million, or 25%, during the year ended December 31, 2006, compared to the corresponding period of 2005. This increase was primarily due to the Partnership’s November 2005 Javelina Acquisition, which contributed $9.0 million; a $5.2 million increase related to the new Carthage gas processing plant in East Texas, which started operations on January 1, 2006, and a $3.0 million increase in Oklahoma due primarily to increases in compression and sales. These increases were partially offset by a $5.4 million decrease in Appalachia due to costs incurred to repair the ALPS pipeline in 2005.
Selling, general and administrative expense. Selling, general and administrative expenses increased $22.6 million, or 105%, during the year ended December 31, 2006, relative to the comparable period in 2005. The increase is primarily due to higher non-cash, equity-based compensation expense of $12.0 million, primarily due to the Partnership’s increased market value; increases in labor costs of $4.9 million related to increased costs for our existing employees plus the cost of additional personnel necessary to support our growth and strategic objectives; higher insurance expense and taxes of $2.4 million; and a one-time charge to terminate the old headquarters lease of $0.8 million.
Depreciation. Depreciation expenses increased $10.5 million, or 54%, during the year ended December 31, 2006, compared to the corresponding quarter of 2005, primarily due to the Partnership’s November 2005 Javelina Acquisition, which contributed $5.4 million; and $2.9 million in East Texas primarily related to the to the new Carthage gas processing
plant and Blocker gathering system.
Earnings (losses) from unconsolidated affiliates. Earnings (losses) from unconsolidated affiliates are primarily related to the Partnership’s investment in Starfish, a joint venture with Enbridge Offshore Pipelines LLC. The Partnership accounts for its 50% interest using the equity method, and the financial results for Starfish are included as earnings (losses) from unconsolidated affiliates. During the year ended December 31, 2006, the Partnership’s earnings from unconsolidated affiliates increased $7.5 million due to the restoration of operations resulting from the completion of the majority of repairs necessary after the 2005 hurricane season.
Interest expense and amortization of deferred financing costs (a component of interest expense). Interest and amortization expense increased $20.5 million during the year ended December 31, 2006, relative to the comparable period in 2005, primarily due to increased debt levels resulting from the financing of our November 2005 Javelina acquisition and higher interest rates. The increase in the amortization relative to the comparable period in 2005 is attributable to deferred financing costs associated with our debt refinancing completed in 2006. Deferred financing costs are being amortized over the terms of the related obligations, which approximate the effective interest method.
Miscellaneous income. Miscellaneous income increased by $11.0 million during the year ended December 31, 2006, relative to the comparable period in 2005, due almost entirely to the Partnership recognizing $11.0 million of income from insurance claims, net of Starfish insurance premiums, recovered as a result from damages from Hurricane Rita.
Texas Margin tax. The State of Texas passed a new tax law that subjects the Partnership to an entity-level tax on the portion of its income that is generated in Texas. We recorded a deferred tax liability of $0.8 million for the year ended December 31, 2006, related to the Partnership’s temporary differences that are expected to reverse in future periods.
Year ended December 31, 2005, compared to the year ended December 31,
The following includes reconciliation to the most comparable GAAP financial measure of this non-GAAP financial measure for the years ended December 31, 2005 and 2004 (in thousands):
MarkWest Hydrocarbon Standalone
Revenues. Revenues increased $59.3 million, or 27%, for the year ended December 31, 2005, compared to the corresponding period of 2004. Higher volumes and better pricing drove revenue in our wholesale propane marketing business, representing a $30.9 million increase in revenue, and our gas marketing business, representing an $18.8 million increase. NGL product revenues increased $18.5 million due to favorable pricing, offset by a decrease in volumes. Increases to revenues were offset by a $5.2 million unfavorable mark-to-market adjustment to replacement gas that resulted from an increase in natural gas prices, and a $1.0 million decrease in Michigan operations, primarily from a reduction in volumes.
Derivative gain (loss). Losses from derivative instruments decreased $2.4 million for the year ended December 31, 2005, compared to the corresponding period in 2004. This decrease in losses was primarily due to the mark-to-market adjustments resulting from our election not to adopt hedge accounting treatment on our derivative instruments. The mark-to-market adjustments resulted in a $0.1million decrease in unrealized losses, which are non-cash items, and a $2.3 million decrease in realized losses, when comparing 2005 to 2004 results.
Purchased product costs. Purchased product costs increased $72.2 million, or 39%, for the year ended December 31, 2005, compared to the corresponding period of 2004. The increase was primarily due to volumes from our wholesale propane marketing business, a $30.7 million increase and our gas marketing business, an $18.1 million increase. NGL
product costs raised $23.2 million because of higher pricing, offset by reduced volumes.
Facility expenses. Facility expenses decreased by approximately $3.4 million, or 14%, during the year ended December 31, 2005, compared to corresponding period of 2004. The decrease was the result of a $1.4 million favorable fuel reimbursement at our Kenova, Cobb and Boldman facilities, a reduction to inventory losses at the Appalachia Liquids Pipeline System (ALPS) of $0.7 million, a net reduction to Siloam fractionation fees and Kenova and Boldman processing fees of $1.6 million, and a net decrease of costs in Michigan of $0.2 million, offset by an increase to inventory losses at Siloam of $0.5 million.
Selling, general and administrative expenses. Selling, general and administrative expenses decreased by $0.2 million, or 2%, during the year ended December 31, 2005, compared to the corresponding period of 2004 as a result of a decrease in compensation expense attributed to the Participation Plan and the 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan, and an increase to allocations of selling, general and administrative expenses to the Partnership.
Income taxes. Income tax benefit increased by $1.9 million due to lower pre-tax book income for the year ended December 31, 2005, compared to the corresponding period of 2004. The 2005 estimated annual effective income tax rate varies from the statutory rate mostly due to a change in the valuation allowance associated with state net operating losses.
MarkWest Energy Partners
Revenues. Revenues for the year ended December 31, 2005, were higher by $198.8 million, or 66%, compared to 2004. The increase was primarily due to higher volumes and natural gas prices in the Partnership’s Oklahoma operations, $80.3 million, and Other Southwest operations, $37.2 million, as well as operating the East Texas system for a full year, $64.3 million. Revenues reflected nine months of activity during 2005 compared to two months of activity during 2004. Revenue also increased in Oklahoma during the year ended December 31, 2005 relative to the corresponding period of 2004 due to increased well volumes contracted to the gathering system, higher crude oil prices enhancing condensate sales and higher liquids revenue that resulted from ethane recovery during 2005 versus ethane rejection during 2004 that contributed to incremental revenue of $42.0 million. In addition, Other Southwest revenues increased $21.3 million due to a 27% increase in natural gas volumes, primarily on the Appleby and Edwards gathering systems.
Derivative gain (loss). Losses from derivative instruments increased $1.0 million for the year ended December 31, 2005, compared to the corresponding period in 2004. This increase in losses was primarily due to the mark-to-market adjustments resulting from our electing not to adopt hedge accounting treatment on our derivative instruments. The mark-to-market adjustments resulted in a $0.6 million increase in unrealized losses, which are non-cash items, and a $0.4 million increase in realized losses, when comparing 2005 to 2004 results.
Purchased product costs. Purchased product costs were higher during the year ended December 31, 2005, by $155.3 million, or 73%, compared to 2004. The combination of an increase in purchased volumes and price contributed to increases in Oklahoma and Other Southwest, primarily Appleby and Edwards, of $75.5 million and $37.1 million, respectively. In addition, the Partnership’s July 30, 2004, East Texas system acquisition had incremental purchased product costs of $35.3 million due, in part, to being operational for a full year, but also higher prices.
Facility expenses. Facility expenses increased approximately $18.1 million, or 60%, during the year ended December 31, 2005, relative to 2004. East Texas accounted for $7.2 million of the increase, related to operating the facility for a full year, as well as performing repairs and a global overhaul of our compressors. Appalachia increased $5.9 million due, in part, to repairs to the ALPS pipeline. Gulf Coast, acquired November 1, 2005, contributed $2.2 million to the increase. Oklahoma, $1.3 million, and Other Southwest, $1.3 million, increased due to repairs and an overhaul of compressors.
Selling, general and administrative expenses. Selling, general and administrative expenses, which are not allocated to segments by the Partnership, increased by $5.4 million, or 34%, during the year ended December 31, 2005, compared to 2004 as a result of the increase in incentive compensation expense of $1.9 million, and audit and external Sarbanes-Oxley related costs of $2.1 million.
Depreciation. Depreciation expense increased $4.0 million, or 26%, during the year ended December 31, 2005, compared to 2004 primarily due to the Partnership’s 2004 East Texas acquisition, $3.3 million, and 2005 Gulf Coast acquisition, $1.1 million. These changes were offset by a decrease in depreciation in Appalachia, due to accelerated depreciation in 2004 for the old Cobb facility.
Earnings (losses) from unconsolidated affiliates. Earnings (losses) from unconsolidated affiliates are primarily related to the Partnership’s investment in Starfish, a joint venture with Enbridge Offshore Pipelines LLC. The Partnership accounts for its 50% interest using the equity method, and the financial results for Starfish are included as earnings (losses) from unconsolidated affiliates. The Partnership completed their acquisition of Starfish on March 31, 2005. During the year ended December 31, 2005, the Partnership’s losses from unconsolidated affiliates were by $2.2 million.
Interest expense and amortization of deferred financing costs (a component of interest expense). Interest and amortization expense increased $14.8 million during the year ended December 31, 2005, relative to the comparable period in 2004, primarily due to increased debt levels resulting from the financing of our 2005 and 2004 acquisitions and to higher interest rates in 2005. The Partnership also incurred approximately $1.0 million in 2005 from penalty interest expense on the senior debt. The increase in the amortization of deferred financing costs in 2005, relative to the comparable period in 2004, is attributable to costs associated with our debt refinancing completed in the fourth quarter of 2005.
Critical Accounting Policies and Estimates Our discussion and analysis of financial condition and results of operations are based on our consolidated financial statements, prepared in accordance with accounting principles generally accepted in the United States of America and contained within this report. The preparation of these statements requires us to make certain assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. Our significant accounting policies are detailed in Note 2 to our consolidated financial statements. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.
Revenue Recognition
The Company generates the majority of its revenues from natural gas gathering and processing, NGL fractionation, transportation and storage, and crude oil gathering and transportation. While all of these services constitute midstream energy operations, the Partnership provides its services pursuant to six different types of arrangements. In many cases, the Partnership provides services under contracts that contain a combination of more than one of the arrangements. The terms of the Partnership’s contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements. Under all of the arrangements, revenue is recognized at the time the product is delivered and title is transferred. It is upon delivery and title transfer that the Partnership meets all four revenue recognition criteria, and it is at such time that the Partnership recognizes revenue.
Revenue and Expense Accruals
We routinely make accruals based on estimates for both revenues and expenses due to the timing of compiling billing information, receiving certain third party information and reconciling our records with those of third parties. The delayed information from third parties includes, among other things, actual volumes purchased, transported or sold, adjustments to inventory and invoices for purchases, actual natural gas and NGL deliveries and other operating expenses. We make accruals to reflect estimates for these items based on our internal records and information from third parties. Most of the estimated accruals are reversed in the following month when actual information is received from third parties and our internal records have been reconciled.
Derivative Instruments
Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, (“SFAS 133”) established accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception. To the extent derivative instruments designated as cash flow hedges are effective, changes in fair value are recognized in other comprehensive income until the underlying hedged item is recognized in earnings. Effectiveness is evaluated by the derivative instrument’s ability to offset changes in fair value or cash flows of the underlying hedged item. Any change in the fair value resulting from ineffectiveness is recognized immediately in earnings. Changes in the fair value of derivative instruments designated as fair value hedges, as well as the changes in the fair value of the underlying hedged item, are recognized currently in earnings. Any differences between the
changes in the fair values of the hedged item and the derivative instrument represent gains or losses from ineffectiveness. To the extent that the Company elects hedge accounting treatment for specific derivatives, the Company formally documents, designates and assesses the effectiveness. As of December 31, 2006 and 2005, no transactions had been designated for hedge accounting treatment.
In the course of normal operations, the Company routinely enters into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs, that under SFAS 133, qualify for and are designated as a normal purchase and sales contracts. In general, the Company exempts these types of contracts from the mark-to-market requirements of SFAS 133 and instead accounts for them using accrual accounting.
For contracts that are not designated as normal purchase and sales contracts, the change in market value of the contracts is recorded as a component of revenue or purchase product costs. The following table summarizes our handling of derivative instruments as presented in our accompanying consolidated statements of operations:
Transaction Type
Realized gain (loss)
Unrealized gain (loss)
Sales:
Fixed Physical Forwards
Revenue
Derivative gain (loss)
All other derivative instruments
Derivative gain (loss)
Derivative gain (loss)
Purchases:
Fixed Physical Forwards
Purchase product costs
Purchase product costs
All other derivative instruments
Purchase product costs
Purchase product costs
Derivative gain (loss) in the table above are included in total revenues in the accompanying consolidated statements of operations.
Income Taxes
The Company accounts for income taxes under the asset and liability method pursuant to the SFAS No. 109, Accounting for Income Taxes (“SFAS 109”). Under SFAS 109, deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realizability of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value.
Intangible Assets
The Company’s intangible assets are comprised of customer contracts and relationships acquired in business combinations, recorded under the purchase method of accounting at their estimated fair values at the date of acquisition. Using relevant information and assumptions, management determines the fair value of acquired identifiable intangible assets. Fair value is generally calculated as the present value of estimated future cash flows using a risk-adjusted discount rate. The key assumptions include contract renewals, economic incentives to retain customers, historical volumes, current and future capacity of the gathering system, pricing volatility, and the discount rate. Amortization of intangibles with definite lives is calculated using the straight-line method over the estimated useful life of the intangible asset. The estimated economic life is determined by assessing the life of the assets to which the contracts or relationships relate, the likelihood of renewals, competitive factors, regulatory or legal provisions, and maintenance and renewal costs.
Impairment of Long-Lived Assets
The Company evaluates its long-lived assets, including intangibles, for impairment when events or changes in circumstances warrant such a review. A long-lived asset group is considered impaired when the estimated undiscounted cash flows from such asset group are less than the asset group’s carrying value. In that event, a loss is recognized to the extent that the carrying value exceeds the fair value of the long-lived asset group. Fair value is determined primarily using estimated discounted cash flows. Management considers the volume of reserves behind the asset and future NGL product and natural gas prices to estimate cash flows. The amount of additional reserves developed by future drilling activity depends, in part, on expected natural gas prices. Projections of reserves, drilling activity and future commodity prices are inherently subjective and contingent upon a number of variable factors, many of which are difficult to forecast. Any significant variance in any of these assumptions or factors could materially affect future cash flows, which could result in the impairment of an asset.
For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value, less the cost to sell, to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change.
Stock and Incentive Compensation Plans
The Company adopted the SFAS No. 123R, Accounting for Stock-Based Compensation (“SFAS 123R”) on January 1, 2006, using the modified prospective method. Prior to adopting SFAS 123R, the Company elected to measure compensation expense for equity-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25 (“APB 25”), Accounting for Stock Issued to Employees.
Under SFAS 123R, compensation expense is based on the fair value of the award. SFAS 123R classifies
stock-based compensation as either equity or liability awards. The fair value on the date of grant for an award classified as equity is recognized over the requisite service period, with a corresponding credit to equity (generally, paid-in capital). The requisite service period is the period during which an individual is required to provide a service in exchange for the award. The requisite service period is estimated based on an analysis of the terms of the share-based payment award. Compensation expense for a liability award is based on the award’s fair value, remeasured at each reporting date until the date of settlement. Additionally, compensation expense is reduced for an estimate of expected award forfeitures.
MarkWest Hydrocarbon
Stock Options
Historically, stock options were issued under the Company’s 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan, (together the “1996 Plans”). In June 2006 shareholders approved the 2006 Stock Incentive Plan (the “2006 Plan”) to replace the 1996 Plans. Under SFAS 123R, our stock options are categorized as equity awards. Compensation expense for stock options is measured based on the grant date fair value and is amortized into earnings over the service period as the options vest. While it was determined in 2005 that the Company does not intend to issue stock options in the future, they are available for issuance under the 2006 Plan. On December 1, 2006 a board resolution provided for the accelerated vesting of 14,950 unvested stock option grants. Consequently, as of December 31, 2006 the Company had no remaining unvested options or any unrecognized compensation expense pertaining to options.
Restricted Stock
The Company issued restricted stock under the 1996 Plans until the adoption of the 2006 Plan at which point all new shares are, and will be, issued pursuant to the rules of the 2006 Plan. Under SFAS 123R, our restricted stock qualifies as an equity award. Accordingly, it is measured at the grant date fair value and the associated compensation expense is recognized over the requisite service period. The restricted stock vests equally over a three year period.
Participation Plan
The Company has also entered into arrangements with certain directors and employees of the Company referred to as the Participation Plan. Under this plan, the Company sells subordinated units of the Partnership or interests in the Partnership’s general partner, under a purchase and sale agreement. Both the subordinated unit and general partner interest transactions are considered compensatory arrangements due to the put-and-call provisions and the associated valuation being based on a formula instead of an independent third party valuation. The subordinated units convert to common units after a holding period. Historically, the Company has settled the subordinated units for cash when individuals leave the Company. The general partner interests have no definite term, but historically have been settled for cash when the employee leaves the Company. Under SFAS 123R, the subordinated units and general partner interests are classified as liability awards. As a result, the Company is required to mark to market the subordinated unit and general partner interest valuations at the end of each period.
Under Topic 1-B of the codification of the Staff Accounting Bulletins, Allocation of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity, some portion of compensation expense related to services provided by MarkWest Hydrocarbon’s employees and directors recognized under the Participation Plan should be allocated to the Partnership. The allocation is based on the percent of time each employee devotes to the Company. Compensation attributable to interests sold to individuals who serve on both the board of MarkWest Hydrocarbon and the Board of Directors of the Partnership’s general partner is allocated equally.
MarkWest Energy Partners
Restricted Units
The Partnership issues restricted units under the MarkWest Energy Partners, L.P. Long-Term Incentive Plan. A restricted unit is a “phantom” unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the Compensation Committee, cash equivalent to the value of a common unit. The restricted units are treated as liability awards under SFAS 123R. As a result, the Partnership is required to mark to market the awards at the end of each reporting period. Compensation expense is remeasured for the phantom unit grants using the market price of MarkWest Energy Partners’ common units at each reporting date. The fair value of the units awarded is amortized into earnings over the period of service and is adjusted monthly for the change in the fair value of the unvested units granted. The phantom units vest equally over a three year period.
Vesting is accelerated for certain employees, if specified performance measures are met. The accelerated vesting criteria provisions are based on annualized distribution goals. If the Partnership’s distributions are at or above the goal for a certain number of consecutive quarters, vesting of the employee’s phantom units is accelerated. The general partner of the Partnership may also elect to accelerate the vesting of outstanding awards, which results in an immediate charge to operations for the unamortized portion of the award.
To satisfy common unit awards, the Partnership will issue new common units, acquire common units in the open market, or use common units already owned by the general partner.
Liquidity and Capital Resources
MarkWest Hydrocarbon Standalone
Our primary source of liquidity to meet operating expenses and fund capital expenditures is cash flow from operations, principally from the marketing of NGL and quarterly distributions received from MarkWest Energy Partners. We believe that cash flow from operations and distributions from the Partnership will be sufficient to fund capital expenditures and other working capital expenditures for the foreseeable future.
On October 13, 2006, the Company completed the repurchase of a 0.5% interest in the general partner. This purchase resulted in an increase in our ownership level in the general partner to 89.7%. As of December 31, 2006, we still owned 89.7% of the general partner of MarkWest Energy Partners, excluding interests held by certain employees and directors but deemed owned by the Company through the Participation Plan. The general partner of MarkWest Energy Partners owns the 2% general partner interest and all of the incentive distribution rights. The incentive distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they entitle us to receive 13% of all cash distributed in a quarter after each unit has received $0.275 for that quarter; 23% of all cash distributed after each unit has received $0.3125 for that quarter; and 48% of all cash distributed after each unit has received $0.375 for that quarter. For the year ended December 31, 2006, we received $8.8 million in distributions from our limited units and $11.3 million from our general partner interest, of which $10.1 million represented payments on incentive distribution rights.
Cash flows generated from our NGL marketing and natural gas supply operations are subject to volatility in energy prices, especially prices for NGLs and natural gas. Our cash flows are enhanced in periods when NGL prices are high relative to the price of the natural gas we purchase to satisfy our “keep-whole” contractual arrangements in Appalachia. Conversely, they are reduced in periods when the NGL prices are low relative to the price of natural gas we purchase to satisfy such contractual arrangements. Under “keep-whole” contracts, we retain and sell the NGLs produced in our processing operations for third-party producers, and then reimburse or “keep-whole” the producers for the energy content of the NGLs removed through the re-delivery to the producers of an equivalent amount (on a Btu basis) of dry natural gas. Generally, the value of the NGLs extracted is greater than the cost of replacing those Btus with dry gas, resulting in positive operating margins under these contracts. Periodically, natural gas becomes more expensive, on a Btu equivalent basis, than NGL products, and the cost of keeping the producer “whole” can result in operating losses.
Debt
In October 2004 the Company entered into a $25.0 million senior credit facility with a term of one year. The $25.0 million revolving facility has a variable interest rate based on the base rate or the London Inter Bank Offering Rate (“LIBOR”), as discussed below. In October, November and December 2005, the Company entered into the first, second and third amendments to the credit agreement. The first amendment to the credit facility extended the term of the original agreement to November 15, 2005. The second amendment reduced the lending amount from $25.0 million to $16.0 million, of which $6.0 million is committed to a letter of credit, leaving $10.0 million available for revolving loans. The second amendment also extended the term of the revolving credit to December 30, 2005. The third amendment extended the term of the revolving credit to January 31, 2006, and reduced the lending amount from $16.0 million to $13.5 million, of which $6.0 million is committed to a letter of credit, leaving $7.5 million available for revolving loans. On January 31, 2006, the Company entered into the first amended and restated credit agreement which reinstated the maximum lending limit of $25.0 million for a one year term. On August 18, 2006, the Company entered into the second amended and restated credit facility which increased the size of the facility from $25 million to $55 million, increasing the term of the agreement to three years and allowing the flexibility for MarkWest Hydrocarbon to directly invest in additional units of MarkWest Energy Partners to fund future growth opportunities.
On February 16, 2007, the Company entered into the first amendment to the second amended and restated credit agreement, increasing the term by one year to August 20, 2010, and providing an additional $50 million of credit to enable the Company to meet margin requirements associated with its derivative instruments.
The Company Credit Facility bears interest at a variable interest rate, plus basis points. The variable interest rate typically is based on the LIBOR; however, in certain borrowing circumstances the rate would be based on the higher of a) the Federal Funds Rate plus 0.5-1%, and b) a rate set by the Facility’s administrative agent, based on the U.S. prime rate. The basis points correspond to the ratio of the Revolver Facility Usage to the Borrowing Base, ranging from 0.50% to 1.75% for Base Rate loans, and 1.50% to 2.75% for Eurodollar Rate loans. The Company pays a quarterly commitment fee on the unused portion of the credit facility at an annual rate ranging from 37.5 to 50.0 basis points.
Under the provisions of the credit facility, the Company is subject to a number of restrictions on its business, including its ability to grant liens on 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 (other than subordinated indebtedness); make distributions on equity investments; declare or make, directly or indirectly, any restricted distributions.
At December 31, 2006, we had no debt outstanding on the Company Credit Facility and $28.0 million available for borrowing.
We spent $0.3 million for capital expenditures for the year ending December 31, 2006. We have budgeted $3.6 million for 2007, principally for computer hardware and software upgrades. We believe that cash on hand, cash received from quarterly distributions (including the incentive distribution rights) from MarkWest Energy Partners and projected cash generated from our marketing operations will be sufficient to meet our working capital requirements and fund our required capital expenditures, if any, for the foreseeable future. Cash generated from our marketing operations will depend on our operating performance, which will be affected by prevailing commodity prices and other factors, some of which are beyond our control.
MarkWest Energy Partners
The Partnership’s primary source of liquidity to meet operating expenses and fund capital expenditures (other than for certain acquisitions) are cash flows generated by its operations and its access to equity and debt markets. The equity and debt markets, public and private, retail and institutional, have been the Partnership’s principal source of capital used to finance a significant amount of its growth, including acquisitions.
On December 29, 2005, MarkWest Energy Operating Company, L.L.C., a wholly owned subsidiary of MarkWest Energy Partners L.P., entered into the fifth amended and restated credit agreement (“Partnership Credit Facility”). It provides for a maximum lending limit of $615.0 million for a five-year term. The credit facility included a revolving facility of $250.0 million and a $365.0 million term loan. The term loan portion of the Partnership Credit Facility was repaid without penalty in October 2006 using a portion of the proceeds from the debt and equity offerings in 2006 leaving the revolving facility intact. Under certain circumstances, the Partnership Credit Facility can be increased from $250.0 million up to $450.0 million. The credit facility is guaranteed by the Partnership and all of the Partnership’s subsidiaries and is collateralized by substantially all of the Partnership’s assets and those of its subsidiaries. The borrowings under the credit facility bear interest at a variable interest rate, plus basis points. The variable interest rate typically is based on the LIBOR; however, in certain borrowing circumstances the rate would be based on the higher of a) the Federal Funds Rate plus 0.5-1%, and b) a rate set by the Partnership Credit Facility’s administrative agent, based on the U.S. prime rate. The basis points correspond to the ratio of the Partnership’s Consolidated Senior Debt (as defined in the Partnership Credit Facility) to Consolidated EBITDA (as defined in the Partnership Credit Facility), ranging from 0.50% to 1.50% for Base Rate loans, and 1.50% to 2.50% for Eurodollar Rate loans. The basis points will increase by 0.50% during any period (not to exceed 270 days) where the Partnership makes an acquisition for a purchase price in excess of $50.0 million (“Acquisition Adjustment Period”). Borrowings under the Partnership Credit Facility were used to finance, in part, the Javelina acquisition discussed above. On December 31, 2006, the available borrowing capacity under the Partnership Credit Facility was $218.4 million.
Cash generated from operations, borrowings under the Partnership Credit Facility and funds from the Partnership’s private and public equity and debt offerings are its primary sources of liquidity. The timing of the Partnership’s efforts to raise equity in 2006 was influenced by its failure to file in a timely manner its Annual Report on Form 10-K for the year ended December 31, 2004, and its quarterly report on Form 10-Q for the quarter ending March 31, 2005. However, as of October 11, 2006, the Partnership has the ability to incorporate by reference information from its future Securities and Exchange Commission (“SEC”) filings into new registration statements in order to raise capital through a public offering. To raise additional capital through public debt or equity offerings, the Partnership is eligible to file a Form S-3, which is a short-form type of registration statement. On November 15, 2006, the Partnership filed a shelf registration statement on Form S-3, which became effective immediately and allows it to attempt to raise up to $500 million by issuing debt and equity securities in the future in registered offerings.
At December 31, 2006, the Partnership and its wholly owned subsidiary MarkWest Energy Finance Corporation also
have two series of senior notes outstanding, $225.0 million at a fixed rate of 6.875%, which will mature in November, 2014 (the “2014 Senior Notes”) and senior notes of $271.9 million, net of an unamortized discount of $3.1 million, at a fixed rate of 8.5%, due in July 15, 2016 (the “2016 Senior Notes”). The proceeds from these notes were used to reduce the Partnership’s outstanding debt under its credit facility. Subject to compliance with certain covenants, the Partnership may issue additional notes from time to time under the indenture pursuant to Rule 144A and Regulation S under the Securities Act of 1933.
The 2016 Senior Notes will mature on July 15, 2016, and interest is payable each July 15 and January 15, commencing January 15, 2007. The Partnership closed this private placement of $200 million on July 6, 2006 and it completed the private placement of an additional $75 million under the indenture on October 20, 2006. The net proceeds from the July and October 2006 private placements were approximately $191.2 million and $74.5 million, respectively, after deducting the initial purchasers’ discounts and legal, accounting and other transaction expenses. The Partnership used the net proceeds from the offerings to repay the term debt under the Partnership Credit Facility, and used the remaining net proceeds to fund both capital expenditures and general corporate expenses. Affiliates of several of the initial purchasers, including RBC Capital Markets Corporation, J.P. Morgan Securities Inc. and Wachovia Capital Markets, LLC, are lenders under the Partnership Credit Facility.
The indenture governing the 2014 Senior Notes and the 2016 Senior Notes limits the activity of the Partnership and its restricted subsidiaries. The provisions of such indenture place limits on the ability of the Partnership and its restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of the Partnership’s restricted subsidiaries to pay dividends, make loans or transfer property to the Partnership; engage in transactions with the Partnership’s affiliates; sell assets, including equity interests of the Partnership’s subsidiaries; make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets.
On July 6, 2006, the Partnership completed its underwritten public offering of 6.0 million common units (the “Common Unit Offering”) at a public offering price of $19.88 per common unit. In addition, on July 12, 2006, the Partnership completed the sale of an additional 600,000 common units to cover over-allotments in connection with the Common Unit Offering. The sale of units resulted in total gross proceeds of $131.2 million, and net proceeds of $123.3 million after the underwriters’ commission and legal, accounting and other transaction expenses. The Partnership used the net proceeds from the offering, and the proceeds from the capital contribution from its general partner to maintain its 2% general partner interest in the Partnership, to retire a portion of the term debt under the Partnership Credit Facility.
The Partnership’s ability to pay distributions to its unitholders and to fund planned capital expenditures and make acquisitions will depend upon its future operating performance. That, in turn, will be affected by prevailing economic conditions in the Partnership’s industry, as well as financial, business and other factors, some of which are beyond its control.
The Partnership used $77.4 million for capital expenditures in 2006, exclusive of any acquisitions, consisting of $75.1 million for expansion capital and $2.3 million for sustaining capital. Expansion capital includes expenditures made to expand or increase the efficiency of the existing operating capacity of our assets, or facilitate an increase in volumes within our operations, whether through construction or acquisition. The Partnership has budgeted between $230.0 and $240.0 million for expenditures in 2007 consisting of approximately $235.0 million for expansion capital and $5.0 million of sustaining capital. The Partnership plans to use between $150.0 and $170.0 million of its expansion capital budget to fund the construction of the Woodford gathering system. Sustaining capital includes expenditures to replace partially or fully depreciated assets in order to extend their useful lives.
Cash Flows
Net cash provided by operating activities increased $149.1 million during the year ended December 31, 2006, compared to the year ended December 31, 2005. This increase resulted primarily from increases in both our net income and that of the non-controlling interest of the Partnership of $76.0 million; an increase in non-cash equity-based compensation expense of $17.5 million, primarily due to the Partnership’s increased market value; an increase in income tax expense of $7.8 million; and
an increase in our unrealized gains on derivative instruments of $5.2 million and increases in the changes of our operating assets and liabilities totaling $43.9 million.
Net cash used in investing activities decreased by $323.8 million during the year ended December 31, 2006, compared to the year ended December 31, 2005, primarily due to our $356.9 million acquisition of Javelina in November 2005. In December 2006 the Partnership completed its acquisition of the Grimes gathering system using cash of $15.0 million. The Partnership used cash of $80.1 million for capital expenditures in 2006, including $21.6 million for the initial construction of the Woodford gathering system. In 2005, the Partnership used cash of $71.3 million for capital expenditures, primarily for the construction of a new processing plant and gathering systems in East Texas to handle our future contractual commitments and construction of the new replacement Cobb processing facility in Appalachia.
Net cash used in financing activities increased $453.1 million during the year ended December 31, 2006, compared to the year ended December 31, 2005. The increase was due primarily to net proceeds from additional long-term debt and private placements in 2005 to fund our acquisitions. Distributions to the Partnership’s unitholders increased to $43.5 million in 2006 from $26.1 million in 2005. Dividends to shareholders increased to $9.7 million during the year ended December 31, 2006 compared to $4.3 million in the prior year period.
Total Contractual Cash Obligations
A summary of our total contractual cash obligations as of December 31, 2006, is as follows (in thousands):
(1) Assumes that our outstanding borrowings at December 31, 2006, will remain outstanding until their respective maturity dates and that we will incur interest expense at 8.75% on the Partnership Credit Facility revolver, 6.875% on the 2014 Senior Notes and 8.25% on the 2016 Senior Notes.
Off-Balance Sheet Arrangements Other than facility and equipment leasing arrangements, we do not engage in off-balance sheet financing activities.
Matters Influencing Future Results
During August and September 2005, Hurricanes Katrina and Rita caused severe and widespread damage to oil and gas assets in the Gulf of Mexico and Gulf Coast regions. Operations of the Partnership’s unconsolidated affiliate, Starfish Pipeline Company were nominally impacted by Hurricane Katrina but were significantly impacted by Hurricane Rita. The Partnership is continuing to submit insurance claims on an on-going basis relating to both business interruption and property damage and have submitted $14.5 million in claims through January 31, 2007. The Partnership has recorded $11.0 million in insurance claims, net of Starfish insurance premiums with respect to its property loss claims, and it anticipates additional recoveries for expenses and losses incurred as repairs proceed. As of December 31, 2006, the Partnership has not recorded any insurance recoveries related to business interruption, due to the uncertainty around collection, but the Partnership has filed a claim for $3.5 million with its insurance carrier.
The loss to both offshore and onshore assets resulting from Hurricane Rita has led to substantial insurance claims within the oil and gas industry. Along with other industry participants, we have seen our insurance costs increase substantially within this region as a result of these developments. We have renewed our insurance coverage relating to Starfish during the second quarter and mitigated a portion of the cost increase by reducing our coverage and adding a broader self-insurance element to our overall coverage.
The Partnership’s affiliate, MEA operates the ALPS pipeline to transport NGLs from its Maytown gas processing plant to its 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 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 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.
MarkWest Hydrocarbon, Inc. is a corporation for federal income tax purposes. As such, our federal taxable income is subject to tax at a maximum rate of 35.0% under current law and a blended state rate of 2.8%, net of Federal benefit. We expect to have future taxable income allocated to us as a result of our investment in the Partnership and from our Appalachia processing agreements.
We anticipate using all of the federal net operating loss carryforwards from previous years for the year ended December 31, 2006. As a result, the amount of money available to provide dividends to our stockholders will decrease for future distributions.
In June 2006 the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”). The Company is currently evaluating the impact of FIN 48.
Recent Accounting Pronouncements
Refer to Note 2 of the consolidated financial statements for information regarding recent accounting pronouncements.
Effects of Inflation and Pricing
We experienced increased costs during 2006, 2005 and 2004 due to increased demand for natural gas and oil related products and services. The natural gas and oil industry is very cyclical and the demand for goods and services of natural gas and oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for natural gas and oil increase, so do all associated costs. Material changes in prices also impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans and values of properties in purchase and sale transactions. Material changes in prices can impact the value of natural gas and oil companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, continued high prices for natural gas and oil could result in increases in the costs of materials, services and personnel.
Commodity Price Sensitivity Our earnings and cash flow are dependent on sales volumes and our ability to achieve positive sales margins on the product we sell. The volumes of our sales and our margin on sales can be adversely affected by the prices of commodities, which are subject to significant fluctuation depending upon numerous factors beyond our control, including the supply of and demand for commodity products. The supply of and demand for our products can be affected by, among other things, production levels, industry-wide inventory levels, the availability of imports, the marketing of products by competitors, and the marketing of competitive fuels.
Seasonality
For the portion of our business that is affected by commodity prices, sales volumes also are affected by various other factors such as fluctuating and seasonal demands for products, changes in transportation and travel patterns and variations in weather patterns from year to year. In general, we store a portion of the propane that we produce in the summer as well as pre-purchase in the summer a portion of the natural gas that we are required to replace during the winter in accordance with
our Appalachian keep-whole processing agreements.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity price changes and to a lesser extent, interest rate changes.
Commodity Price Risk
Our primary risk management objective is to manage volatility in our cash flows. A committee comprised of members of the senior management team oversees all of our derivative activity.
We utilize a combination of fixed-price forward contracts, fixed-for-floating price swaps and options on the over-the-counter (“OTC”) market. The Company may also enter into futures contracts traded on the New York Mercantile Exchange (“NYMEX”). Swaps and futures contracts allow us to manage volatility in our margins because corresponding losses or gains on the financial instruments are generally offset by gains or losses in our physical positions.
We enter into OTC swaps with financial institutions and other energy company counterparties. We conduct a standard credit review on counterparties and have agreements containing collateral requirements where deemed necessary. We use standardized swap agreements that allow for offset of positive and negative exposures. We may be subject to margin deposit requirements under OTC agreements (with non-bank counterparties) and NYMEX positions.
The use of derivative instruments may expose us to the risk of financial loss in certain circumstances, including instances when (i) NGLs do not trade at historical levels relative to crude oil, (ii) sales volumes are less than expected requiring market purchases to meet commitments, or (iii) our OTC counterparties fail to purchase or deliver the contracted quantities of natural gas, NGLs or crude oil or otherwise fail to perform. To the extent that we enter into derivative instruments, we may be prevented from realizing the benefits of favorable price changes in the physical market. We are similarly insulated, however, against unfavorable changes in such prices.
Fair value is based on available market information for the particular derivative instrument and incorporates the commodity, period, volume and pricing. Positive (negative) amounts represent unrealized gains (losses).
MarkWest Hydrocarbon Standalone
MarkWest Hydrocarbon Standalone may enter into physical and/or financial positions to manage its risks related to commodity price exposure. Due to timing of purchases and sales, direct exposure to price volatility can be created because there is no longer an offsetting purchase or sale that remains exposed to market pricing. Through marketing and derivatives activities, direct exposure may occur naturally, or we may choose direct exposure when we favor that exposure over frac spread risk. Beginning in 2006 MarkWest Hydrocarbon Standalone pre-purchased natural gas for shrink requirements in future months and, for both natural gas and NGLs, entered into swaps and future sales agreements to manage frac spread risk. These derivative instruments are marked to market.
The following tables summarize the current derivative positions specific to MarkWest Hydrocarbon Standalone’s segment at December 31, 2006 (in thousands, except price data):
(1) Swaps represent fixed forward sales and purchases, which, in combination economically hedge our frac spread position.
(2) A weighted average is used for grouped positions.
The following table summarizes the non-current derivative positions specific to MarkWest Hydrocarbon Standalone’s segment at December 31, 2006 (in thousands, except price data):
(1) Swaps represent fixed forward sales to hedge our production of NGLs.
A summary of MarkWest Hydrocarbon Standalone’s commodity derivative instruments is provided below (in thousands):
MarkWest Hydrocarbon Standalone entered into the following derivative positions subsequent to December 31, 2006:
(1) Swaps represent fixed forward sales and purchases, which, in combination economically hedge our frac spread position.
(2) A weighted average is used for grouped positions.
MarkWest Energy Partners
The Partnership’s primary risk management objective is to reduce volatility in its cash flows arising from changes in commodity prices related to future sales of natural gas, NGLs and crude oil. Swaps and futures contracts may allow the Partnership to reduce volatility in its realized margins as realized losses or gains on the derivative instruments generally are offset by corresponding gains or losses in the Partnership’s sales of physical product. While the Partnership largely expects its realized derivative gains and losses to be offset by increases or decreases in the value of its physical sales, it will experience volatility in reported earnings due to the recording of unrealized gains and losses on its derivative positions that will have no offset. The volatility in any given period related to unrealized gains or losses can be significant to the overall results of the Partnership, however, it ultimately expects those gains and losses to be offset when they become realized.
The following tables summarize the current derivative positions specific to MarkWest Energy Partner’s segment at December 31, 2006 (in thousands, except price data):
(1) Forward sales to hedge our production.
(2) A weighted average is used for grouped positions
(3) Purchase of puts to hedge our Ethane production.
(4) Forward producer collars to hedge our production.
The following table summarizes the non-current derivative positions specific to MarkWest Energy Partner’s segment at December 31, 2006 (in thousands, except price data):
(1) Forward producer collars to hedge our production.
(2) A weighted average is used for grouped positions.
A summary of MarkWest Energy’s commodity derivative instruments is provided below (in thousands):
The Partnership entered into the following derivative positions subsequent to December 31, 2006:
(1) Forward sales to hedge our production.
(2) A weighted average is used for grouped positions.
Interest Rate
Our primary interest rate risk exposure results from the revolving portion of the Partnership Credit Facility that has a borrowing capacity of $250.0 million and was entered into on December 29, 2005. The debt related to this agreement bears interest at variable rates that are tied to either the U.S. prime rate or LIBOR at the time of borrowing. The Partnership may make use of interest rate swap agreements in the future, to adjust the ratio of fixed and floating rates in its debt portfolio.
Based on our overall interest rate exposure at December 31, 2006, a hypothetical instantaneous increase or decrease of one percentage point in interest rates applied to borrowings under our credit facility would change earnings by less than $0.1 million, net of tax, over a 12-month period.
Item 8.
Item 8. Financial Statements and Supplemental Data
Index to Consolidated Financial Statements
Report of Deloitte & Touche LLP, Independent Registered Public Accounting Firm
Report of KPMG LLP, Independent Registered Public Accounting Firm
Consolidated Balance Sheets at December 31, 2006 and 2005
Consolidated Statements of Operations for the years ended December 31, 2006, 2005 and 2004
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2006, 2005 and 2004
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2006, 2005 and 2004
Consolidated Statements of Cash Flows for the years in the period ended December 31, 2006, 2005 and
Notes to Consolidated Financial Statements for the years ended December 31, 2006, 2005 and 2004
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of MarkWest Hydrocarbon, Inc.
Denver, Colorado
We have audited the accompanying consolidated balance sheets of MarkWest Hydrocarbon, Inc. and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, comprehensive income (loss), changes in stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of MarkWest Hydrocarbon, Inc. and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for stock-based compensation in 2006 with the implementation of Statement of Financial Accounting Standards No. 123R “Share-Based Payment”.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 7, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an adverse opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ Deloitte & Touche, LLP
Denver, Colorado
March 7, 2007
Report of Independent Registered Public Accounting Firm
The Board of Directors MarkWest Hydrocarbon, Inc.:
We have audited the accompanying consolidated statements of operations, comprehensive income (loss), changes in stockholders’ equity, and cash flows of MarkWest Hydrocarbon, Inc. and its subsidiaries for the year ended December 31, 2004. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of MarkWest Hydrocarbon, Inc. and subsidiaries for the year ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.
MARKWEST HYDROCARBON, INC.
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
The accompanying notes are an integral part of these consolidated financial statements.
MARKWEST HYDROCARBON, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
The accompanying notes are an integral part of these consolidated financial statements.
MARKWEST HYDROCARBON, INC. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
MARKWEST HYDROCARBON, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
MARKWEST HYDROCARBON, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
MarkWest Hydrocarbon, Inc. (“MarkWest Hydrocarbon” or the “Company”) is an energy company primarily focused on marketing natural gas liquids (NGLs) and increasing shareholder value by growing MarkWest Energy Partners, L.P. (“MarkWest Energy Partners” or the “Partnership”), a consolidated subsidiary and publicly traded master limited partnership. MarkWest Energy Partners is engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids; and the gathering and transportation of crude oil. The Company also markets natural gas and NGLs. MarkWest Hydrocarbon and MarkWest Energy Partners provide services primarily in Appalachia, Michigan, Texas, Oklahoma, Gulf Coast and other areas of the southwest.
2. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements include the accounts of MarkWest Hydrocarbon, Inc., MarkWest Energy Partners, L.P. and all of its majority-owned subsidiaries (collectively “the Company”) and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The Company’s consolidated financial statements include the accounts of all majority-owned subsidiaries. Equity investments in which the Company exercises significant influence, but does not control and is not the primary beneficiary, are accounted for using the equity method. Intercompany balances and transactions have been eliminated.
On April 27, 2006, MarkWest Hydrocarbon announced that its Board of Directors approved the issuance of one share of common stock for each ten shares of common stock held by common stockholders. The stock was issued on May 23, 2006, to the stockholders of record as of the close of business on May 11, 2006; the ex-dividend date was May 9, 2006. 1,084,647 shares were issued at a fair value of $24.4 million, based upon the last sale price on the record date ($22.50 per share). Cash of $3,200 was paid in lieu of fractional shares, based upon the last sale price on the record date. All common stock accounts and per share data have been retroactively adjusted to give effect to the dividend of our common stock.
On January 25, 2007, the Board of the General Partner of the Partnership declared the Partnership’s two-for-one split of the Partnership’s units. The units were issued on February 28, 2007 for holders of record at the close of business on February 22, 2007. The unit split resulted in the issuance of an additional 15,603,257 common units and 600,000 subordinated units. All Partnership specific 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 to the unit split.
Non-Controlling Interest in Consolidated Subsidiary
The non-controlling interest in consolidated subsidiary on the consolidated balance sheet represents the initial investment by the partners other than MarkWest Hydrocarbon in the Partnership, plus those partners’ share of the net income of the Partnership since its initial public offering on May 24, 2002. Non-controlling interest in net income of consolidated subsidiary in the consolidated statement of operations represents those partners’ share of the net income of the Partnership.
Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates are used in accounting for, among other items, valuing identified intangible assets, determining the fair value of derivative instruments, evaluating impairments of long lived assets, establishing estimated useful lives for long-lived assets, valuing asset retirement obligations, and in determining liabilities, if any, for legal contingencies.
Cash and Cash Equivalents
The Company considers investments in highly liquid financial instruments purchased with an original maturity of 90 days or less to be cash equivalents. Such investments include money market accounts.
Inventories
Inventories are valued at the lower of weighted average cost or market. Inventories consisting primarily of crude oil
and unprocessed natural gas are valued based on the cost of the raw material. Processed natural gas inventories include material, labor and overhead. Shipping and handling costs are included in operating expenses.
Prepaid Replacement Natural Gas
Prepaid replacement natural gas consists of natural gas purchased in advance of its actual use valued using the weighted average cost method.
Property, Plant and Equipment Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of assets are capitalized. Repairs, maintenance and renewals that do not extend the useful lives of the assets are expensed as incurred. Interest costs for the construction or development of long-term assets are capitalized and amortized over the related asset’s estimated useful life. Leasehold improvements are depreciated over the shorter of the useful life or lease term. Depreciation is provided principally on the straight-line method over the following estimated useful lives:
The Company recognizes the fair value of a liability for an asset retirement obligation in the period, in which the liability is incurred, with an offsetting increase in the carrying amount of the related long-lived asset. Over time, the liability is accreted to its future value, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. The Company adopted the Financial Accounting Standards Board (“FASB”) Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (“FIN 47”), on January 1, 2005. FIN 47 clarified the accounting for conditional asset retirement obligations under Statement of Financial Accounting Standards (“SFAS”) No.143, Accounting for Asset Retirement Obligations (“SFAS 143”). A conditional asset retirement obligation is an unconditional legal obligation to perform an activity in which the timing and / or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 requires an entity to recognize a liability for a conditional asset retirement obligation if the amount can be reasonably estimated. Adopting FIN 47 had an immaterial impact on the Company.
Investment in Starfish On March 31, 2005, the Partnership acquired its non-controlling, 50% interest in Starfish Pipeline Company, LLC (“Starfish”) for $41.7 million, which is accounted for under the equity method. Differences between the Partnership’s investment and its proportionate share of Starfish’s reported equity are amortized based upon the respective useful lives of the assets to which the differences relate. The Partnership’s share of Starfish’s earnings in 2006 was $5.3 million compared to a loss of $2.2 million in 2005.
The Partnership’s accounting policy requires it to evaluate operating losses, if any, and other factors that may have occurred, that may be indicative of a decrease in value of the investment which is other than temporary, and which should be recognized even though the decrease in value is in excess of what would otherwise be recognized by application of the equity method. The evaluation allows the Partnership to determine if an equity method investment should be impaired and that an impairment, if any, is fairly reflected in its financial statements
The Partnership believes the equity method is an appropriate means for it to recognize increases or decreases measured by GAAP in the economic resources underlying the investments. Regular evaluation of these investments is appropriate to evaluate any potential need for impairment. It uses the following types of triggers to identify a loss in value of an investment that is other than a temporary decline. Examples of a loss in value may be identified by:
· An inability to recover the carrying amount of the investment;
· A current fair value of an investment that is less than its carrying amount; and
· Other operational criteria that cause us to believe the investment may be worth less than otherwise accounted for by using the equity method.
Intangible Assets
The Company’s intangible assets are comprised of customer contracts and relationships acquired in business combinations, recorded under the purchase method of accounting at their estimated fair values at the date of acquisition. Using relevant information and assumptions, management determines the fair value of acquired identifiable intangible assets. Fair value is generally calculated as the present value of estimated future cash flows using a risk-adjusted discount rate. The key assumptions include contract renewals, economic incentives to retain customers, historical volumes, current and future capacity of the gathering system, pricing volatility, and the discount rate. Amortization of intangibles with definite lives is calculated using the straight-line method over the estimated useful life of the intangible asset. The estimated economic life is determined by assessing the life of the assets to which the contracts or relationships relate, the likelihood of renewals, competitive factors, regulatory or legal provisions, and maintenance and renewal costs.
Impairment of Long-Lived Assets The Company evaluates its long-lived assets, including intangibles, for impairment when events or changes in circumstances warrant such a review. A long-lived asset group is considered impaired when the estimated undiscounted cash flows from such asset group are less than the asset group’s carrying value. In that event, a loss is recognized to the extent that the carrying value exceeds the fair value of the long-lived asset group. Fair value is determined primarily using estimated discounted cash flows. Management considers the volume of reserves behind the asset and future NGL product and natural gas prices to estimate cash flows. The amount of additional reserves developed by future drilling activity depends, in part, on expected natural gas prices. Projections of reserves, drilling activity and future commodity prices are inherently subjective and contingent upon a number of variable factors, many of which are difficult to forecast. Any significant variance in any of these assumptions or factors could materially affect future cash flows, which could result in the impairment of an asset.
For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value, less the cost to sell, to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change.
Deferred Financing Costs
Deferred financing costs, included in Other assets in the accompanying consolidated balance sheets, are amortized over the estimated lives of the related obligations or, in certain circumstances, accelerated if the obligation is refinanced, using the straight line method which approximates the effective interest rate method.
Deferred Contract Costs
The Company entered into a series of agreements with a gas producer in September 2004, under which the Company processes natural gas under modified keep-whole arrangements. In connection with these agreements, the Company paid $3.3 million of consideration to the producer in connection with these non-separable contracts, which are being amortized as additional cost of the gas purchased over the term of the contracts, October 1, 2004 through February 9, 2015. Amortization related to these contracts for the years ended December 31, 2006 and 2005 was $0.3 million and $0.3 million, respectively.
Deferred income
Deferred income represents prepayments received under fixed fee contracts to deliver NGLs at a future date. Deferred income is recognized as revenue upon delivery of the product.
Derivative Instruments
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, (“SFAS 133”) established accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception. To the extent derivative instruments designated as cash flow hedges are effective, changes in fair value are recognized in other comprehensive income until the underlying hedged item is recognized in earnings. Effectiveness is evaluated by the derivative instrument’s ability to offset changes in fair value or cash flows of the underlying hedged item. Any change in the fair value resulting from ineffectiveness is recognized immediately in earnings. Changes in the fair value of derivative instruments designated as fair value hedges, as well as the changes in the fair value of the underlying hedged item, are recognized currently in earnings. Any differences between the changes in the fair values of the hedged item and the derivative instrument represent gains or losses from ineffectiveness. To the extent that the Company elects hedge accounting treatment for specific derivatives, the Company formally documents, designates and assesses the
effectiveness. As of December 31, 2006 and 2005, no transactions had been designated for hedge accounting treatment.
In the course of normal operations, the Company routinely enters into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs, that under SFAS 133, qualify for and are designated as a normal purchase and sales contracts. In general, the Company exempts these types of contracts from the mark-to-market requirements of SFAS 133 and instead accounts for them using accrual accounting.
For contracts that are not designated as normal purchase and sales contracts, the change in market value of the contracts is recorded as a component of revenue or purchase product costs. The following table summarizes our handling of derivative instruments as presented in our accompanying consolidated statements of operations:
Transaction Type
Realized gain (loss)
Unrealized gain (loss)
Sales:
Fixed Physical Forwards
Revenue
Derivative gain (loss)
All other derivative instruments
Derivative gain (loss)
Derivative gain (loss)
Purchases:
Fixed Physical Forwards
Purchase product costs
Purchase product costs
All other derivative instruments
Purchase product costs
Purchase product costs
Derivative gain (loss) in the table above are included in total revenues in the accompanying consolidated statements of operations.
Treasury Stock
Treasury stock purchases are accounted for under the cost method, whereby the entire cost of the acquired stock is recorded as treasury stock. Treasury stock reissued is relieved on a weighted average cost basis.
Fair Value of Financial Instruments Management believes the carrying amount of financial instruments, including cash, accounts receivable, accounts payable, accrued expenses, and other financial instruments approximates fair value because of the short-term maturity of these instruments. Management believes the carrying value of MarkWest Hydrocarbon’s Credit Facility and the Partnership’s Credit Facility approximates fair value due to their variable interest rates. The estimated fair value of the Senior Notes was approximately $499.8 million and $207.0 million at December 31, 2006 and 2005, respectively, based on quoted market prices, see Note 12. Derivative instruments are recorded at fair value, based on available market information, see Note 13.
Revenue Recognition
The Company generates the majority of its revenues from natural gas gathering and processing, NGL fractionation, transportation and storage, and crude oil gathering and transportation. While all of these services constitute midstream energy operations, the Partnership provides its services pursuant to six different types of arrangements. In many cases, the Partnership provides services under contracts that contain a combination of more than one of the arrangements. The following are descriptions of the Partnership’s arrangements.
· Fee-based arrangements. The Partnership receives 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 the Partnership earns from these arrangements is directly related to the volume of natural gas, NGLs or crude oil that flows through our systems and facilities and is not directly dependent on commodity prices. In certain cases, these arrangements provide for minimum annual payments. If a sustained decline in commodity prices were to result in a decline in volumes, the Partnership’s revenues from these arrangements would be reduced.
· Percent-of-proceeds arrangements. The Partnership gathers and processes natural gas on behalf of producers, sells the resulting residue gas, condensate and NGLs at market prices, and remits to producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments, the Partnership delivers an agreed-upon percentage of the residue gas and NGLs to the producer, and sells the volumes it keeps to third parties at market prices. Generally, under these types of arrangements its revenues and net operating margins generally increase as natural gas, condensate and NGL prices increase, and its revenues and net operating margins decrease as natural gas and NGL prices decrease.
· Percent-of-index arrangements. The Partnership generally purchases 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. It then gathers and delivers the natural gas to pipelines, where it resells the natural gas at the index price, or at a different percentage discount to the index price. The net operating margins the Partnership realizes under these arrangements decrease in periods of low natural gas prices, because these net operating margins are based on a percentage of the index price. Conversely, their net operating margins increase during periods of high natural gas prices.
· Keep-whole arrangements. The Partnership gathers natural gas from the producer, processes the natural gas, and sells 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, the Partnership 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 the Partnership’s revenues and net operating margins increase as the price of condensate and NGLs increases relative to the price of natural gas, and decreases as the price of natural gas increases relative to the price of condensate and NGLs.
· Settlement margin. Typically, the Partnership is allowed to retain a fixed percentage of the volume gathered to cover the compression fuel charges and deemed line losses. To the extent the gathering system is operated more efficiently than specified per contract allowance, the Partnership is entitled to retain the difference for its own account.
In many cases, the Partnership provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of the Partnership’s contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements. Under all of the arrangements, revenue is recognized at the time the product is delivered and title is transferred. It is upon delivery and title transfer that the Partnership meets all four revenue recognition criteria, and it is at such time that the Partnership recognizes revenue.
The Partnership’s assessment of each of the four revenue recognition criteria as they relate to its revenue producing activities is as follows:
· Persuasive evidence of an arrangement exists. The Partnership’s customary practice is to enter into a written contract, executed by both the customer and the Partnership.
· Delivery. Delivery is deemed to have occurred at the time the product is delivered and title is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent the Partnership retains its equity liquids as inventory, delivery occurs when the inventory is subsequently sold and title is transferred to the third party purchaser.
· The fee is fixed or determinable. The Partnership negotiates the fee for its services at the outset of its fee-based arrangements. In these arrangements, the fees are nonrefundable. The fees are generally due within ten days of delivery or services rendered. For other arrangements, the amount of revenue is determinable when the sale of the applicable product has been completed upon delivery and transfer of tile. Proceeds from the sale of products are generally due in ten days.
· Collectibility is probable. Collectibility is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (e.g. cash position and credit rating) and their ability to pay. If collectibility is not considered probable at the outset of an arrangement in accordance with the Partnership’s credit review process, revenue is recognized when the fee is collected.
Certain revenue from sales of customer gas to a third-party processor is recognized net, under EITF 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, as the Partnership earns a fixed amount and does not take ownership of the gas.
Revenue and Expense Accruals
We routinely make accruals based on estimates for both revenues and expenses due to the timing of compiling billing information, receiving certain third party information and reconciling our records with those of third parties. The delayed information from third parties includes, among other things, actual volumes purchased, transported or sold, adjustments to inventory and invoices for purchases, actual natural gas and NGL deliveries and other operating expenses. We make accruals to reflect estimates for these items based on our internal records and information from third parties. The estimated accruals are reversed in the following month when actual information is received from third parties and our internal records have been reconciled.
Stock and Incentive Compensation Plans
The Company adopted the SFAS No. 123R, Accounting for Stock-Based Compensation (“SFAS 123R”) on January 1, 2006, using the modified prospective method. Prior to adopting SFAS 123R, the Company elected to measure compensation expense for equity-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25 (“APB 25”), Accounting for Stock Issued to Employees.
Under SFAS 123R, compensation expense is based on the fair value of the award. SFAS 123R classifies stock-based compensation as either equity or liability awards. The fair value on the date of grant for an award classified as equity is
recognized over the requisite service period, with a corresponding credit to equity (generally, paid-in capital). The requisite service period is the period during which an individual is required to provide a service in exchange for the award. The requisite service period is estimated based on an analysis of the terms of the share-based payment award. Compensation expense for a liability award is based on the award’s fair value, remeasured at each reporting date until the date of settlement. Additionally, compensation expense is reduced for an estimate of expected award forfeitures.
MarkWest Hydrocarbon
Stock Options
Historically, stock options were issued under the Company’s 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan, (together the “1996 Plans”). In June 2006 shareholders approved the 2006 Stock Incentive Plan (the “2006 Plan”) to replace the 1996 Plans. Under SFAS 123R, our stock options are categorized as equity awards. Compensation expense for stock options is measured based on the grant date fair value and is amortized into earnings over the service period as the options vest. While it was determined in 2005 that the Company does not intend to issue stock options in the future, they are available for issuance under the 2006 Plan. On December 1, 2006 a board resolution provided for the accelerated vesting of 14,950 unvested stock option grants. Consequently, as of December 31, 2006 the Company had no remaining unvested options or any unrecognized compensation expense pertaining to options.
Restricted Stock
The Company issued restricted stock under the 1996 Plans until the adoption of the 2006 Plan at which point all new shares are, and will be, issued pursuant to the rules of the 2006 Plan. Under SFAS 123R, our restricted stock qualifies as an equity award. Accordingly, it is measured at the grant date fair value and the associated compensation expense is recognized over the requisite service period. The restricted stock vests equally over a three year period.
Participation Plan
The Company has also entered into arrangements with certain directors and employees of the Company referred to as the Participation Plan. Under this plan, the Company sells subordinated units of the Partnership or interests in the Partnership’s general partner, under a purchase and sale agreement. Both the subordinated unit and general partner interest transactions are considered compensatory arrangements due to the put-and-call provisions and the associated valuation being based on a formula instead of an independent third party valuation. The subordinated units convert to common units after a holding period. Historically, the Company has settled the subordinated units for cash when individuals leave the Company. The general partner interests have no definite term, but historically have been settled for cash when the employee leaves the Company. Under SFAS 123R, the subordinated units and general partner interests are classified as liability awards. As a result, the Company is required to mark to market the subordinated unit and general partner interest valuations at the end of each period.
Under Topic 1-B of the codification of the Staff Accounting Bulletins, Allocation of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity, some portion of compensation expense related to services provided by MarkWest Hydrocarbon’s employees and directors recognized under the Participation Plan should be allocated to the Partnership. The allocation is based on the percent of time each employee devotes to the Company. Compensation attributable to interests sold to individuals who serve on both the board of MarkWest Hydrocarbon and the Board of Directors of the Partnership’s General Partner is allocated equally.
MarkWest Energy Partners
Restricted Units
The Partnership issues restricted units under the MarkWest Energy Partners, L.P. Long-Term Incentive Plan. A restricted unit is a “phantom” unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the Compensation Committee, cash equivalent to the value of a common unit. The restricted units are treated as liability awards under SFAS 123R. As a result, the Partnership is required to mark to market the awards at the end of each reporting period. Compensation expense is remeasured for the phantom unit grants using the market price of MarkWest Energy Partners’ common units at each reporting date. The fair value of the units awarded is amortized into earnings over the period of service and is adjusted monthly for the change in the fair value of the unvested units granted. The phantom units vest equally over a three year period.
Vesting is accelerated for certain employees, if specified performance measures are met. The accelerated vesting criteria provisions are based on annualized distribution goals. If the Partnership’s distributions are at or above the goal for a certain number of consecutive quarters, vesting of the employee’s phantom units is accelerated. The general partner of the Partnership may also elect to accelerate the vesting of outstanding awards, which results in an immediate charge to operations for the unamortized portion of the award.
To satisfy common unit awards, the Partnership will issue new common units, acquire common units in the open market, or use common units already owned by the general partner.
Pro Formas
Had compensation cost for the Company’s stock-based and unit-based compensation plans been determined based on the fair value at the grant dates under those plans consistent with the method prescribed by SFAS 123R for the fiscal years ended December 31, 2005 and 2004, the Company’s net income and earnings per share would have been adjusted to the pro forma amounts listed below:
Income Taxes
The Company accounts for income taxes under the asset and liability method pursuant to SFAS No. 109, Accounting for Income Taxes (“SFAS 109”). Under SFAS 109, deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realizability of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value.
Comprehensive Income (Loss)
Comprehensive income (loss) includes net income (loss) and other comprehensive income (loss), which includes unrealized gains and losses on commodity or interest rate derivative financial instruments, accounted for as hedges, and unrealized gains or losses on marketable securities, accounted for as available for sale.
Earnings (Loss) Per Share
Basic earnings (loss) per share are computed by dividing net income by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share is computed by adjusting the weighted average number of common shares outstanding for the dilutive effect, if any, of common share equivalents. The Company uses the treasury stock method to determine the dilutive effect. Dilutive potential common shares include outstanding stock options and stock awards. All share information has been adjusted to give retroactive effect to the May 2006 stock dividend.
The following are the number of shares used to compute the basic and diluted earnings per share (in thousands, except per share data):
Recent Accounting Pronouncements
In February 2006 the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140 (“SFAS 155”). This statement amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”), and SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities and resolves issues addressed in SFAS 133 Implementation Issue No. D1, “Application of Statement 133 to Beneficial Interest in Securitized Financial Assets.” This Statement: (a) permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation; (b) clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133; (c) establishes a requirement to evaluate beneficial interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation; (d) clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives; and, (e) eliminates restrictions on a qualifying special-purpose entity’s ability to hold passive derivative financial instruments that pertain to beneficial interests that are or contain a derivative financial instrument. The standard also requires presentation within the financial statements that identifies those hybrid financial instruments for which the fair value election has been applied and information on the income statement impact of the changes in fair value of those instruments. The Company is required to apply SFAS 155 to all financial instruments acquired, issued or subject to a remeasurement event beginning January 1, 2007, although early adoption is permitted as of the beginning of an entity’s fiscal year. The adoption of SFAS 155 is not expected to have a material impact on the consolidated financial statements of the Company.
In June 2006 the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”). The interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS109, Accounting for Income Taxes. Specifically, the pronouncement prescribes a “more likely than not” recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. The interpretation is effective for fiscal years beginning after December 15, 2006. The Company is currently evaluating the impact of FIN 48.
In September 2006 the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS 157”). SFAS 157 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years, with early adoption permitted. The Company has not yet determined the impact, if any, the implementation of SFAS 157 may have on the consolidated financial statements of the Company.
In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. The SEC staff believes that registrants should quantify errors using both a balance sheet and an income statement approach and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. SAB 108 is effective for the first annual period ending after November 15, 2006. The Company adopted SAB 108 for the
year ending December 31, 2006, and it did not have a material effect on the consolidated financial statements of the Company.
The FASB has issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”), which permits an entity to measure certain financial assets and financial liabilities at fair value. The Statement’s objective is to improve financial reporting by allowing entities to mitigate volatility in reported earnings caused by the measurement of related assets and liabilities using different attributes, without having to apply complex hedge accounting provisions. Under SFAS 159, entities that elect the fair value option will report unrealized gains and losses in earnings at each subsequent reporting date. The fair value option may be elected on an instrument-by-instrument basis, with a few exceptions, as long as it is applied to the instrument in its entirety. The fair value option election is irrevocable, unless a new election date occurs. The new Statement establishes presentation and disclosure requirements to help financial statement users understand the effect of the entity’s election on its earnings, but does not eliminate disclosure requirements of other accounting standards. Assets and liabilities that are measured at fair value must be displayed on the face of the balance sheet. SFAS 159 is effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. Early adoption is permitted as of the beginning of the previous fiscal year provided that the entity (1) makes that choice in the first 120 days of that fiscal year, (2) has not yet issued financial statements, and (3) elects to apply the provisions of SFAS 157. The Company has not yet determined the impact, if any; the implementation of SFAS 159 may have on the consolidated financial statements of the Company.
3. Acquisitions by MarkWest Energy Partners
During 2006, 2005 and 2004, the Partnership completed the following acquisitions. Each acquisition was accounted for under the purchase method. The assets acquired and liabilities assumed were recorded at the estimated fair market values as of the acquisition date. The preliminary allocation of assets and liabilities may be adjusted to reflect the final determined amounts during a short period of time following the acquisition. The results of operations from these acquisitions are included in our consolidated financial statements from the acquisition date.
Santa Fe Acquisition
On December 29, 2006, the Partnership purchased 100% of the ownership interest in Santa Fe Gathering, L.L.C for $15.0 million, subject to working capital adjustments. The gathering system is located in Roger Mills and Beckham Counties, Oklahoma. The Grimes system was constructed in May 2005 to gather from growing production fields. Current system throughput is approximately 16 MMcf/d. The final purchase price allocation is expected to be completed in the second quarter of 2007.
Javelina Acquisition
On November 1, 2005, the Partnership acquired equity interests in Javelina Company, Javelina Pipeline Company and Javelina Land Company, L.L.C., which were 40%, 40% and 20%, respectively, owned by subsidiaries of El Paso Corporation, Kerr-McGee Corporation and Valero Energy Corporation. The Partnership paid consideration of $357.0 million, plus $41.8 million for net working capital that included approximately $35.5 million in cash. The Corpus Christi, Texas, gas processing facility treats and processes off-gas from six local refineries, two of which are owned by Valero Energy Corporation, two by Koch Industries, Inc. and two by Citgo Petroleum Corporation. Constructed in 1989 to recover up to 28,000 Bbl/d of NGLs, the facility currently processes approximately 125 to 130 MMcf/d of inlet gas and produces approximately 26,200 Bbl/d of NGLs. The Partnership and the seller negotiated a final settlement of the acquired working capital of $41.8 million, and the final payment of $5.9 million was paid to the sellers in May of 2006 and included in the final purchase price allocation, which was completed in the second quarter of 2006.
Starfish Joint Venture
On March 31, 2005, the Partnership paid $41.7 million to an affiliate of Enterprise Products Partners L.P. for a 50% non-operating membership interest in Starfish Pipeline Company, LLC. Starfish is a joint venture with Enbridge Offshore Pipelines LLC, which the Partnership accounts for using the equity method. Starfish owns the FERC-regulated Stingray natural gas pipeline, and the unregulated Triton natural gas gathering system and West Cameron dehydration facility. All are located in the Gulf of Mexico and southwestern Louisiana.
East Texas System Acquisition
On July 30, 2004, the Partnership completed the East Texas system acquisition of American Central Eastern Texas’ Carthage gathering system and gas-processing assets, located in East Texas, for approximately $240.7 million. The Partnership’s consolidated financial statements include the results of operations of the Carthage gathering system from July 30, 2004. The acquired assets consist of processing plants, gathering systems, a processing facility currently under construction and an NGL pipeline.
Hobbs Lateral Acquisition
On April 1, 2004, the Partnership acquired the Hobbs lateral pipeline for approximately $2.3 million. The Hobbs lateral consisted of a four-mile pipeline, with a capacity of 160 million cubic feet of natural gas per day, connecting the Northern Natural Gas interstate pipeline to Southwestern Public Service’s Cunningham and Maddox power-generating stations in Hobbs, New Mexico. The Hobbs lateral is a New Mexico intrastate pipeline regulated by the FERC.
The following table summarizes the costs and allocations of the above acquisitions (in thousands):
Pro Forma Results of Operations (Unaudited)
The following table reflects the unaudited pro forma consolidated results of operations for the years ended December 31, 2005 and 2004, as though the Javelina, Starfish and East Texas acquisitions had occurred on January 1, 2004. The unaudited pro forma results of operations for the Hobbs and Santa Fe acquisitions have not been presented, as the acquisitions were not considered significant. The results have been prepared for comparative purposes only and may not be indicative of future results. All earnings per share information have been updated to reflect the May 2006 stock dividend.
4. Marketable securities
Marketable securities are classified as available-for-sale and stated at market based on the closing price of the securities at the balance sheet date. Accordingly, unrealized gains are reflected in other comprehensive income, net of applicable income taxes. For losses that are other than temporary, the cost basis of the securities is written down to fair value, and the amount of the write down is reflected in the statement of operations. The Company utilizes a first-in first-out cost basis to compute realized gains and losses. Realized gains and losses, dividends, interest income, and the amortization of discounts and premiums are reflected in the statement of operations.
The following are the components of marketable securities (in thousands):
For the year ended December 31, 2006, the Company recognized net unrealized gains on marketable securities of $0.7 million, net of the related tax expense of $0.5 million. These gains are shown as a component of other comprehensive income for 2006.
For the year ended December 31, 2005, the Company recognized net unrealized losses on marketable securities of $0.2 million, net of the related tax benefit of $0.1 million. These losses are shown as a component of other comprehensive income for 2005.
5. Significant Customers and Concentration of Credit Risk
For the year ended December 31, 2006, revenues from Targa Resources Partners, L.P. (“Targa”) totaled $76 million, representing 10% of the Company’s consolidated revenues. Sales to Targa are made primarily from the MarkWest Energy Partner segment. The Company had a receivable of $3.0 million from Targa as of December 31, 2006.
For the years ended December 31, 2005 and 2004, revenues from one other customer totaled $67 million and $60 million, representing 9% and 13% of the Company’s consolidated revenues, respectively. Sales to this customer were made primarily from the MarkWest Energy Partner segment. The Company had a receivable of $5.5 million from this customer as of December 31, 2005.
6. Receivables and Other current assets
Receivables consist of the following (in thousands):
Other current assets consist of the following (in thousands):
Risk management premium
In the third and fourth quarters of 2006 the Partnership entered into certain put option contracts on commodities requiring premium payments to secure certain floor prices. The Partnership paid $1.0 million to the counterparty as a premium on certain short-term put option contracts. The payment is recorded as a short-term asset and will be amortized through revenue as the puts expire or are exercised. The contracts are recorded as derivative instruments, so charges in fair value of the contracts are recorded as an unrelated gain or loss.
7. Properties, plant and equipment
Property, plant and equipment consist of (in thousands):
The Company capitalizes interest on major projects during construction. For the years ended December 31, 2006 and 2005, the Company capitalized interest of $0.9 million and $2.1 million, respectively
Woodford gathering system
In late 2006 the Partnership began the construction and operation of the Woodford gathering system and compression system to support wells in a 200-square-mile project area situated in a four-county region in the Arkoma Basin in eastern Oklahoma. As of December 31, 2006, the Partnership invested capital of $26.4 million.
8. Intangible assets
The Company’s intangible assets at December 31, 2006 and 2005 are comprised of customer contracts and relationships, as follows (in thousands):
Amortization expense related to intangible assets was $16.0 million, $9.7 million and $3.6 million for the years ended December 31, 2006, 2005 and 2004, respectively.
Estimated future amortization expense related to the intangible assets at December 31, 2006, is as follows (in thousands):
9. Other long-term assets
The Company’s other long-term assets at December 31, 2006 and 2005 are comprised of the following (in thousands):
Risk management premium
In the third and fourth quarters of 2006 the Partnership entered into certain put option contracts on commodities requiring premium payments to secure certain floor prices. The Partnership paid $0.7 million to the counterparty as a premium on certain long-term put option contracts. The payment is recorded as a long-term asset (and reclassified to a current asset once the contract is set to expire within one year) and will be amortized through revenue as the puts expire or are exercised. The contracts are recorded as derivative instruments, so changes in fair value of the contracts are recorded as an unrealized gain or loss.
10. Accrued liabilities
Accrued liabilities consist of the following (in thousands):
11. Asset retirement obligation
The Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”), on January 1, 2003. Under SFAS 143, the fair value of a liability for an asset retirement obligation is recognized in the period in which the liability is incurred with an offsetting increase in the carrying amount of the related long-lived asset. The recognition of an asset retirement obligation requires that management make numerous estimates, assumptions and judgments regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; inflation rates, and future advances in technology. In periods subsequent to initial measurement of the liability, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Over time, the liability is accreted to its future value, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss.
The Company’s assets subject to asset retirement obligations are primarily certain gas-gathering pipelines and processing facilities, a crude oil pipeline and other related pipeline assets. The Company also has land leases that require the Company to return the land to its original condition upon the termination of the lease. In connection with the adoption of SFAS 143, the Company reviewed current laws and regulations governing obligations for asset retirements and leases, as well as the Company’s leases and other agreements.
The following is a reconciliation of the changes in the asset retirement obligation from December 31, 2004, to December 31, 2006 (in thousands):
At December 31, 2006, 2005 and 2004, there were no assets legally restricted for purposes of settling asset retirement obligations. The asset retirement obligation liability has been recorded as “Other long-term liabilities” in the accompanying consolidated balance sheets.
12. Debt
Debt as of December 31, 2006 and 2005 is summarized below (in thousands):
MarkWest Hydrocarbon
Credit Facility (August 2006 to Present)
On August 18, 2006, the Company entered into the second amended and restated credit agreement (“Company Credit Facility”) which provides a maximum lending limit of $55.0 million, increased from $25.0 million; and extends the term from one to three years. The Company Credit Facility includes a $40.0 million Revolving Facility and a $15.0 million Unit Acquisition Facility. The $15.0 million Unit Acquisition Facility may be used to finance the acquisition of MarkWest Energy Partners common or subordinated units.
The Company Credit Facility bears interest at a variable interest rate, plus basis points. The variable interest rate typically is based on the London Inter Bank Offering Rate (“LIBOR”); however, in certain borrowing circumstances the rate would be based on the higher of a) the Federal Funds Rate plus 0.5-1%, and b) a rate set by the Facility’s administrative agent, based on the U.S. prime rate. The basis points correspond to the ratio of the Revolver Facility Usage to the Borrowing Base, ranging from 0.50% to 1.75% for Base Rate loans, and 1.50% to 2.75% for Eurodollar Rate loans. The Company pays a quarterly commitment fee on the unused portion of the credit facility at an annual rate ranging from 37.5 to 50.0 basis points.
Under the provisions of the Company Credit Facility, the Company is subject to a number of restrictions on its business, including its ability to grant liens on 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 (other than subordinated indebtedness); make distributions on equity investments; declare or make, directly or indirectly, any restricted distributions.
The credit facility also contains covenants requiring the Company to maintain:
· a leverage ratio (as defined in the credit agreement) of not greater than 4.0 to 1.0, or up to 5.5 to 1.0, in certain circumstances;
· a minimum net worth of a) $30.0 million plus, b) 50% of consolidated net income (if positive) earned on or after July 1, 2006, plus, c) 100% of net proceeds of all equity issued by the Company subsequent to August 18, 2006; and
· a minimum collateral coverage ratio of not more than 2.0 to 1.0 as of the date of any determination.
On February 16, 2007, the Company entered into the first amendment to the second amended and restated credit agreement. The Term of the Agreement was extended by one year, to August 20, 2010. Additionally, provisions were added for a Non-Borrowing Base Revolving Credit Facility (“NBB Facility”). The NBB Facility provides for up to $50 million of credit to enable the Company to meet margin requirements associated with its derivative instruments.
The new agreement also added the following covenant:
· In the event the NBB Facility loans are drawn the minimum collateral coverage ratio increases to 3.5 to 1.0.
Credit Facility (January 2006 to August 2006)
On January 31, 2006, the Company entered into the first amended and restated credit agreement, which provided a maximum lending limit of $25.0 million for a one-year term, and which amended and restated the October 2004 agreement discussed below. As of December 31, 2006, the Company had $6.0 million of the availability committed to a letter of credit, leaving $19.0 million available for revolving loans.
On March 23, 2006, the Company amended the First Amended and Restated Credit Agreement to reduce the cash reserve requirement from $13.0 million to $5.0 million through December 31, 2006.
Credit Facility (October 2004 to January 2006)
In October 2004 the Company entered into a $25.0 million senior credit facility with a term of one year. The $25.0 million revolving facility had a variable interest rate based on the base rate, which is equal to the higher of a) the Federal Funds Rate plus ½ of 1%, and b) the rate of interest in effect for such day as publicly announced from time to time by the Administrative Agent as its prime rate, plus the applicable rate, which is based on a utilization percentage. In October, November and December 2005, the Company entered into the first, second and third amendment to the credit agreement. The first amendment extended the term of the original agreement to November 15, 2005. The second amendment reduced the lending amount from $25.0 million to $16.0 million, of which $6.0 million of availability is committed to a letter of credit, leaving $10.0 million available for revolving loans. The second amendment also extended the term of the revolving credit to December 30, 2005. The third amendment extended the term of the revolving credit to January 31, 2006, and reduced the lending amount from $16.0 million to $13.5 million, of which $6.0 million is committed to a letter of credit, leaving $7.5 million available for revolving loans at December 31, 2005.
MarkWest Energy Partners
2016 Senior Notes
In July 2006 MarkWest Energy Partners, LP and its wholly owned subsidiary MarkWest Energy Finance Corporation (the “Issuers”) co-issued $200 million in aggregate principal amount of 81¤2% senior notes due 2016 (the “2016 Senior Notes”) to qualified institutional buyers. The 2016 Senior Notes will mature on July 15, 2016, and interest is payable on each July 15 and January 15, commencing January 15, 2007. In October 2006 the Issuers offered $75.0 million in additional debt securities under this same indenture. The net proceeds from the private placements were approximately $191.2 million and $74.5 million, respectively, after deducting the initial purchasers’ discounts and legal, accounting and other transaction expenses. The Issuers used a portion of the net proceeds from the offerings to repay the term debt under the Partnership Credit Facility. Affiliates of several of the initial purchasers, including RBC Capital Markets Corporation, J.P. Morgan Securities Inc., and Wachovia Capital Markets, LLC, are lenders under the Partnership Credit Facility. Each of the Partnership’s existing subsidiaries, other than MarkWest Energy Finance Corporation, has guaranteed the notes jointly and severally and fully and unconditionally. The 2016 notes are senior unsecured obligations equal in right of payment with all of the Partnership’s existing and future senior debt. These notes are senior in right of payment to all of the Partnership’s future subordinated debt but effectively junior in right of payment to its secured debt to the extent of the assets securing the debt, including the Partnership’s obligations in respect of its Partnership Credit Facility.
The indenture governing the Partnership’s 2016 Senior Notes limits the activity of the Partnership and its restricted subsidiaries, including the ability of the Partnership and its restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions, or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of the Partnership’s restricted subsidiaries to pay dividends, make loans or transfer property to the Partnership; engage in transactions with the Partnership’s affiliates; sell assets, including equity interests of the Partnership’s subsidiaries; make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets. Subject to compliance with certain covenants, the Partnership may issue additional notes from time to time under the indenture pursuant to Rule 144A and Regulation S under the Securities Act of 1933.
The Partnership agreed to file an exchange offer registration statement or, under certain circumstances, a shelf registration statement, pursuant to a registration rights agreement relating to the 2016 Senior Notes. The Partnership failed to complete the exchange offer in the time provided for in the subscription agreements (January 6, 2007), and as a consequence it began incurring an interest rate penalty of 0.5% annually, increasing 0.25% every 90 days thereafter up to 1%, until such time as the exchange offer was completed. The Partnership incurred penalty interest of 0.5% from January 7, 2007 until February 26, 2007.
2014 Senior Notes
In October 2004 MarkWest Energy Partners, LP and its wholly owned subsidiary, MarkWest Energy Finance Corporation, co-issued $225.0 million in senior notes (“2014 Senior Notes”) at a fixed rate of 6.875%, payable semi-annually in arrears on May 1 and November 1, and commencing on May 1, 2005. The 2014 Senior Notes mature on November 1, 2014. The Partnership may redeem some or all of the notes at any time on or after November 1, 2009, at certain redemption prices together with accrued and unpaid interest to the date of redemption. The Partnership may redeem all of the notes at any time prior to November 1, 2009, at a make-whole redemption price. In addition, prior to November 1, 2007, the Partnership may redeem up to 35% of the aggregate principal amount of the notes with the proceeds of certain equity offerings at a stated redemption price. The Partnership must offer to repurchase the notes at a specified price if it a) sells certain assets and does not reinvest the proceeds or repay senior indebtedness, or b) experiences specific kinds of changes in control. Each of the Partnership’s existing subsidiaries, other than MarkWest Energy Finance Corporation, has guaranteed the notes jointly and severally and fully and unconditionally. The 2014 Senior Notes are senior unsecured obligations equal in right of payment with all of the Partnership’s existing and future senior debt. These notes are senior in right of payment to all of the Partnership’s future subordinated debt but effectively junior in right of payment to its secured debt to the extent of the assets securing the debt, including the Partnership’s obligations in respect of its Partnership Credit Facility.
The indenture governing the 2014 Senior Notes limits the activity of the Partnership and its restricted subsidiaries. Limitations include the ability of the Partnership and its restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions, or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of the Partnership’s restricted subsidiaries to pay dividends, make loans or transfer property to the Partnership; engage in transactions with the Partnership’s affiliates; sell assets, including equity interests of the Partnership’s subsidiaries; make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets. Subject to compliance with certain covenants, the Partnership may issue additional notes from time to time under the indenture pursuant to Rule 144A and Regulation S under the Securities Act of 1933.
The Partnership agreed to file an exchange offer registration statement or, under certain circumstances, a shelf registration statement, pursuant to a registration rights agreement relating to the 2014 Senior Notes. The Partnership failed to complete the exchange offer in the time provided for in the subscription agreements (April 26, 2005) and, as a consequence, was incurring an interest rate penalty of 0.5% annually, increasing 0.25% every 90 days thereafter up to 1%, until such time as the exchange offer was completed. The registration statement was filed on January 17, 2006, the exchange offer was completed on March 7, 2006, and the interest penalty ceased.
Partnership Credit Facility
On December 29, 2005, MarkWest Energy Operating Company, L.L.C., a wholly owned subsidiary of MarkWest Energy Partners L.P., entered into the fifth amended and restated credit agreement (“Partnership Credit Facility”), which provides for a maximum lending limit of $615.0 million for a five-year term. The credit facility includes a revolving facility of $250.0 million and a $365.0 million term loan. The credit facility is guaranteed by the Partnership and all of the Partnership’s subsidiaries and is collateralized by substantially all of the Partnership’s assets and those of its subsidiaries. The borrowings under the credit facility bear interest at a variable interest rate, plus basis points. The basis points vary based on the ratio of the Partnership’s Consolidated Debt (as defined in the Partnership Credit Facility) to Consolidated EBITDA (as defined in the Partnership Credit Facility), ranging from 0.50% to 1.50% for Base Rate loans, and 1.50% to 2.50% for Eurodollar Rate loans. The basis points will increase by 0.50% during any period (not to exceed 270 days) where the Partnership makes an acquisition for a purchase price in excess of $50.0 million (“Acquisition Adjustment Period”). For the year ended December 31, 2006, the weighted average interest rate on the Partnership Credit Facility was 7.2%.
The aggregate amount of minimum principal payments required on long-term debt in each of the years indicated are as follows as of December 31, (in thousands):
13. Derivative financial instruments
Our primary risk management objective is to manage volatility in our cash flows. A committee comprised of members of the senior management team oversees all of our derivative activity.
We utilize a combination of fixed-price forward contracts, fixed-for-floating price swaps and options on the over-the-counter (“OTC”) market. The Company may also enter into futures contracts traded on the New York Mercantile Exchange (“NYMEX”). Swaps and futures contracts allow us to manage volatility in our margins because corresponding losses or gains on the financial instruments are generally offset by gains or losses in our physical positions.
We enter into OTC swaps with financial institutions and other energy company counterparties. We conduct a standard credit review on counterparties and have agreements containing collateral requirements where deemed necessary. We use standardized swap agreements that allow for offset of positive and negative exposures. We may be subject to margin deposit requirements under OTC agreements (with non-bank counterparties) and NYMEX positions.
The use of derivative instruments may expose us to the risk of financial loss in certain circumstances, including instances when (i) NGLs do not trade at historical levels relative to crude oil, (ii) sales volumes are less than expected requiring market purchases to meet commitments, or (iii) our OTC counterparties fail to purchase or deliver the contracted quantities of natural gas, NGLs or crude oil or otherwise fail to perform. To the extent that we enter into derivative instruments, we may be prevented from realizing the benefits of favorable price changes in the physical market. We are similarly insulated, however, against unfavorable changes in such prices.
Fair value is based on available market information for the particular derivative instrument and incorporates the commodity, period, volume and pricing. Positive (negative) amounts represent unrealized gains (losses).
MarkWest Hydrocarbon Standalone
MarkWest Hydrocarbon Standalone may enter into physical and/or financial positions to manage its risks related to commodity price exposure. Due to timing of purchases and sales, direct exposure to price volatility can be created because there is no longer an offsetting purchase or sale that remains exposed to market pricing. Through marketing and derivatives activities, direct exposure may occur naturally, or we may choose direct exposure when we favor that exposure over frac spread risk. Beginning in 2006 MarkWest Hydrocarbon Standalone pre-purchased natural gas for shrink requirements in future months and, for both natural gas and NGLs, entered into swaps and future sales agreements to manage frac spread risk. These derivative instruments are marked to market.
The following tables summarize the current derivative positions specific to MarkWest Hydrocarbon Standalone’s segment at December 31, 2006 (in thousands, except price data):
(1) Swaps represent fixed forward sales and purchases, which, in combination economically hedge our frac spread position.
(2) A weighted average is used for grouped positions.
The following table summarizes the non-current derivative positions specific to MarkWest Hydrocarbon Standalone’s segment at December 31, 2006 (in thousands, except price data):
(1) Swaps represent fixed forward sales to hedge our production.
A summary of MarkWest Hydrocarbon Standalone’s commodity derivative instruments is provided below (in thousands):
MarkWest Energy Partners
The Partnership’s primary risk management objective is to reduce volatility in its cash flows arising from changes in commodity prices related to future sales of natural gas, NGLs and crude oil. Swaps and futures contracts may allow the Partnership to reduce volatility in its realized margins as realized losses or gains on the derivative instruments generally are offset by corresponding gains or losses in the Partnership’s sales of physical product. While the Partnership largely expects it’s realized derivative gains and losses to be offset by increases or decreases in the value of its physical sales, it will experience volatility in reported earnings due to the recording of unrealized gains and losses on its derivative positions that will have no offset. The volatility in any given period related to unrealized gains or losses can be significant to the overall results of the Partnership, however, it ultimately expects those gains and losses to be offset when they become realized.
The following tables summarize the current derivative positions specific to MarkWest Energy Partner’s segment at December 31, 2006 (in thousands, except price data):
(1) Forward sales to hedge our production.
(2) A weighted average is used for grouped positions.
(3) Purchase of puts to hedge our Ethane production.
(4) Forward producer collars to hedge our production.
The following table summarizes the non-current derivative positions specific to MarkWest Energy Partner’s segment at December 31, 2006 (in thousands, except price data):
(1) Forward producer collars to hedge our production.
(2) A weighted average is used for grouped positions.
A summary of MarkWest Energy’s commodity derivative instruments is provided below (in thousands):
14. Income taxes
The components of the income tax benefit (expense) from continuing operations are as follows (in thousands):
A reconciliation of the actual income tax benefit (expense) from continuing operations and the amount computed by applying the federal statutory rate of 35% to the income (loss) before income taxes is as follows (in thousands):
(1) The calculation of federal income tax at statutory rate has been adjusted for the non-controlling interest in net income of consolidated subsidiary.
The deferred tax assets and liabilities resulting from temporary book-tax differences are comprised of the following (in thousands):
At December 31, 2006 the Company had state net operating loss carryforwards of approximately $14.6 million that expire between 2011 and 2026. The Company expects that future taxable income will likely be apportioned to states other than those in which the net operating loss was generated. As a result, the Company believes it is more likely than not that the state net operating losses will not be realized and has provided a 100% valuation allowance against this long-term deferred tax asset. The Company had federal alternative minimum tax credit carryforwards of $2.7 million that have no expiration date and can be applied as a credit to reduce regular federal income tax.
15. Stock and Incentive Compensation Plans
All previously awarded MarkWest Hydrocarbon restricted stock, stock options and other compensation arrangements based on the market value of our common stock have been adjusted to reflect the May 2006 stock dividend. Furthermore, all previously awarded Partnership units have been adjusted to reflect the February 2007 two-for-one unit split (see Note 2 above).
Total compensation cost for share-based pay arrangements was as follows (in thousands):
Of the total compensation cost recognized for restricted units $0.1, $0.4 and $0.5 million related to the accelerated vesting of restricted units for the years ended December 31, 2006, 2005 and 2004, respectively. The accelerated vesting of restricted units occurs when specific distribution targets are achieved, as set forth in the individual grant agreements
The following summarizes the total compensation cost not yet recognized as of December 31, 2006, related to nonvested awards (in thousands). The actual compensation cost recognized might differ for the restricted units, as they qualify as liability awards, which are affected by changes in the fair value.
At December 31, 2006, the Company has three stock-based compensation plans, one of which is through its consolidated subsidiary, MarkWest Energy Partners.
2006 Stock Incentive Plan
In June 2006, the Company’s shareholders approved the 2006 Stock Incentive Plan (“2006 Plan”), effective July 1, 2006. The 2006 Plan replaced both the 1996 Stock Incentive Plan and the 1996 Non-employee Director Stock Option Plan (together the “1996 Plans”). Under the 2006 Plan the Company may grant a maximum of 1,000,000 restricted shares and stock options, subject to varying vesting terms and expected terms as discussed below.
Stock Options
The Company issued stock options under the 1996 Plans until 2005. While it was determined in 2005 that the Company does not intend to issue stock options in the future, they are available for issuance under the 2006 Plan. On December 1, 2006 a board resolution provided for the accelerated vesting of 14,950 unvested stock option grants affecting eight employees. Consequently, as of December 31, 2006 the Company had no remaining unvested options or any unrecognized compensation expense pertaining to options. For the year ended December 31, 2006, the Company received $0.3 million from the exercise of stock options.
Under SFAS 123R, the Company’s stock options are categorized as equity awards. Accordingly, compensation expense for options is measured based on the grant date fair value and is amortized into earnings over the service period as the options vest. The options historically vested at the rate of 25% per year for options granted in 1999 and thereafter, and 20% per year for options granted prior to 1999. The fair value of the options is estimated using the Black-Scholes option-pricing model. The options have a maximum term of ten years and may, at the discretion of the Company, be exercised using either a Company-assisted or broker-assisted cashless exercise.
The following summarizes the impact of the Company’s stock option plan (in thousands of shares):
The Company did not grant any stock options in 2006 or 2005. The fair value of each option granted in 2004 was estimated using the Black-Scholes option-pricing model. The following assumptions were used to compute the weighted average fair value of options granted:
A summary of the status of the Company’s stock option plans as of December 31, 2006, 2005 and 2004, are presented below.
Restricted Stock
The Company issued restricted stock under the 1996 Plans until the adoption of the 2006 Plan at which point all new shares are, and will be, issued pursuant to the rules of the 2006 Plan. Under SFAS 123R, the restricted stock qualifies as an equity award. Accordingly, restricted stock is measured at the grant date fair value and the associated compensation expense is recognized over the requisite service period, reduced for an estimate of expected forfeitures. The restricted stock vests equally over a three year period. No shares were granted prior to 2005.
The following summarizes the impact of the Company’s restricted stock plans:
During the years ended December 31, 2006, 2005 and 2004, the Company received no proceeds for issuing restricted stock, and there were no cash settlements.
Participation Plan
The Company has also entered into arrangements with certain directors and employees of the Company referred to as the Participation Plan. Under it, the Company sells subordinated units of the Partnership or interests in the Partnership’s general partner under a purchase and sale agreement. There is no maximum contractual term under the Participation Plan. The Company’s capacity to grant further general partner interests is limited by its ownership in the general partner. The subordinated units are sold without any restrictions on transfer.
Both the subordinated unit and general partner interest transactions are considered compensatory arrangements due to the put-and-call provisions and the associated valuation being based on a formula instead of an independent third party valuation. Under SFAS 123R, the subordinated units and general partner interests are classified as liability awards. As a result, the Company is required to mark to market the subordinated unit and general partner interest valuations at the end of each period. Compensation expense related to general partner interests is calculated as the difference in the formula value and the amount paid by those individuals. The formula value is the amount MarkWest Hydrocarbon would have to pay the employees and directors to repurchase the general partner interests, and is based on the current market value of the Partnership’s common units and the current quarterly distributions paid.
The interest in the Partnership’s general partner is sold with certain put-and-call provisions. These require MarkWest Hydrocarbon to buy back, or require the individuals to sell back their interest in the general partner to MarkWest Hydrocarbon. Specifically, the employees and directors can exercise their put if (1) MarkWest Hydrocarbon or the Partnership’s general partner undergoes a change of control; (2) additional membership interests are issued that, on a pro forma basis, decrease the distributions to all the then existing members; (3) any amendment, alteration or repeal of the provisions of the general partner agreement materially and adversely affects the then existing rights, duties, obligations or restrictions of the employees and directors; or (4) the employee or director (i) becomes totally disabled while a director, officer or employee of the general partner, of MarkWest Hydrocarbon or of any of their affiliates, or (ii) dies, or (iii) retires as a director, officer or employee of the general partner of MarkWest Hydrocarbon or of any of their affiliates after reaching the age of 60 years. The employee or his estate has 120 days after the put event to exercise the put under (4) and 30 days after notice to exercise under (1) through (3). MarkWest Hydrocarbon can exercise its call option if (i) the employee or director ceases to be a director or employee of MarkWest Hydrocarbon or any of its affiliates, or (ii) if there is a change of control of MarkWest or of the Partnership’s general partner. For the call option based upon a termination of employment or directorship, MarkWest Hydrocarbon has 12 months following the termination date to exercise its call option. MarkWest Hydrocarbon has agreed to exempt the general partner interests of three present or former directors from the call option based upon a termination of employment or directorship. Additionally, pursuant to the terms of our current CEO’s employment agreement with MarkWest Hydrocarbon, all of his general partner interest has become exempt from the call option based upon a termination of employment or directorship for reasons other than cause. For the call option based upon a change of control of MarkWest or of the Partnership’s general partner, MarkWest Hydrocarbon has 30 days following the change of control to exercise its call option.
On October 13, 2006, the Company completed the repurchase of a 0.5% interest in the general partner. This purchase resulted in an increase in our ownership level in the general partner to 89.7%. The Company did not sell any subordinated units to employees or directors in 2006 or 2005. Likewise, the Company did not reacquire any subordinated units in 2006 or 2005.
MarkWest Energy Partners’ Long-Term Incentive Plan
The number of restricted units available for issuance under the LTIP has been adjusted to reflect the February 2007 two-for-one unit split (see Note 2 above).
The general partner has adopted the MarkWest Energy Partners, L.P. Long-Term Incentive Plan for employees and directors of the general partner, as well as employees of its affiliates who perform services for us. The plan consists of
restricted units and unit options. It permits the grant of awards covering an aggregate of 1,000,000 common units, comprised of 400,000 restricted units and 600,000 unit options. The Compensation Committee of the general partner’s Board of Directors administers the plan.
Restricted Units
A restricted unit is a “phantom” unit that entitles the grantee to receive a common unit of the Partnership upon the vesting of the phantom unit, or, at the discretion of the Compensation Committee, cash equivalent to the value of a common unit. The restricted units vest over a service period of three years; however, vesting for certain awards may be accelerated if specific annualized distribution goals are met. During the vesting period, these restricted units are entitled to receive distribution equivalents, which represent cash equal to the amount of distributions made on common units.
Under SFAS 123R, the restricted units are treated as liability awards. As a result, the Partnership is required to mark to market the awards at the end of each reporting period. Compensation expense is measured for the phantom unit grants using the market price of MarkWest Energy Partners’ common units at each reporting date. The fair value of the units awarded is amortized into earnings over the period of service and is adjusted monthly for the change in the fair value of the unvested units granted.
The following is a summary of restricted unit activity under the Partnership’s Long-Term Incentive Plan:
For the year ended December 31, 2006, the Partnership issued 26,986 common units for vested restricted units. For the years ended December 31, 2005 and 2004 the partnership issued 17,700 and 54,596 common units, respectively and an additional 500 units were acquired in the open market in 2005.
Of the total number of restricted units that vested in 2006, 2005 and 2004, the Partnership received no proceeds for issuing restricted units (other than the contributions by the general partner to maintain its 2% ownership interest), and there were no cash settlements. Additionally, in 2004 the Partnership’s opted to redeem 310 restricted units for cash.
Unit Options. The Compensation Committee has the authority to make grants of unit options under the plan to employees and directors containing such terms as the committee shall determine. Unit options are exercisable over a period determined by the Compensation Committee. Unit options also are exercisable upon a change in control of the Partnership, the general partner, MarkWest Hydrocarbon or upon the achievement of specified financial objectives.
As of December 31, 2006, the Partnership had not granted any unit options.
16. Employee Benefit Plan
The Company made contributions of $1.0 million, $1.0 million and $0.5 million to a 401(k) savings and profit-sharing plan for the years ended December 31, 2006, 2005 and 2004, respectively. The Company did not contribute any common shares to a 401(k) savings or profit-sharing plan for the year ended December 31, 2006. The Company contributed approximately 12,000 and 15,000 common shares to a 401(k) savings and profit-sharing plan for the years ended December 31, 2005 and 2004, respectively, with an aggregate fair value of $1.0 million and $0.2 million, respectively. The plan is discretionary, with annual contributions determined by the Company’s Board of Directors.
17. Stockholder’s equity
MarkWest Hydrocarbon
Cash Dividends
The Company paid quarterly cash dividends for the years ended December 31, 2006, 2005 and 2004, as retroactively restated to give effect to the 2006 and 2004 stock dividends (see below) as follows:
Stock Dividends
On April 27, 2006, MarkWest Hydrocarbon announced that its Board of Directors approved the issuance of one share of common stock for each ten shares of common stock held by common stockholders. The stock was issued on May 23, 2006, to the stockholders of record as of the close of business on May 11, 2006; the ex-dividend date was May 9, 2006.
On October 28, 2004, the Company’s Board of Directors declared a stock dividend of one share of MarkWest Hydrocarbon’s common stock for each ten shares owned by stockholders. The stock dividend of 976,974 shares was paid on November 19, 2004 to the stockholders of record as of the close of business on November 9, 2004.
Cash Dividend
On January 22, 2004, the Board of Directors declared a one-time special cash dividend of $0.50 per share of common stock. The dividend was paid on February 18, 2004 to stockholders of record as of the close of business on February 4, 2004, with an ex-dividend date of February 2, 2004.
MarkWest Energy Partners
Unit Split - February 28, 2007
On February 28, 2007 the Partnership completed a two-for-one split of the Partnership’s Common Units, whereby holders of record at the close of business on February 22, 2007 received one additional Common Unit for each Common Unit owned on that date. The unit split resulted in the issuance of an additional 15,603,257 common units and 600,000
subordinated units. For all periods presented, all Partnership specific 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 to the unit split.
Public Offering - July 6, 2006
The Partnership priced its offering of 6,000,000 common units at $19.875 per unit. In addition, on July 12, 2006, the Partnership completed the sale of an additional 600,000 common units to cover over-allotments in connection with the Common Unit Offering. The sale of units resulted in total gross proceeds of $131.2 million, and net proceeds of approximately $125.9 million, after the underwriters’ commission and legal, accounting and other transaction expenses. The Partnership used the net proceeds from the offering, which includes a capital contribution from its general partner to maintain its 2% general partner interest in the Partnership, to repay a portion of the outstanding indebtedness under term debt on the Partnership Credit Facility.
Private Placement - December 28, 2005
The Partnership sold 1,149,428 common units to certain accredited investors at $21.75 per common unit, for gross proceeds of $25.0 million. $20 million of the proceeds were received in December 2005. The remaining $5 million was accrued at December 31, 2005, and received in January 2006. Offering costs of $0.1 million reduced the aggregate gross proceeds of $25.0 million to $24.9 million of net proceeds.
Private Placement - November 11, 2005
The Partnership sold 3,288,130 common units to certain accredited investors at $22.11 per common unit, for gross proceeds of $72.7 million. Offering costs of $0.1 million reduced the aggregate gross proceeds of $72.7 million to $72.6 million of net proceeds.
Public Offering - September 21,
The Partnership priced its offering of 4,314,790 common units at $21.71 per unit. The Partnership sold 4,000,000 units, for gross proceeds of $86.8 million. The remaining 314,790 were sold by certain unitholders, who retained the proceeds. In connection with the over-allotment provisions of the underwriting agreement, the Partnership issued an additional 647,218 common units, for gross proceeds of $14.1 million. Underwriters’ fees of $4.8 million, and professional fees and other offering costs of $0.4 million, reduced the gross proceeds of $100.9 million to $95.7 million of net proceeds. The net proceeds of $95.7 million, and the $2.1 million contributed by the general partner to maintain its 2% interest, resulted in total net proceeds associated with the offering of $97.8 million.
Private Placement - July 30,
The Partnership sold 2,608,876 common units to certain accredited investors at $17.25 per common unit, for gross proceeds of $45.0 million. Offering costs of $0.9 million reduced the aggregate gross proceeds of $45.0 million to $44.1 million of net proceeds. The net proceeds of $44.1 million, and the $0.9 million contributed by the general partner to maintain its 2% interest, resulted in total net proceeds associated with the private placement of $45.0 million.
Public Offering - January 12, 2004 The Partnership priced its offering of 2,296,000 common units at $19.95 per unit. The Partnership sold 2,200,888 units, for gross proceeds of $43.9 million. The remaining 95,112 were sold by certain unitholders, who retained the proceeds. In connection with the over-allotment provisions of the underwriting agreement, the Partnership issued an additional 145,000 common units, for gross proceeds of $2.9 million. Underwriters’ fees of $2.5 million, and professional fees and other offering costs of $1.3 million, reduced the gross proceeds of $46.8 million to $43.0 million of net proceeds. The net proceeds of $43.0 million, and the $0.9 million contributed by the general partner to maintain its 2% interest, resulted in total net proceeds of $43.9 million.
18. Commitments and contingencies
Legal
In the ordinary course of its business the Company 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 Company; 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, MarkWest Energy Appalachia, LLC (“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 Company 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
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 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.
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 Company for certain expenses related to the pipeline incident. These include the Company’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 Company was granted leave of the Court to amend its complaint to add a bad faith claim, and a claim for punitive damages. The Company 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 Company will ultimately recover under the policies. Discovery in the action is continuing. The Company 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.
The Company just recently learned that a default judgment had been entered against it in May of 2006, in an action entitled Runyan v. Eclipse Realty LLC et al, (Arapahoe County District Court, Colorado, Case No. 06CV1054, filed February 2006). The Company was not aware of having ever received a summons and was not given any notification of a motion for default judgment. The Company is still investigating whether there ever was proper service of process. The action involves a personal injury claim by an individual who allegedly slipped and fell due to snowy conditions while approaching the office building in which the Company was one of several tenants. Eclipse Realty, the landlord of the building, was responsible for the maintenance and upkeep of the common areas of the office building. The Company is seeking to have the default judgment vacated, and then having the Company dismissed as an improper party to the action. The Company also has a contractual indemnification from Eclipse Realty, the landlord of the building, and we have demanded that Eclipse Realty defend and indemnify the Company. We are unable to predict the outcome of our motion to vacate the default judgment or our indemnification claim, but the Company does not expect at this time that the matter should have a material adverse effect on our financial position.
The Partnership received notice from one of its 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 Company 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 Company’s financial condition, liquidity or results of operations.
Lease Obligations
The Company has various non-cancelable operating lease agreements for equipment expiring at various times through fiscal 2015. Annual rent expense under these operating leases was $9.3 million, $7.0 million and $5.2 million for the years ended December 31, 2006, 2005, and 2004, respectively. The minimum future lease payments under these operating leases as of December 31, 2006, are as follows (in thousands):
19. Related party transactions
Through the Company’s wholly owned subsidiary, Matrex, LLC, the Company held interests in a few exploration and production assets in which MAK-J Energy Partners Ltd. (“MAK-J”) also owns interests. These interests were sold on October 7, 2005. The general partner of MAK-J is a corporation owned and controlled by the Company’s former President and Chief Executive Officer and current Chairman of the Board of Directors.
There were no outstanding related party receivables as of December 31, 2006 or 2005. The Company also has payables to MAK-J, representing its share of revenues generated in the normal course of business, of zero and less than $0.1 million as of December 31, 2006 and 2005, respectively.
20. Subsequent Events
On February 16, 2007, the Company entered into the first amendment to the second amended and restated credit agreement, increasing the term by one year to August 20, 2010, and providing an additional $50 million of credit to enable the Company to meet margin requirements associated with its derivative instruments.
In the first quarter of 2007, the Partnership’s Gulf Coast business unit received proceeds of $5.5 million from a recently concluded rate case. The proceeds will be recorded as a reduction of facilities expense and interest income in the first quarter results of operations.
21. Segment Information MarkWest Hydrocarbon’s operations are classified into two reportable segments:
1. MarkWest Hydrocarbon Standalone - The Company sells its equity and third-party NGLs, purchases third-party natural gas and sells its equity and third-party natural gas. Between February 2004 and June 2006, when the agreement was terminated, the Company was engaged in the wholesale propane marketing business through a third party agency agreement. MarkWest Hydrocarbon Standalone operates MarkWest Energy Partners, a publicly traded limited partnership.
2. MarkWest Energy Partners - The Partnership is engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids; and the gathering and transportation of crude oil.
The Company evaluates the performance of its segments and allocates resources to them based on operating income. The Company conducts its operations in the United States.
The tables below present information about the net income or net loss for the reported segments for the three years ended December 31, 2006, 2005 and 2004 (in thousands). Net income or net loss for each segment includes total revenues minus purchased product costs, facility expenses, selling, general and administrative expenses, depreciation, amortization of intangible assets, accretion of asset retirement obligations and impairments and excludes interest income, interest expense, amortization of deferred financing costs, gain on sale of non-operating assets, non-controlling interest in net income of consolidated subsidiary, miscellaneous income or expense and income taxes.
Selling, general and administrative expenses are allocated to the segments based on direct expenses incurred by the segments or allocated based on the percent of time that employees devote to the segment in accordance with the Partnership’s services agreement with the Company.
22. Quarterly Results of Operations (Unaudited)
The following summarizes the Company’s quarterly results of operations for 2006 and 2005 (in thousands, except per share data):
23. Valuation and Qualifying Accounts
Activity in the allowance for doubtful accounts is as follows (in thousands):
(1) Bad debts written off (net of recoveries).
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
On September 20, 2005, the Company engaged Deloitte & Touche LLP as the Registrant’s independent registered public accounting firm for the year ending December 31, 2005, and to perform procedures related to the financial statements included in the Company’s quarterly reports on Form 10-Q, beginning with the quarter ended September 30, 2005. The Audit Committee made the decision to engage Deloitte & Touche and that decision was then approved, adopted and ratified by the Company’s Board of Directors. The Company had not consulted with Deloitte & Touche during the two most recent fiscal years or during any subsequent interim period prior to its appointment as auditor regarding either (i) the application of accounting principles to a specified transaction, either completed or proposed; or the type of audit opinion that might be
rendered on the Registrant’s consolidated financial statements, and neither a written report was provided to the Partnership nor oral advice was provided that Deloitte & Touche concluded was an important factor considered by the Partnership in reaching a decision as to the accounting, auditing or financial reporting issue; or (ii) any matter that was either the subject of disagreement (as defined in Item 304(a)(1)(iv) of Regulation S-K and the related instructions) or a reportable event (within the meaning of Item 304(a)(1)(v) of Regulation S-K).
Item 9A.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) are controls and other procedures that are designed to provide reasonable assurance that the information that we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
In connection with the preparation of this Annual Report, our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2006. In making this evaluation, our management considered material weaknesses discussed in Management’s Report on Internal Control Over Financial Reporting. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of December 31, 2006.
In light of the material weakness described in Management’s Report on Internal Control Over Financial Reporting, through the date of the filing of this Form 10-K, we have implemented remedial measures to address the material weakness in our internal controls that existed on December 31, 2006. The remediation procedures included detailed management review of substantially all contracts in effect at December 31, 2006, for the presence of derivatives or embedded derivatives. In addition, we have enhanced The procedures around contract reviews and monitoring of new accounting guidance, including the development of a newly designed contract review template. Based on these procedures, management has concluded that the material weakness that existed at December 31, 2006 had been remediated prior to the filing of this report. Accordingly, management believes that the consolidated financial statements included in this Annual Report present fairly, in all material respects, our financial condition, results of operations and cash flows as of, and for, the periods presented in conformity with GAAP.
Changes in Internal Control Over Financial Reporting
There have been changes in our internal controls over financial reporting that occurred during the fiscal quarter ended December 31, 2006 and subsequent to that date that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting:
Remediation of Prior Year’s Material Weaknesses in Internal Control
As reported in Item 9A. Controls and Procedures of the Company’s 2005 Form 10-K, material weaknesses existed in the Company’s control structure as of December 31, 2005 and 2004. The remediation of these material weaknesses and underlying significant deficiencies were addressed by a series of actions detailed in prior filings.
Although each of the individual control changes may not be material alone, in aggregate the control changes implemented have had a material impact on the effectiveness of the control environment.
Internal Control Environment. In connection with management’s assessment of the effectiveness of internal control over financial reporting for the year ended December 31, 2005, we identified and Deloitte & Touche LLP confirmed the presence of an ongoing material weakness related to our internal control environment. Specifically, our control environment did not sufficiently promote effective internal control over financial reporting through the management structure to prevent a material misstatement, as was evidenced by deficiencies or significant deficiencies.
In order to remediate this material weakness, we completed the following actions between July 2005 and December 2006:
Deficiency or significant deficiency identified at December 31, 2005, and the remediation activity:
Entity level controls, including the anti-fraud program and controls necessary to address the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) elements of risk assessment, information and communication, were inadequate.
· We established a compliance office focused on the entity-level risk assessment, control design, deficiency identification and remediation, detailed review and re-documentation of all of our internal control processes and implementation of significant internal control design changes to ensure that all internal control objectives are met.
· We conducted an entity-level risk assessment, established an internal audit plan and began to execute that internal audit plan. Results are reported directly to our general partner’s audit committee and to senior management.
· We established a Fraud Risk Assessment and Management Program and executed that program.
· We enhanced employee awareness of our already existing Code of Conduct, ethics and anti-fraud policies, through a training program that we delivered to substantially all employees in the second and third quarters of 2006. This training included heightened awareness of the ethics hotline availability and access options.
Fixed assets controls including instances of inappropriate authorization of invoices and improper reconciliation procedures.
· We formalized the monthly account reconciliation process for all balance sheet accounts. We implemented a formal review of reconciliations by our business unit accounting management.
· We conducted a detailed review and re-documentation of all of our control processes and made significant control design changes to ensure that all control objectives are met.
Controls over expenditures including instances of inappropriate authorization of invoices and the inability to independently validate accuracy and validity of amounts recorded.
· We strengthened our expenditure controls and centralized all expenditure processing in the Denver office.
Segregation of duties within certain key processes was inadequate to support management’s assertions with respect to accuracy and completeness of financial records.
· We established controls for the review of each process and software system to identify potential segregation of duties issues and established proper segregation of duties or mitigating controls throughout the organization.
Application controls over financially significant applications with respect to change management and information systems operations.
· We established controls for the review of the access to and security of financially relevant software systems.
Financial reporting controls related to the closing process, including control over non-routine transactions, unusual journal entries and the use of estimates and judgment.
· We strengthened our disclosure review committee charter to solicit and review input from management personnel throughout the Company regarding possible instances of fraud or significant events requiring disclosure.
· We implemented a technical accounting issues forum to address non-routine transactions and the use of critical estimates and judgment.
· We formalized the monthly account reconciliation process for all balance sheet accounts and have implemented a formal review of reconciliations by accounting management.
· We consolidated substantially all accounting functions in the Denver office to provide enhanced communication and reporting capability.
Accounting for Income Taxes related to reconciliation of tax accounts.
· We formalized the monthly account reconciliation process for all balance sheet accounts and have implemented a formal review of reconciliations by accounting management.
· An additional review of financial statement presentation classifications is conducted prior to presentation and disclosure.
Spreadsheet controls related to change management within key financial spreadsheets.
· We adopted new policies and practices around spreadsheets supported by new controls governing change management within key financial spreadsheets.
· We augmented the new spreadsheet change management controls by identifying compensating controls for reliance during the controls maturation process.
Risk Management and Accounting for Derivative Financial Instruments. In connection with management’s assessment of the effectiveness of internal control over financial reporting for the year ended December 31, 2005, we identified and Deloitte & Touche LLP confirmed, as of December 31, 2005, the presence of an additional material weakness related to our risk management and accounting for derivative financial instruments. We did not have adequate internal controls and processes in place to support our management’s assertions with respect to the completeness, accuracy and validity of commodity transactions. The design of internal controls over commodity transactions did not support the independent validation of data or control and review of transaction activity. In particular, personnel responsible for executing and entering transactions into commodity accounting systems also had duties that were not compatible with transaction execution and entry. In order to remediate this material weakness, we added the following personnel in July 2005, January and September 2006, respectively:
· Vice President of Risk and Compliance, to oversee and ensure improvements in our commodity transaction verification and monitoring capabilities.
· Director of Risk Management and staff to establish appropriate verification and monitoring activities associated with our commodity transactions.
· Credit Manager, to establish more robust monitoring and reporting processes around our credit concentrations and risk.
In order to further remediate this material weakness, we also completed the following actions between July 2005 and December 2006:
· We enhanced our risk management and credit policies to more clearly define the oversight roles and define the relationships and responsibilities of all involved parties. These policies were approved at the October 2006 Board of Directors meeting.
· We enhanced our risk management policies and procedures related to the review and approval of material purchase or sale contracts that may meet the definition of derivatives.
· We segregated our front-office (the transaction personnel), mid-office (the controllers), and back-office (the accountants) processes related to our financial commodity transactions and our physical trading activities.
· We enhanced our financial analysis around commodity transactions and our reporting to executive management and the board of directors.
· We moved the responsibility for credit risk management to the mid-office and established enhanced procedures for the management of credit risk.
Management tests of controls conducted in the fourth quarter of 2006 and as of December 31, 2006, provide reasonable assurance that the enhanced and changed controls were operating effectively and that the material weaknesses identified at December 31, 2005, except for the narrowly defined material weakness reported at December 31, 2006 and described in the 2006 Management’s Report on Internal Controls Over Financial Reporting, have been remediated.
Because Javelina was acquired late in 2005, management did not include the internal control processes for the Javelina entities in its assessment of internal controls as of December 31, 2005. Management has included all aspects of internal controls for Javelina in its 2006 assessment.
Remediation of Current Year’s Material Weakness in Internal Control
As reported in Management’s Report on Internal Controls Over Financial Reporting, a material weakness existed related to accounting for derivatives as of December 31, 2006. Specifically, there was an issue related to our prior year material weakness that had not been fully remediated prior to year-end. As of year-end, management did not have a process in place to monitor old contracts in response to changes in SFAS 133 and had not conducted a comprehensive review of all contracts entered into prior to 2006 for the purpose of ensuring that determinations about derivative implications and SFAS 133 issues had been made appropriately and remained appropriate. The reason such a comprehensive review was deemed necessary as 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. The remediation of this material weakness was addressed and completed by management before the filing of this Form 10-K.
Subsequent to year-end, management has enhanced the process for identifying derivatives and conducted a comprehensive review of substantially all contracts across the Company to determine whether derivatives and embedded derivatives have been appropriately identified and that those determinations remain appropriate given evolving literature. No errors with respect to derivatives and embedded derivatives were noted in
that review process. With the conclusion of this review process, management believes this review effectively remediates the material weakness that was identified in the year-end 2006 assessment. Deloitte & Touche, LLP has not audited our remediation procedures and disclaims an opinion on our assertion that the material weakness has been remediated
Management’s Report on Internal Control Over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America and includes those policies and procedures that:
· pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
· provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
· provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.
Management assessed the effectiveness of our internal controls over financial reporting as of December 31, 2006. In making this assessment, management used the criteria established in Internal Control-Integrated Framework issued by the COSO.
A material weakness is a significant deficiency (within the meaning of Public Company Accounting Oversight Board Auditing Standard No. 2), or combination of significant deficiencies, that result in there being a more than remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.
At December 31, 2006, management identified and Deloitte & Touche 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 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 133 issues were made appropriately and remained appropriate. A comprehensive review was deemed necessary as 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.
Deloitte & Touche LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued an attestation report on management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006. The report, which expresses unqualified opinions on management’s assessment and an adverse opinion on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm”.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
MarkWest Hydrocarbon, Inc.
Denver, Colorado
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that MarkWest Hydrocarbon, Inc. and subsidiaries (the “Company”) did not maintain effective internal control over financial reporting as of December 31, 2006, because of the effect of the material weakness identified in management’s assessment based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining
effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error of fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
A material weakness is a significant deficiency, or combination of significant deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weakness has been identified and included in management’s assessment: At December 31, 2006, management identified and we confirmed the existence of a continuing material weakness related to accounting for derivatives. Specifically, there was an issue related to the prior year material weakness in accounting for derivative financial instruments that had not been fully remediated at December 31, 2006. As of December 31, 2006, 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.
The material weakness resulted from deficiencies in the design and operating effectiveness of controls relating to the ongoing monitoring of contracts to update accounting positions based on changes in SFAS No. 133. The operating effectiveness deficiencies relate to the application of normal purchase/normal sale provisions of SFAS No. 133. While this control deficiency could result in material unrealized gains or losses going undetected, no material errors were identified.
This material weakness was considered in determining the nature, timing, and extent of audit tests applied to our audit of the consolidated financial statements as of and for the year ended December 31, 2006, of the Company and this report does not affect our report on such financial statements.
Within the section titled “Remediation of Current Year’s Material Weakness in Internal Control” of Item 9A. Controls and Procedures, management discloses the steps taken to remediate this material weakness prior to the filing of this 10-K. As these procedures were performed subsequent to December 31, 2006, and thus, not subject to our audit procedures, we disclaim an opinion with respect to any representations by management concerning the remediation of the material weakness in existence at December 31, 2006.
In our opinion, management’s assessment that the Company did not maintain effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also, in our opinion because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organization of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2006, of the Partnership and our report dated March 7, 2007 expressed an unqualified opinion on those financial statements.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
March 7, 2007
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
The following table shows information for the directors and executive officers of MarkWest Hydrocarbon, Inc. Executive officers are appointed and directors are elected for three-year terms.
John M. Fox has served as MarkWest Hydrocarbon’s Chairman of the Board of Directors since its inception in April 1988, and in the same capacity for the general partner of MarkWest Energy since May 2002. Mr. Fox also served as President and Chief Executive Officer of MarkWest Hydrocarbon and the general partner of MarkWest Energy from April 1988 until his retirement as President on November 1, 2003 and his resignation as Chief Executive Officer effective December 31, 2003. Mr. Fox was a founder of Western Gas Resources, Inc. and was its Executive Vice President and Chief Operating Officer from 1972 to 1986.
Michael L. Beatty has served as a member of the Board of Directors at MarkWest Hydrocarbon sine June 2005. Mr. Beatty is currently Chairman and CEO of the law firm of Beatty & Wozniak, P.C. located in Denver, Colorado, with a practice focused on energy and natural resources. Mr. Beatty began his career at Vinson & Elkins and later became a professor of law at the University of Idaho before joining the legal department of Colorado Interstate Gas Company, a subsidiary of The Coastal Corporation. Mr. Beatty thereafter served in a variety of legal positions with Coastal, ultimately becoming Executive Vice President, General Counsel and a Director of the company. Mr. Beatty also served as Chief of Staff to Colorado Governor Roy Romer from 1993 to 1995.
Donald C. Heppermann served as Executive Vice President, Chief Financial Officer and Secretary of MarkWest Hydrocarbon, Inc. and the general partner of MarkWest Energy since October 2003 until his retirement in March 2004. Mr. Heppermann joined MarkWest Hydrocarbon and the general partner of the Partnership in November 2002 as Senior Vice President and Chief Financial Officer, and served as Senior Executive Vice President beginning in January 2003. Mr. Heppermann has served as a member of the Company’s Board of Directors since November 2002 and the general partner of the Partnership’s board of directors since its inception in May 2002 and serves as Chairman of the Finance Committee. Prior to joining MarkWest Hydrocarbon and the general partner of MarkWest Energy, Mr. Heppermann was a private investor and a career executive in the energy industry with responsibilities in operations, finance, business development and strategic planning. From 1990 to 1997, Mr. Heppermann served as President and Chief Operating Officer for InterCoast Energy Company, an unregulated subsidiary of Mid American Energy Company. From 1987 to 1990, Mr. Heppermann was employed by Pinnacle West Capital Corporation, the holding company for Arizona Public Service Company, where he was Vice President of Finance. From 1965 to 1987, Enron Corporation and its predecessors employed Mr. Heppermann in a variety of positions, including Executive Vice President, Gas Pipeline Group.
William A. Kellstrom has served as a member of the Board of Directors of MarkWest Hydrocarbon since May 2000 and the general partner of MarkWest Energy since its inception in May 2002. Mr. Kellstrom has held a variety of managerial positions in the natural gas industry since 1968. They include distribution, pipelines and marketing. He held
various management and executive positions with Enron Corporation, including Executive Vice President, Pipeline Marketing and Senior Vice President, Interstate Pipelines. In 1989, he created and was President of Tenaska Marketing Ventures, a gas marketing company for the Tenaska Power Group. From 1992 until 1997 he was with NorAm Energy Corporation (since merged with Reliant Energy, Incorporated) where he was President of the Energy Marketing Company and Senior Vice President, Corporate Development. Mr. Kellstrom retired in 1997 and is periodically engaged as a consultant to energy companies.
Anne E. Mounsey has served as a member of the Company’s Board of Directors since October 2004. From 1991 to 2003, Ms. Mounsey held various positions with the Company, her most recent as Manager of Marketing and Business Development. Ms. Mounsey is the daughter of John M. Fox, the Company’s Chairman of the Board of Directors.
Karen L. Rogers has served as a member of the Board of Directors of MarkWest Hydrocarbon since June 2000. Ms. Rogers serves on the Board’s Audit Committee. Ms. Rogers also serves as the Chief Financial Officer for Winter Ridge Energy since October 2006. In June 2005, Ms. Rogers joined Blacksand Energy, Inc., a privately held oil and gas development and production company, as the Chief Financial Officer. Prior to joining Blacksand Energy, Inc. Ms. Rogers was employed since 2000 as Vice President, Energy Group, for Wells Fargo Bank N.A. Prior to 1997, Ms. Rogers was Senior Vice President and Manager of NationsBank Energy Group Denver, Inc. She has more than 25 years of experience in energy finance and corporate banking.
William F. Wallace has served as a member of the Board of Directors of MarkWest Hydrocarbon since June 2004. Prior to his retirement in 2001, Mr. Wallace was Vice Chairman of the board of directors of Barrett Resources Corp. since 1996, after being named to that position in 1995 following the merger of Barrett Resources and Plains Petroleum Co., both oil and gas exploration companies. From 1994 to 1995, Mr. Wallace was President, Chief Operating Officer and a Director of Plains Petroleum Co. Prior to joining Plains Petroleum; Mr. Wallace spent 23 years with Texaco Inc., an integrated oil and gas company, including six years as Vice President of Exploration for Texaco USA and as Regional Vice President of Texaco’s Eastern Region. Mr. Wallace served on the Kerr-McGee Corporation board of directors from 2004 until its merger with Anadarko in 2006. Previously, he served as a director of Westport Resources Corporation from 1997 until Westport’s merger with Kerr-McGee Corporation in 2004.
Donald D. Wolf has served as a member of the Company’s Board of Directors since June 1996. In September 2004, Mr. Wolf joined Aspect Energy as President and Chief Executive Officer. Mr. Wolf also serves as the Chief Executive Officer of Quantum Resources, a private oil and gas acquisition partnership. Mr. Wolf served as Chairman, Chief Executive Officer and Director of Westport Resources Corporation from April 2000 until Westport’s merger with Kerr-McGee Corporation in 2004. He joined Westport Oil and Gas Company, Inc. in June 1996 as Chairman and Chief Executive Officer and has a diversified 35-year career in the oil and natural gas industry.
Frank M. Semple, President, Chief Executive Office and Director, was appointed as President of both MarkWest Hydrocarbon and the general partner of MarkWest Energy on November 1, 2003. Mr. Semple also became Chief Executive Officer of both MarkWest Hydrocarbon and the general partner of MarkWest Energy on January 1, 2004. Prior to his appointment, Mr. Semple served in various capacities, most recently as Chief Operating Officer of WilTel Communications, formerly Williams Communications Group, Inc. (“WCG”) from 1997 to 2003. Prior to his tenure at WilTel Communications, he was the Senior Vice President/General Manager of Williams Natural Gas from 1995 to 1997, Vice President of Marketing and Vice President of Operations and Engineering for Northwest Pipeline, and Director of Product Movements and Division Manager for Williams Pipeline during his 22-year career with The Williams Companies. During his tenure at Williams Communications, he also served on the board of directors for PowerTel Communications and the Competitive Telecommunications Association (Comptel). On April 22, 2002, WCG and one of its subsidiaries (“Debtors”) filed a petition for relief under the Bankruptcy Code with the United States Bankruptcy Court for the Southern District of New York. On September 30, 2002, the Bankruptcy Court entered an order confirming the Debtors’ plan of reorganization that became effective October 15, 2002. Mr. Semple holds a Mechanical Engineering degree from the United States Naval Academy and is a professional engineer registered in the State of Kansas.
C. Corwin Bromley, Senior Vice President, General Counsel and Secretary, was appointed as General Counsel of MarkWest Hydrocarbon MarkWest Energy in October 2004. Prior to joining MarkWest, Mr. Bromley served as Assistant General Counsel at RAG American Coal Holding, Inc. from 1999 through 2004, and as General-Managing Attorney and Sr. Environmental Attorney at Cyprus Amax Minerals Company from 1989 to 1999. Prior to that, Mr. Bromley was in private practice with the law firm Popham, Haik, Schnobrich & Kaufman from 1984 through 1989. Preceding his legal career, Mr. Bromley worked as a structural/design engineer involved in several domestic and international LNG and energy projects with the firms CBI, Inc. and Chicago Bridge and Iron Company. Mr. Bromley received his J.D. degree from the University of Denver and his bachelor’s degree in civil engineering from the University of Wyoming.
Nancy K. Buese (formerly Masten), Senior Vice President, Chief Financial Officer, was appointed Chief Financial Officer of both MarkWest Hydrocarbon and the general partner of MarkWest Energy in October 2006. Prior to her appointment as CFO, Ms. Buese served as Chief Accounting Officer of the Company and the Partnership’s general partner since November 2005. Prior to joining MarkWest, Ms. Buese was the Chief Financial Officer for Experimental and Applied Sciences (“EAS”) in Golden, Colorado. EAS is a wholly owned subsidiary of the Ross Product Division of Abbott Laboratories. Prior to her employment at EAS, Ms. Buese was a Vice President with TransMontaigne Inc. in Denver, Colorado. Preceding this appointment, Ms. Buese was a Partner with Ernst & Young LLP, having spent time in the firm’s Denver, London, New York and Washington, D.C. offices.
John C. Mollenkopf, Senior Vice President, Chief Operations Officer, was appointed as Chief Operations Officer of both MarkWest Hydrocarbon and the general partner of MarkWest Energy in October 2006. Prior to his appointment as COO, Mr. Mollenkopf served as Senior Vice President, Southwest Business Unit since January 2004 and as Vice President, Business Development since January 2003. Prior to these positions he served as Vice President, Michigan Business Unit, of MarkWest Energy’s general partner since its inception in May 2002 and in the same capacity with MarkWest Hydrocarbon since December 2001. Prior to that, Mr. Mollenkopf was General Manager of the Michigan Business Unit of MarkWest Hydrocarbon since 1997. He joined MarkWest Hydrocarbon in 1996 as Manager, New Projects. From 1983 to 1996, Mr. Mollenkopf worked for ARCO Oil and Gas Company, holding various positions in process and project engineering, as well as operations supervision.
Randy S. Nickerson, Senior Vice President, Chief Commercial Officer, was appointed as Chief Commercial Officer of both MarkWest Hydrocarbon and the general partner of MarkWest Energy in October 2006. Prior to his appointment as CCO, Mr. Nickerson served as Senior Vice President, Corporate Development of MarkWest Hydrocarbon since October 2003, and as Executive Vice President, Corporate Development of the Partnership’s general partner since January 2003. Prior to these positions, Mr. Nickerson served as Senior Vice President of the Partnership’s general partner since its inception in May 2002 and served in the same capacity with MarkWest Hydrocarbon since December 2001. Prior to that, Mr. Nickerson served as MarkWest Hydrocarbon’s Vice President and the General Manager of the Appalachia Business Unit since June 1997. Mr. Nickerson joined MarkWest Hydrocarbon in July 1995 as Manager, New Projects and served as General Manager of the Michigan Business Unit from June 1996 until June 1997. From 1990 to 1995, Mr. Nickerson was a Senior Project Manager and Regional Engineering Manager for Western Gas Resources, Inc. From 1984 to 1990, Mr. Nickerson worked for Chevron USA and Meridian Oil Inc. in various process and project engineering positions.
David L. Young, Senior Vice President, Corporate Services, was appointed to that position for both MarkWest Hydrocarbon and the Partnership’s general partner effective October 2006. Prior to that Mr. Young served as Senior Vice President, Northeast Business Unit, since February 1, 2004. Prior to joining MarkWest, Mr. Young spent eighteen years at The Williams Companies, Inc. in Tulsa, Oklahoma, having served most recently as Vice President and General Manager of the video services business for WilTel Communications, formerly WCG from 1997 to 2003. Prior to that, Mr. Young’s management positions at The Williams Companies included serving as Senior Vice President and General Manager for Texas Gas Pipeline and Williams Central Pipeline Company. On April 22, 2002, the Debtors filed a petition for relief under the Bankruptcy Code with the United States Bankruptcy Court for the Southern District of New York. On September 30, 2002, the Bankruptcy Court entered an order confirming the Debtors’ plan of reorganization that became effective October 15, 2002.
Richard A. Ostberg, Vice President of Risk and Compliance, was appointed the Risk and Compliance Officer of both MarkWest Hydrocarbon and the general partner of MarkWest Energy in July 2005. Prior to that, Mr. Ostberg served as Vice President and Controller of Black Hills Energy. Prior to Black Hills, Mr. Ostberg spent four years with Pacific Minerals, Inc, the operator of the Bridger Coal mine and spent eight years with Deloitte & Touche in their audit practice, including two years consulting from his national office assignment in Washington, D.C.
Andrew L. Schroeder, Vice President Finance, Investor Relations, Treasurer, and Assistant Secretary has served in these with MarkWest Hydrocarbon and the Partnership’s general partner since February 2003. Prior to his appointment, he was Director of Finance/Business Development at Crestone Energy Ventures from 2001 through 2002. Prior to that, Mr. Schroeder worked at Xcel Energy for two years as Director of Corporate Financial Analysis. Prior to that, he spent seven years working with various energy companies. He began his career with Touche, Ross & Co. and spent eight years in public accounting. He is a Certified Public Accountant licensed in the State of Colorado.
Audit Committee Financial Expert The members of the Company’s Audit Committee of the Board of Directors are Mr. Kellstrom (chairman), Mr. Beatty, Ms. Rogers, Mr. Wallace and Mr. Wolf. Each of the individuals serving on our Audit Committee satisfies the standards for independence of the AMEX and the SEC as they relate to audit committees. Our Board of Directors believes each of the members of the Audit Committee is financially literate. In addition, our Board of Directors has determined that
Mr. Kellstrom is financially sophisticated and qualifies as an “audit committee financial expert” within the meaning of the regulations of the SEC.
Audit Committee Pre-Approval Policy
The Audit Committee pre-approves all audit and permissible non-audit services provided by the independent registered public accounting firm on a case-by-case basis. These services may include audit services, audit-related services, tax services and other services. Our Chief Accounting Officer is responsible for presenting the Audit Committee with an overview of all proposed audit, audit-related, tax or other non-audit services to be performed by the independent registered public accounting firm. The presentation must be in sufficient detail to define clearly the services to be performed. The Audit Committee does not delegate its responsibilities to pre-approve services performed by the independent registered public accounting firm to management or to an individual member of the Audit Committee. The Audit Committee may, however, from time to time delegate its authority to the Audit Committee Chairman, who reports on the independent registered public accounting firm services approved by the Chairman at the next Audit Committee meeting.
Code of Conduct and Ethics
We have adopted a Code of Conduct and Ethics that complies with SEC standards, applicable to the persons serving as our directors, officers (including, without limitation, our CEO, CFO and Principal Operations Officers) and employees. This includes the prompt disclosure to the SEC of a Current Report on Form 8-K of any waiver of the code for executive officers or directors approved by the board of directors. A copy of our Code of Business Conduct and Ethics is available free of charge in print to any shareholder who sends a request to the office of the Secretary of MarkWest Hydrocarbon, Inc. at 1515 Arapahoe Street, Suite 700, Denver, Colorado 80202. The Code of Conduct and Ethics is also posted on our website, www.markwest.com.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our directors, executive officers, and persons who own more than 10% of a registered class of our equity securities registered under Section 12 of the Exchange Act, to file with the SEC initial reports of ownership and reports of changes in ownership in such securities. SEC regulations also require directors, executive officers and greater than 10% stockholders to furnish us with copies of all Section 16(a) reports they file.
To our knowledge, based solely on review of the copies of such reports furnished to us and written representations that no other reports were required, we believe our directors, executive officers and greater than 10% stockholders complied with all Section 16(a) filing requirements during the year ended December 31, 2006, except as noted:
· Mr. Heppermann, a Director of the Company, filed one late report, which covered one transaction resulting in an increase of 6,654 shares.
· Mr. Ivey, who retired as Chief Financial Officer of the Company on October 1, 2006, filed one late report, which covered one transaction resulting in a decrease of 2,547 shares.
· Ms. Marle, a Vice President of the Company, filed one late report, which covered one transaction resulting in a decrease of 3,904 shares.
· Mr. Young, a Senior Vice President of the Company, filed one late report, which covered one transaction resulting in a decrease of 156 shares.
We are not aware of any other failure to file a Section 16(a) form with the SEC, or any transaction that was required to be reported, but that was not reported on a timely basis.
Item 11.
Item 11. Executive Compensation.
Compensation Discussion and Analysis
Introduction
MarkWest Hydrocarbon has developed a total compensation philosophy and structure which is designed to be both market responsive and performance based. All our employees, including the executives are employed by MarkWest Hydrocarbon, and are compensated by MarkWest Hydrocarbon. However, the executive officers are also executive officers for the General Partner and perform management services for the Partnership. The Partnership and its general partner, have no direct officers or employees, but instead have entered into a Services Agreement with us to provide the day to day operational, management, accounting, personnel and related administrative services to the Partnership. Under the Services Agreement, the General Partner reimburses us for an allocated portion of our employees’ and executives’ base and incentive
compensation. Further, due to the relatively greater amount of cash flow and income generated by the Partnership, the Partnership funds a proportional share of the short-term cash incentive pool available for our employees, including the executive officers. Accordingly, the General Partner’s Compensation Committees and Boards of Directors have a significant interest in and participate with us, in the determination of the compensation of our executive officers and employees. The compensation of named executive officers presented in this Compensation Discussion and Analysis and the accompanying tables, reflect the total combined compensation for the named executive officers’ services to both the Partnership and MarkWest Hydrocarbon.
Compensation Committee
Committee Members and Independence
The Compensation Committee consists of three members of the board of directors, Donald D. Wolf (Chairman), William F. Wallace, and William A. Kellstrom. The Compensation Committee is charged with overseeing the compensation of the Company’s directors and executives, and with administering the Company’s incentive-compensation plans, including its equity-based plan, the MarkWest Hydrocarbon, Inc. 2006 Stock Incentive Plan. Each member of the Compensation Committee qualifies as an independent director under the requirements of the Securities and Exchange Commission, and the American Stock Exchange.
Role of Committee
The Compensation Committee discharges the Board’s responsibilities relating to general compensation policies and practices and to compensation of our directors and executives. The Compensation Committee also administers our incentive-compensation plans and equity-based plans. In discharging its responsibilities, the Compensation Committee establishes principles and procedures in order to ensure to the Board and the unitholders that the compensation practices of the Company are appropriately designed and implemented to attract, retain and reward high quality directors and executives, and are in accordance with all applicable legal and regulatory requirements. In this context, the Compensation Committee’s authority, duties and responsibilities are:
· To annually review the Company’s philosophy regarding executive compensation.
· To periodically review market and industry data to assess the Company’s competitive position, and to retain any compensation consultant to be used to assist in the evaluation of directors’ and executive officers’ compensation.
· To establish and approve the Company goals and objectives, and associated measurement metrics relevant to compensation of the Company’s executive officers,
· To establish and approve incentive levels and targets relevant to compensation of the executive officers.
· To annually review and make recommendations to the Board to approve, for all principal executives and officers, the base and incentive compensation, taking into consideration the judgment and recommendation of the Chief Executive Officer for the compensation of the principal executives and officers.
· To separately review, determine and approve the Chief Executive Officer’s applicable compensation levels based on the Committee’s evaluation of the Chief Executive Officer’s performance in light of the Company’s and the individual goals and objectives.
· To periodically review and make recommendations to the Board with respect to the compensation of directors, including board and committee retainers, meeting fees, equity-based compensation, and such other forms of compensation as the Compensation Committee may consider appropriate.
· To administer and annually review the Company’s incentive compensation plans and equity-based plans.
· To review and make recommendations to the Board regarding any executive employment agreements, any proposed severance arrangements or change in control and similar agreements/provisions, and any amendments, supplements or waivers to the foregoing agreements, and any perquisites, special or supplemental benefits.
· To review and discuss with management, the Compensation Disclosure and Analysis (CD&A), and determine the Committee’s recommendation for the CD&A’s inclusion in the Company’s annual report filed on Form 10-K with the SEC.
Committee Meetings Our Compensation Committee meets as often as necessary to perform its duties and responsibilities. The Compensation Committee held eight meetings during fiscal 2006, and the chairman of the General Partner’s Compensation Committee also attended four meetings of the MarkWest Hydrocarbon Compensation Committee.
Our Compensation Committee receives and reviews materials prepared by management, consultants, or committee members, in advance of each meeting. Depending on the agenda for the particular meeting, these materials may include:
· Minutes and materials from the previous meeting(s);
· Reports on year-to-date Company and Partnership financial performance versus budget;
· Reports on progress and levels of performance of individual and Company/Partnership performance objectives;
· Reports on the Company’s financial and stock performance versus a peer group of companies;
· Reports from the Committee’s compensation consultant regarding market and industry data relevant to executive officer compensation;
· Reports and executive compensation summary worksheets, which sets forth for each executive officer: current total compensation and incentive compensation target percentages, current equity ownership holdings and general partner ownership interest, and current and projected value of each and all such compensation elements, including distributions and dividends there from, over a five year period.
Compensation Philosophy
General Philosophy
The primary objectives of our compensation program are to attract, retain and challenge high quality executives through a total compensation plan that is both market competitive and performance-based. We strive to accomplish these objectives by compensating all employees, including our Named Executive Officers (the “NEOs”); with total compensation packages consisting of a combination of competitive base salary and incentive compensation. We believe that compensation should be designed to reward executives for achievement of the Company’s financial plans and strategic objectives, and to provide opportunities for increased compensation based on extraordinary performance by our employees, including our NEOs.
Pay for Performance
At the core of our compensation philosophy is our strong belief that pay should also be directly linked to performance. We believe in a pay for performance culture that places a significant portion of executive officer total compensation as contingent upon, or variable with, individual performance, Company performance and achievement of strategic goals including increasing shareholder value.
The performance based compensation for our executives is in the form of (i) annual cash incentives to promote achievement of, and accountability for, shorter term performance plans and strategic goals, and (ii) equity grants, designed to align the long-term interests of our executive officers with those of our shareholders, by creating a strong and direct link between executive compensation and shareholder return over a multiple year performance cycle. Long term incentive equity awards are granted in restricted stock issued under the MarkWest Hydrocarbon 2006 Stock Incentive Plan and phantom units issued under the Partnership’s Long-Term Incentive Plan... These shares/units vest one-third annually over a three-year period. In addition to the performance based equity grants, the NEOs and other key members of management have had the opportunity to purchase from the Company membership interests in the Partnership’s general partner. This opportunity for General Partner ownership was provided in order to incent and retain key employees and align their interests with our long term strategic goals. The purchase arrangements are referred to as the Participation Plan and are discussed in further detail below.
Base Compensation to Reflect Position and Responsibility and Competitiveness within Industry
A key component of an executive’s total compensation, base salaries are designed to compensate executives commensurate with their respective level of experience, scope of responsibilities, sustained individual performance and future potential. The goal has been to provide for base salaries that are sufficiently competitive with other similar-sized energy companies and/or partnerships, both regionally and nationally, in order to attract and retain talented leaders.
Overall Philosophy
Our compensation philosophy is based on the premise of attracting and motivating exceptional leaders, setting high goals, working toward the common objectives of meeting the expectations of customers and stockholders, and rewarding outstanding performance. Following this philosophy, in determining NEO compensation, we consider all relevant factors, such as the competition for talent, our desire to link pay with performance, the use of equity to align NEO interests with those of our stockholders, individual contributions, teamwork and performance, each NEO’s total compensation package, and internal pay equity.
Compensation Setting Process
Management’s Role in the Compensation Setting Process.
Management plays a significant role in the compensation-setting process. The most significant aspects of management role are:
· Assisting in establishing business performance goals and objectives;
· Evaluating employee and company performance;
· CEO recommending compensation levels and awards for executive officers;
· Implementing the Board approved compensation plans; and
· Assistance in preparing agenda and materials for the Committee meetings.
The Chief Executive Officer and the General Counsel and Secretary generally attend the Committee meetings. However, the Committee also regularly meets in executive session. The Chief Executive Officer makes recommendations with respect to financial and corporate goals and objectives, and makes non CEO executive compensation recommendations to the Compensation Committee based on company performance, individual performance and the peer group compensation market analysis. The Compensation Committee considers and deliberates on this information and in turn makes recommendations to the Board of Directors, for the Board’s determination and approval of the NEO’s and other members of senior management’s compensation, including base compensation, short-term cash incentives and long-term equity incentives. The Chief Executive Officer’s performance and compensation is reviewed, evaluated and established separately by the Compensation Committee and ratified and approved by the Board of Directors.
Committee Consultants - Benchmarking
To evaluate all areas of executive compensation, the Compensation Committee seeks the additional input of outside compensation consultants and available comparative information. In 2006, our Compensation Committee engaged Towers Perrin as a compensation consultant, primarily to provide and analyze peer group data to assist our Compensation Committee in assessing executive compensation levels, for total compensation as well as the individual base and incentive components. The peer group data assembled by Towers Perrin included data from sixteen midstream pipeline/energy companies, replicating our industry competitors and giving a large sample size, but which included companies of varying revenue and market-cap sizes, with varying market maturity from start-up to very mature companies. We selected these companies because they are essentially the same set of companies against which we also compare our overall performance as a performance objective. These peer group companies include: ONEOK Partners, Hiland Partners, DCP Midstream, Regency Energy, Sunoco Logistics, Williams Partners, Magellan Midstream, Atlas Pipeline, TEPPCO Partners, TransMontaigne Partners, Crosstex Energy, Martin Midstream, Buckeye Partners, Holly Energy, Valero, L.P., and Eagle Rock. To normalize the data for comparison, Towers Perrin size adjusted the data using regression analysis to a revenue scope of $1 billion. While the Towers Perrin data was provided to the Compensation Committee to demonstrate the market levels within our industry, the consultant did not provide recommendations in terms of pay package for the NEOs. Towers-Perrin did not make recommendations regarding any element of the NEO compensation package.
We also take into account broader based survey data for executive compensation among public companies in the energy industry, both regionally and nationally, such as the “ECI Liquid Pipeline Roundtable 2006 Compensation Survey,” conducted by Effective Compensation, Incorporated, and the Altman Weil, Inc. “Compensation Benchmarking Survey for 2006,” as we believe that this information provides us with a statistically significant sample that supplements the Towers Perrin peer group data.
Setting Total Compensation Levels and Targets
To evaluate our total compensation is competitive and provides appropriate rewards to attract and retain talented leaders, as discussed above, we rely on analyses of peer companies performed by our independent compensation consultants and on other industry and occupation specific survey data available to us. Our general benchmark is to establish both base salary and total compensation for the executive officers at the 50th percentile of the peer group data, recognizing that a significant portion of executive officer total compensation should be contingent upon, or variable with, achievement of individual and Company performance objectives and strategic goals, as well as being variable with stockholder value. Further, while the objective for base salary is at the 50th percentile of the peer group data, Executives’ base salaries are designed to reward core competencies and contributions to the Company, and may be increased above this general benchmark based on (i) the individual’s increased contribution over the preceding year; (ii) the individual’s increased responsibilities over the preceding year; and (iii) any increase in median competitive pay levels.
Setting Performance Objectives
The Company’s annual and five year business plans and strategic objectives are presented by management at the Company’s January board meeting. The board engages in an active discussion concerning the financial targets, the appropriateness of the strategic objectives, and the difficulty in achieving same. After making changes it deems appropriate, the board adopts the Company’s annual business plan. In establishing the compensation plan, our Compensation Committee then utilizes the primary financial objectives from the adopted business plan, operating cash flow, as the primary targets for determining the executive officers’ short-term cash incentives and long term equity incentive compensation. The Committee also establishes additional non-financial performance goals and objectives, the achievement of which is required for funding of a significant portion (25%) of the executive officers’ incentive compensation. In 2006, these non financial performance goals and objectives included achieving accurate financial reporting and timely SEC filings; demonstrating full compliance and superior performance in the Partnership’s environmental, health and safety practices; performing appropriate SOX/404 remediation activities and achieving successful testing of and compliance with SOX requirements; and general and administrative expense management.
Annual Evaluation
The Chief Executive Officer recommends the actual incentive award amounts for all other NEOs based on actual company performance relative to the targets as well as on individual performance, and recommends the NEOs’ base salaries levels for the coming year. The Compensation Committee considers these recommendations at the end of each fiscal year in determining its recommendations to the Board of Directors for the final short-term cash incentive and long-term equity award amounts for each NEO and for the NEO’s base salary levels. The actual incentive amounts awarded to each NEO are ultimately subject to the discretion of the Compensation Committee and the Board of Directors. The incentive awards for the Chief Executive Officer are separately evaluated and determined by the Compensation Committee using similar metrics, and ratified and approved by the Board of Directors.
Other Compensation
Additional equity-based awards may be also granted to NEOs, as well as other employees, upon commencement of employment, for promotions or special performance recognition, or for retention purposes, based on the recommendation of the Chief Executive Officer. In determining whether to recommend additional grants to an NEO, the Chief Executive Officer typically considers the individual’s performance and any planned change in functional responsibility.
Coordination with MarkWest Energy GP, L.L.C. and MarkWest Energy Partners, L.P.
As noted above, our executive officers are also executive officers for the General Partner and these executive officers and our employees perform management, accounting, personnel and related administrative services for the Partnership pursuant to a Services Agreement between us and the General Partner. Under the Services Agreement, the General Partner reimburses us for an allocated portion of our employees’ and executives’ base and incentive compensation. Further, due to the relatively greater amount of cash flow and income generated by the Partnership, the Partnership funds a proportional share of the short-term cash incentive pool available for our employees, including the executive officers. Accordingly, the General Partner’s Compensation Committee participates with us in the determination of the employees’ and executives’ base and incentive compensation and the General Partner and Partnership participates in an allocated portion of the funding of short term incentive cash compensation payments, as well as the long term equity incentive awards provided to our executives and key management employees.
Elements of Executive Compensation
Total Compensation
Total compensation for our NEOs consists of four elements: (i) base salary; (ii) an annual short-term incentive cash award based on achieving specific performance targets as measured by cash flow and other objectives; (iii) an annual long-term equity incentive award, which is also performance based and paid out over a future period in the form of restricted units; and finally (iv) the fair value of each NEO’s investment in the General Partner under the Participation Plan (discussed below). Base salaries are the value upon which both the short-term and long term incentive compensation percentage targets are measured against. See table under section entitled Allocation Among Elements, below. For evaluation and comparison of overall compensation of the executives, and to assist it in making its compensation decisions, the Compensation Committee reviews an executive compensation summary worksheet, which sets forth for each NEO: current compensation and compensation target percentages, current equity ownership holdings and GP interest, and current and projected value of each and all such compensation elements, including distributions and dividends therefrom, over a five year period.
Base Salaries.
Base salaries are designed to compensate executives commensurate with their respective level of experience, scope of responsibilities, and to reward sustained individual performance and future potential. The goal has been to provide for base salaries that are sufficiently competitive with other similar-sized energy companies and/or partnerships, both regionally and nationally, in order to attract and retain talented leaders.
Incentive Compensation
Incentive compensation is intended to align compensation with business objectives and performance and enable the company to attract, retain and reward high quality executive officers whose contributions are critical to short and long-term success of the Company. The NEOs incentive awards are based upon four key performance metrics: 1) the Company’s operating cash flow; 2) MarkWest Hydrocarbon’s operating cash flow; 3) achievement of agreed-upon strategic and corporate performance goals; and 4) each executive’s departmental and individual goals and performance. The actual incentive amounts awarded to each NEO are ultimately subject to the discretion of the Compensation Committee and the Board of Directors
Short-Term Cash Incentive Plan Compensation
Short-term incentive awards are paid out in annual cash awards. The short-term cash incentive award targets for the NEOs are established at the beginning of the year as a percentage of their base salary, and the actual awards are determined at the following year’s January Board of Directors meetings based on actual company performance relative to established goals and objectives, as well as on evaluation of the NEO’s relevant departmental and individual performance during the past year. The short-term cash incentive pool is funded only if a minimum of 75% of the respective cash flow targets of the Partnership and of MarkWest Hydrocarbon is met. Once the threshold is met, then the size of the fund available for all cash incentive awards increases in relation to the extent to which financial targets and non financial objectives are achieved and exceeded, in a linear fashion from threshold through to full stretch, which is capped at 125% of the respective cash flow targets. Short-term cash incentive awards for the NEOs in 2006 were targeted at 40%-50% of base salary for achievement of base-plan performance goals and at up to an additional 40%-50% of base salary for achievement of stretch performance.
Long-Term Equity Incentive Program
In addition to the base salary and short-term cash incentive payments, our NEOs and other members of senior management are awarded long-term equity compensation based upon meeting or exceeding financial and operational targets that are established by the Board of Directors at the outset of the year. Long term incentive equity awards are granted in phantom units issued under the Partnership’s Long-Term Incentive Plan, and in restricted stock issued under the MarkWest Hydrocarbon 2006 Stock Incentive Plan. Allocation of value of long-term equity awards between Partnership phantom units and MarkWest Hydrocarbon shares of restricted stock is based upon time devoted by the individual NEO to the respective entities’ business and affairs. Both the phantom units of Partnership and the restricted shares of MarkWest Hydrocarbon vest in equal installments over a three-year period. Recipients are eligible to collect stock dividends and/or common unit distribution payments on these awards during the vesting period. The awards are intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the shares or units. Recipients do not pay any consideration for the shares or units they receive. Long-term equity incentive award targets for the NEOs in 2006 were targeted at a value of at 40-75% of base salary for achievement of the base-plan goals, and the opportunity for stretch long-term equity incentive awards are left to the discretion of the Compensation Committee and the Board.
Participation Plan
To enable executives to develop and maintain a significant long-term ownership position and alignment with our long term strategic goals, each of the NEOs have been permitted to purchase from the Company membership interests in the Partnership’s General Partner (“GP interest”), which purchase arrangements are in general referred to as the Participation Plan. The purchase and sale price of a GP Interest is based upon a formula which is derived from the then current market value of the Partnership’s common units, and the then quarterly distributions previously paid by the Partnership. The GP Interests were purchased by each NEO at different times and in different percentage levels. The fair value of each NEO’s GP Interest investment under the Participation Plan is included in the Summary Compensation Table under the column “Other Compensation.” Our Board of Directors have determined at this time to cease any further sales of GP Interests.
Due to the differences in each of the NEOs individual level of membership GP interests and the nature and value of such GP Interest as opposed to the incentive grants of phantom units, an NEOs individual GP Interest level is taken into account in setting an executive’s long-term equity incentive target percentages; i.e. generally the higher the individual general partner membership interest, the lower the long-term equity incentive target percentage.
Allocation among Compensation Elements
Under our 2006 compensation structure, the mix and allocation of base salary, short-term incentive, and long-term incentive for our NEOs is shown in the following table. Base salary is the value upon which the incentive award amounts are based. The long-term equity award target percentages of base salary levels for performance achievement of base-plan objectives are generally higher than the target percentage levels for short-term cash incentive awards, but as noted above, the long-term equity incentive target percentage levels are differentiated amongst the NEOs to take into account the individual NEO’s GP Interest values in an effort to partially ameliorate internal inequities for the GP interest values. Opportunities for stretch awards for short-term cash incentive awards for the NEOs are generally targeted up to double of the base-plan target percentages (e.g. an additional incremental target percentage of 40% to 50% of base salary), while the opportunity for stretch awards for long-term equity awards are left to the discretion of the compensation committee and the Board.
Compensation Decisions for 2006
Short-Term Cash Incentive Awards
Short-term cash incentive awards for the NEOs for 2006 were targeted at 40% -50% of base salary for achievement of base-plan performance goals and at up to an additional 40% - 50% of base salary for achievement of stretch performance. In 2006, we exceeded all of our base-plan goals and achieved stretch performance levels in financial and operational targets. The Compensation Committees and the Boards of Directors of the General Partner and of MarkWest Hydrocarbon approved the NEOs short-term cash incentive awards for 2006 at 40% of base salary. For achieving stretch performance in 2006, incremental stretch short term cash incentive awards for the NEOs were granted in the range of approximately 30% to 45% of base salary. The Compensation Committees separately derived the CEO’s base, short-term, and long-term incentive. The CEO’s short-term cash incentive award for 2006, including the incremental stretch component, was granted at 91% of base salary.
Long-Term Equity Incentive Awards
The Compensation Committee set the 2006 long-term incentive award targets for NEOs having a value of at 40-75% of base salary for achievement of the base-plan goals, and the opportunity for stretch long-term equity incentive awards are left to the discretion of the Compensation Committee and the Board. For 2006, we exceeded all of our base-plan goals and achieved stretch performance levels in financial and operational targets. The Compensation Committees and the Boards of Directors of MarkWest Hydrocarbon and the General Partner approved the NEOs long-term equity incentive awards in the range from 40% to 75% of base salary. For achieving stretch performance in 2006, incremental stretch long-term equity incentive awards were granted in the range of approximately 10% to 20% of their base salary. The Compensation Committees separately derived the CEO’s long-term incentive, and these are granted at the Board’s discretion. The CEO’s long-term incentive award for 2006, including the incremental stretch component, was granted at 100% of base salary.
Other Compensation Components
Severance Plan
Directors, executive officers and certain designated key employees are covered under the MarkWest Hydrocarbon, Inc.1997 Severance Plan. The 1997 Severance Plan provides for payment of benefits in the event that (i) the covered person terminates his or her employment for “good reason” (as defined), (ii) the covered person’s employment is terminated “without cause” (as defined), (iii) the covered person’s employment is terminated by reason of death or disability or (iv) the
covered person voluntarily resigns. In the case of (i), (ii) and (iii) above, the covered person shall be entitled to receive base salary and continued medical benefits for a period ranging from six months to twenty-four months, depending upon the covered person’s status at the time of the termination. In the case of (iv) above, the covered person shall be entitled to receive base salary for a period ranging from one month to six months and continued medical benefits for a period ranging from one month to six months. In either case, the aggregate amount of benefits paid to an employee shall in no event exceed twice the employee’s annual compensation during the year immediately preceding the termination. The eligibility for qualifying for these benefits is subject to the covered person entering into acceptable non-compete and release agreements with the Company.
A few of our General Partner’s named executive officers are already party to a Non-Competition, Non-Solicitation and Confidentiality Agreement. As a result of signing the Non-Competition, Non-Solicitation and Confidentiality Agreement, they are eligible to receive severance payments under the above described MarkWest Hydrocarbon 1997 Severance Plan.
Employment Agreements
Except for the Chief Executive Officer, none of the NEOs have an employment agreement.
CEO Employment Agreement
Mr. Semple entered into an executive employment agreement with MarkWest Hydrocarbon on November 1, 2003, pursuant to which Mr. Semple serves as MarkWest Hydrocarbon’s President and Chief Executive Officer and pursuant to which the Board of Directors of MarkWest Hydrocarbon appointed Mr. Semple to serve as the President and Chief Executive Officer of our general partner.
Under the employment agreement, Mr. Semple receives an annual base salary and is entitled to receive benefits for which employees and/or executive officers are generally eligible. In addition, Mr. Semple was awarded phantom units in the general partner under the general partner’s long-term incentive plan and stock options under the MarkWest Hydrocarbon incentive stock plan. Mr. Semple also agreed to purchase from MarkWest Hydrocarbon an interest in each of the general partner and the Partnership, subject to certain repurchase rights by MarkWest Hydrocarbon following the termination of his employment.
Under his employment agreement, in the event Mr. Semple’s employment is terminated without cause, or if he resigns for good reason, he is entitled to severance payments equal to his base salary for a period of thirty-six months. In addition, Mr. Semple is entitled to COBRA benefits for a period of twenty-four months. In the event Mr. Semple voluntarily resigns, he is entitled to receive severance payments equal to his base salary and COBRA benefits for a period of six months. In the event Mr. Semple is terminated for cause, he shall not be entitled to receive any severance or COBRA benefits.
Indemnification Agreements
In January 2007, the Partnership, our General Partner and MarkWest Hydrocarbon entered into Indemnification Agreements with certain directors and officers (“Indemnitees”). By the terms of the Indemnification Agreements, the companies shall indemnify Indemnitees to the fullest extent permitted by law against all expenses and liabilities (as defined in the Indemnification Agreement) if Indemnitees were or are, or are threatened to be made a party to, any threatened, pending or completed action, suit, proceeding, or alternative dispute resolution mechanism, whether civil, criminal, administrative, investigative or other and whether brought by or in the right of the companies or otherwise, by reason of (or arising in part out of) any event or occurrence related to the fact that Indemnitees are or were a director, officer, employee, agent or fiduciary of the companies, or any subsidiary of the companies, or are or were serving at the request of the companies as a director, officer, employee, agent or fiduciary of another corporation, partnership, joint venture, trust or other enterprise, or by reason of any action or inaction on the part of the Indemnitees while serving in such capacity.
Retirement Plans
MarkWest Hydrocarbon maintains a 401(k) plan to which MarkWest matches employee contributions up to the first 6% of an employee’s annual base salary. We do not provide any supplemental retirement benefits to our senior executives.
Change in Control Agreements
Our executives are not awarded any type of protection upon a change in control other than what is offered by the 1997 Severance Plan and the vesting of phantom units upon a change in control.
Perquisites
MarkWest does not provide for any perquisites or any other benefits for its senior executives that are not generally available to all employees.
Internal Pay Equity
We believe that internal equity is an important factor to be considered in establishing compensations for the executive officers. We have not adopted a policy; however, we do review compensation levels to ensure that appropriate equity exists.
Tax Deductibility of Compensation
We generally will seek to maximize the deductibility for tax purposes all elements of compensation. Section 162(m) of the Internal Revenue Code places a $1,000,000 annual limit on the compensation deductible by the Company paid to certain of its executives. The limit, however, does not apply to “qualified performance-based compensation.” We review compensation plans in light of applicable tax provisions and may revise plans to maximize deductibility. However, we may approve compensation that does not qualify for deductibility when we deem it in the best interests of MarkWest.
Option Grants
Although we have granted stock options in the past, we ceased granting stock options after 2004 as incentive awards as a result of accounting, tracking and expensing issues associated with stock options under Statement of Financial Accounting Standards No. 123R. All stock options which were granted in the past were granted at an option price at least equal to the fair market value of our common stock on the date of grant. To further reduce ongoing accounting, tracking and expensing burdens, we vested the remaining 14,950 unvested options in December 2006, which affected a total of eight individuals, including two NEOs and three current directors. As a result of this action described above, these options, with varying remaining vesting schedules, have become immediately exercisable.
Although permitted under MarkWest Energy, L.P.’s Long Term Incentive Plan, no options have been granted by the Partnership.
Compensation Committee Report
We have reviewed and discussed the foregoing Compensation Discussion and Analysis with management. Based on our review and discussion with management, we have recommended to the Board of Directors that the Compensation Discussion and Analysis be included in the Company’s Proxy Statement and its Annual Report on Form 10-K for the year ended December 31, 2006.
Submitted by:
Donald D. Wolf
William F. Wallace
William A. Kellstrom
Members of the Compensation Committee
Summary Compensation Table
The following table sets forth the cash and non cash compensation earned for the year ended December 31, 2006 by each person who served as the Chief Executive Officer, Chief Financial Officer during 2006 and the three other highest paid officers (the “Named Executive Officers”).
(1) See footnote 2 to the consolidated financial statements for a description of our SFAS 123R valuation assumptions.
(2) A credit to compensation expense was recognized for Mr. Ivey's forfeiture of 6,050 stock options at his retirement, which was effective October 1, 2006. In accordance with SFAS 123R the compensation cost recognized in prior periods was reversed for only the unvested portion of the award.
(3) As of December 31, 2006 the fair value of each executive’s investment in the Participation Plan was as follows: Mr. Semple $5,302,255; Ms. Buese $385,098; Mr. Nickerson $4,297,984; Mr. Mollenkopf $4,297,984 and Mr. Bromley $192,549, respectively. Mr. Ivey realized $981,776 upon his retirement, which was effective October 1, 2006.
(4) (4) For the year ended December 31, 2006 the amount of MWP dividends received was as follows: Mr. Semple $10,626.
(5) For the year ended December 31, 2006 our matching contribution to the named executive's 401(k) plan was as follows: Mr. Semple $12,103; Mr. Ivey $10,951; Ms. Buese $13,200; Mr. Nickerson $13,000; Mr. Mollenkopf $12,412 and Mr. Bromley $13,194.
(6) Post termination payments as of December 31, 2006 under the 1997 Severance Plan would be as follows: Mr. Semple $1,055,400; Ms. Buese $170,100; Mr. Nickerson $317,700; Mr. Mollenkopf $302,700 and Mr. Bromley $162,750.
(7) Change in control payments under the MarkWest Energy Partners Long-Term Incentive Plan as of December 31, 2006 would be as follows: Mr. Semple $224,165; Ms. Buese $469,028; Mr. Nickerson $176,385; Mr. Mollenkopf $125,802 and Mr. Bromley $387,188. These dollar amounts are the fair value of unvested restricted (phantom) units as of December 31, 2006 and are also reported in the Outstanding Equity Awards at Year End Table.
(8) Compensation received (net of capital calls) during the year ended December 31, 2006 under the Participation Plan was as follows: Mr. Semple $188,248; Mr. Ivey $23,911; Ms. Buese $16,341; Mr. Nickerson $150,599 and Mr. Mollenkopf $150,599.
(9) Compensation received pursuant to a Consulting Services Agreement for the year ended December 31, 2006 was as follows: Mr. Ivey $19,850.
(10) Compensation received pursuant to a Separation Agreement for the year ended December 31, 2006 was as follows: Mr. Ivey $55,449.
Grant of Plan-Based Awards Table
The following table sets forth the stock awards granted for the year ended December 31, 2006 and estimated future payments under our non-equity incentive compensation plan for the Named Executive Officers. Previously awarded Partnership units have been adjusted to reflect the February 2007 two-for-one unit split (see Note 2 to the consolidated financial statements).
(1) The equity component of our long-term equity incentive plan is granted in MarkWest Hydrocarbon, Inc. (MWP) restricted stock and MarkWest Energy Partners, L.P. (MWE) phantom units after the performance based conditions are satisfied, however, the awards remain subject to forfeiture and service based vesting conditions (these shares/units vest one-third annually over a three-year period). These equity awards are granted pursuant to targets multiples of base salary at achievement of base-plan performance (converted into shares/units valued at date of grant) and the allocations between MWP and MWE shares/unites are based upon time devoted by the individual NEO to the respective entities’ business and affairs during the year. See discussion in the Compensation Discussion and Analysis preceding these tables. Recipients are eligible to collect stock dividends and/or common unit distribution payments on these awards during the vesting period.
(2) MWP stock awards granted on January 31, 2006 were issued under the MarkWest Hydrocarbon 1996 Employee Stock Incentive Plan. The grant on November 1, 2006 was issued under the MarkWest Hydrocarbon 2006 Stock Incentive Plan, which became effective on July 1, 2006.
(3) MWE unit awards were granted under the MarkWest Energy Partners, L.P. Long-Term Incentive Plan.
Outstanding Equity Awards at Year End Table
The following table summarizes the options and stock awards outstanding as of December 31, 2006 for the Named Executive Officers. The market value was determined using the closing prices on MWP and MWE on December 29, 2006. Previously awarded Partnership units have been adjusted to reflect the February 2007 two-for-one unit split (see Note 2 to the consolidated financial statements).
(1) Awards granted in MWP stock have a three year vesting schedule, with one third of the award vesting on the anniversary date of the award each year.
(2) Awards granted in MWE units have a three year vesting schedule, with the vesting period commencing, depending upon the grant date, on the first either January 31st or July 31st of or following the grant date, with one third of the award vesting on the anniversary of such vesting period commencement date each year.
(3) The market value of unvested MarkWest Energy Partners (MWE) units is included in "All Other Compensation" in the Summary Compensation Table. Under the provisions of the Partnership's Long-Term Incentive Plan, these unvested restricted (phantom) units would vest in the event of a change in control.
Option Exercise and Stock Vesting Table
The following table summarizes the option and stock award activity during the year ended December 31, 2006 for the Named Executive Officers. Partnership units that vested during the year have been adjusted to reflect the February 2007 two-for-one unit split (see Note 2 to the consolidated financial statements).
Pension Benefits Table
The Partnership does not offer any pension benefits.
Non-Qualified Deferred Compensation
The Partnership has no non-qualified deferred compensation plans.
Director Compensation Table
The following table sets forth the cash and non cash compensation earned for the year ended December 31, 2006 by each person who served as a Non-employee Director of MarkWest Hydrocarbon, Inc.
(1) See Note 2 to the consolidated financial statements for a description of our SFAS 123R valuation assumptions.
(2) As of December 31, 2006 the aggregate number of stock awards held by each member of our board of directors was 1,733.
(3) As of December 31, 2006 the aggregate number of option awards held was: Mr. Fox 5,091; Mr. Heppermann 6,655; Mr. Kellstrom 1,210; Ms. Mounsey 1,210; Ms. Rogers 1,210 and Mr. Wallace 1,210.
(4) As of December 31, 2006 the fair value of the named director’s investment in the Participation Plan was as follows: Mr. Fox $4,297,984 and Mr. Heppermann $2,681,403.
(5) For the year ended December 31, 2006 the amount of MWP dividends received was as follows: Mr. Fox $34,047 and Mr. Heppermann $15,882.
(6) Compensation received (net of capital calls) during the year ended December 31, 2006 under the Participation Plan was as follows: Mr. Fox $150,599 and Mr. Heppermann $94,124.
(7) Compensation received pursuant to a Consulting Agreement for the year ended December 31, 2006 was a follows: Mr. Heppermann $18,000.
MarkWest Energy G.P., L.L.C.
The following table sets forth the cash and non cash compensation earned for the year ended December 31, 2006 by each person who served as a Non-employee Director of MarkWest Energy G.P., L.L.C.
(1) See footnote 2 to the consolidated financial statements for a description of our SFAS 123R valuation assumptions.
(2) As of December 31, 2006 the aggregate number of unit awards held, retroactively adjusted for the February 2007 unit split were: Mr. Fox 1,666; Mr. Bailey 1,000; Mr. Dempster 1,916; Mr. Heppermann 1,666; Mr. Kellstrom 1,916 and Mr. Nicoletti 1,916.
(3) Change in control payments under the MarkWest Energy Partners Long-Term Incentive Plan as of December 31, 2006 would be as follows: Mr. Fox $59,650; Mr. Bailey $29,825; Mr. Dempster $74,563; Mr. Heppermann $59,650; Mr. Kellstrom $74,563 and Mr. Nicoletti $74,563. These dollar amounts are the fair value of unvested restricted (phantom) units as of December 31, 2006.
(4) As of December 31, 2006 the fair value of the named director's investment in the Participation Plan was as follows: Mr. Fox $4,297,984 and Mr. Heppermann $2,681,403.
(5) Compensation received (net of capital calls) during the year ended December 31, 2006 under the Participation Plan was as follows: Mr. Fox $150,599 and Mr. Heppermann $94,124.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth certain information as of February 15, 2007, regarding the beneficial ownership of our common stock held by beneficial owners of 5% or more of common stock, by each director, by each Named Executive Officer and by all of the directors and officers of the Company as a group.
* Indicates less than 1.0%
(1) Unless otherwise noted, the address for the beneficial owner is c/o MarkWest Hydrocarbon, Inc., 1515 Arapahoe St., Tower 2, Suite 700, Denver, CO 80202.
(2) Beneficial ownership for the purposes of the foregoing table is defined by Rule 13d-3 under the Securities and Exchange Act of 1934, as amended. Under that rule, a person is generally considered to be the beneficial owner of a security if he or she shares the power to vote or direct the voting thereof or to dispose or direct the disposition thereof or has the right to acquire either of those powers within sixty days of February 15, 2007. For executive officers and certain directors, the common stock beneficially owned includes interests in shares held in employee benefit plans. Unless otherwise indicated, the directors and named executive officers have sole voting and dispositive power over the shares listed above, other than shared rights created under joint tenancy or marital property laws as between the directors or named executive officers and their respective spouses.
(3) All percentages have been determined as of February 15, 2007, in accordance with Rule 13d-3 under the Securities Exchange Act of 1934, as amended. For purposes of this table, a person or group of persons is deemed to have beneficial ownership of any share of common stock that such person or group has the right to acquire within sixty days after February 15, 2007. For purposes of computing the percentage of outstanding shares of common stock held by each person or group of persons named above, any security which such person or group has the right to acquire within sixty days after February 15, 2007, is deemed to be outstanding for the purpose of computing the percentage of ownership of such person or group. At February 15, 2007 11,992,520 shares were outstanding. Rights to acquire a total of 65,532 shares of common stock were exercisable within sixty days.
(4) Includes an aggregate of (i) 4,842,387 shares owned directly by MWHC Holding, Inc., an entity controlled by Mr. Fox, of which Mr. Fox is also considered a beneficial owner (Mr. Fox has an indirect pecuniary interest in the MWHC shares); (ii) 81,250 shares held in the aggregate in the Brian T. Crabtree Trust which Mr. Fox is the Trustee; (iii) 118,000 shares held in the aggregate in the Fox Family Foundation; (iv) 1,452 shares held in the aggregate by Bode Blanco, L.L.C.; and (v) 124,235 shares held by the MaggieGeorge Foundation, for which certain family members of Mr. Fox are directors. Mr. Fox disclaims beneficial ownership of the shares held in the MaggieGeorge Foundation within the meaning of Rule 13d-3 under the Exchange Act.
(5) Information is based solely on a Schedule 13G/A filed with the Securities and Exchange Commission by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne, on February 5, 2007, with respect to shares held as of December 31, 2006. The Schedule 13G/A indicates that Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne have shared voting power and dispositive power with respect to 908,099 shares. The reported shares are owned by investment accounts managed, with discretion to purchase or sell securities, by Kayne Anderson Capital Advisors, L.P., as a registered investment advisor. Kayne Anderson Capital Advisors, L.P. is the general partner of the limited partnerships and investment adviser to the other accounts. Richard A. Kayne is the controlling shareholder of the corporate owner of Kayne Anderson Investment Management, Inc., the general partner of Kayne Anderson Capital Advisors, L.P. Mr. Kayne is also a limited partner of each of the limited partnerships and a shareholder of the registered investment company. Kayne Anderson Capital Advisors, L.P. disclaims beneficial ownership of the shares reported, except those shares attributable to it by virtue of its general partner interests in the limited partnerships. Mr. Kayne disclaims beneficial ownership of the shares reported, except those shares held by him or attributable to him by virtue of his limited partnership interests in the limited partnerships, his indirect interest in the interest of Kayne Anderson Capital Advisors, L.P. in the limited partnership, and his ownership of common stock of the registered investment company.
MarkWest GP, L.L.C.
The following table sets forth the beneficial ownership of the Partnership’s general partner as of February 15, 2007, held by the directors, each named executive officer and by all directors and officers as a group.
(1) Includes a 1.6% ownership interest held directly by Mr. Fox and an 89.7% ownership interest held by MarkWest Hydrocarbon. As of February 15, 2007, Mr. Fox beneficially owned approximately 45% of the voting securities of MarkWest Hydrocarbon. Mr. Fox currently serves as MarkWest Hydrocarbon’s Chairman of the Board of Directors. Mr. Fox resigned as President of MarkWest Hydrocarbon effective November 1, 2003, and as Chief Executive Officer effective January 1, 2004. As a result, Mr. Fox may be deemed to be the beneficial owner of the ownership interests owned by MarkWest Hydrocarbon.
MarkWest Energy Partners
The following table sets forth the beneficial ownership of units as of March 1, 2007, held by beneficial owners of 5% or more of the units; by directors of our general partner; by each named executive officer listed in the summary compensation table included in this Form 10-K; and by all directors and officers of our general partner as a group. The units reported have been adjusted to reflect the February 2007 two-for-one unit split (see Note 2 to the consolidated financial statements).
* Indicates less than 1.0%
(1) Unless otherwise noted, the address for the beneficial owner is c/o MarkWest Hydrocarbon, Inc., 1515 Arapahoe St., Tower 2, Suite 700, Denver, CO 80202.
(2) Beneficial ownership for the purposes of the foregoing table is defined by Rule 13d-3 under the Securities and Exchange Act of 1934, as amended. Under that rule, a person is generally considered to be the beneficial owner of a security if he or she shares the power to vote or direct the voting thereof or to dispose or direct the disposition thereof or has the right to acquire either of those powers within sixty days of March 1, 2007.
(3) Ownership is made up of common units and 1,200,000 subordinated units held directly and indirectly through subsidiaries.
(4) Includes 3,738,992 common units and 1,200,000 subordinated units owned by MarkWest Hydrocarbon and its subsidiaries. As of March 1, 2007, Mr. Fox beneficially owned approximately 45% of the voting securities of MarkWest Hydrocarbon. Mr. Fox currently serves as MarkWest Hydrocarbon’s Chairman of the Board. Mr. Fox resigned as President of MarkWest Hydrocarbon effective November 1, 2003, and as Chief Executive Officer effective January 1, 2004. As a result, Mr. Fox may be deemed to be the beneficial owner of the subordinated units owned by MarkWest Hydrocarbon.
(5) Tortoise Capital Advisors LLC (“TCA”) acts as an investment advisor to Tortoise Energy Infrastructure Corporation (“TYG”), a closed-end investment company. TCA, by virtue of an Investment Advisory Agreement with TYG, has all investment and voting power over securities owned of record by TYG. Despite its delegation of investment and voting power to TCA, however, TYG may be deemed to be the beneficial owner under Rule 13d-3 of the Securities and Exchange Act of 1940, of the securities it owns of record because it has the right to acquire investment and voting power through termination of the Investment Advisory Agreement. Thus, TCA and TYG have reported that they share voting power and dispositive power over the securities owned of record by TYG. TCA also acts as an investment advisor to certain managed accounts. Under contractual agreements with individual account holders, TCA, with respect to the securities held in the managed accounts, shares investment and voting power with certain account holders, and has no voting power but shares investment power with certain other account holders. TCA may be deemed the beneficial owner of the securities covered by this statement under Rule 13d-3 of the Act. None of the securities are owned of record by TCA, and TCA disclaims any beneficial interest in such shares.
(6) Information is based on a Schedule 13G/A filed with the Securities and Exchange Commission by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne, on February 5, 2007, with respect to units held as of December 31, 2006. The Schedule 13G/A indicates that Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne have shared voting power and dispositive power with respect to 1,415,780 units. The number of reported units has been adjusted to reflect a 2 for 1 unit split which was paid on February 28, 2007 to unitholders of record on February 22, 2007. The reported units are owned by investment accounts managed, with discretion to purchase or sell securities, by Kayne Anderson Capital Advisors, L.P., as a registered investment advisor. Kayne Anderson Capital Advisors, L.P. is the general partner of the limited partnerships and investment adviser to the other accounts. Richard A. Kayne is the controlling shareholder of the corporate owner of Kayne Anderson Investment Management, Inc., the general partner of Kayne Anderson Capital Advisors, L.P. Mr. Kayne is also a limited partner of each of the limited partnerships and a shareholder of the registered investment company. Kayne Anderson Capital Advisors, L.P. disclaims beneficial ownership of the units reported, except those units attributable to it by virtue of its general partner interests in the limited partnerships. Mr. Kayne disclaims beneficial ownership of the units reported, except those units held by him or attributable to him by virtue of his limited partnership interests in the limited partnerships, his indirect interest in the interest of Kayne Anderson Capital Advisors, L.P. in the limited partnership, and his ownership of common units of the registered investment company.
Item 13.
Item 13. Certain Relationships, Related Transactions and Director Independence
Transactions with Management and Others
In September 2006 the Company entered into a Consulting Services Agreement and Separation Agreement with James G. Ivey. Pursuant to the Consulting Services Agreement, Mr. Ivey provided consulting services to the Company from October 2 through October 31, 2006, and received compensation in the amount of $19,850. Pursuant to the Separation Agreement, the Company agreed to pay Mr. Ivey his base salary for a period of eighteen months, through March 2008, or approximately $0.3 million. Also pursuant to the Separation Agreement, Mr. Ivey executed a release and waiver of claims against the Company and provided non-compete and non-solicitation covenants for the eighteen-month period of separation payments referenced above.
Participation Plan
From time to time, MarkWest Hydrocarbon sells to certain of its executive officers and directors (i) a certain amount of the subordinated units the Company obtained during the formation of MarkWest Energy in May 2002 and (ii) a portion of its ownership interest in the general partner, which was also obtained by the Company during the formation of the Partnership. These transactions are accounted for as compensatory arrangements, consistent with the guidance in APB No. 25, Accounting for Stock Issued to Employees and EITF No 95-16, Accounting for Stock Compensation Arrangements with Employer Loan Features under APB Opinion No. 25, which requires the Company to record compensation expense based on the market value of the subordinated Partnership units and the formula value of the general partner interests held by the employees and directors, at the end of each reporting period. The sales are governed by a purchase and sales agreement that outlines the terms and conditions. Immediately after MarkWest Energy’s initial public offering on May 24, 2002, MarkWest Hydrocarbon sold an 8.6% interest in the general partner of the Partnership and 49,728 of its Partnership subordinated units, to certain officers of MarkWest Hydrocarbon. The officers and executives paid approximately 30% of the purchase price in cash and financed the remainder with loans from MarkWest Hydrocarbon. The loans were evidenced by non-recourse promissory notes requiring the principal balance to be repaid no later than June 30, 2009 and bearing interest at the rate of 7% per annum on the unpaid balance. As of December 31, 2006, there was no loans outstanding related to the initial purchase of the general partner interests or subordinated units by the executives and officers. In accordance with the Sarbanes-Oxley Act of 2002, the Company no longer grants loans to employees.
Since May 2002, MarkWest Hydrocarbon has sold additional interests in the general partner to employees and directors of 5.0% and has repurchased ownership interests from employees and directors of 3.3%. During the same timeframe, the Partnership has sold an additional 28,000 subordinated units and repurchased 16,720. As of December 31, 2006, 10.3% of the general partner is currently held by employees and directors. The Board of Directors of the Partnership’s general partner has determined at this time to cease any further sales of GP Interests
Item 14.
Item 14. Principal Accountant Fees and Services For the years ended December 31, 2006 and 2005, consolidated accounting fees and services for the Company were as follows (in thousands):
(1) Audit-related fees include fees for reviews of registration statements and issuances of consents, reviews of private placement offering documents, benefit plan audits, issuance of letter to underwriters, due diligence pertaining to potential business acquisitions and a review of risk management policies and procedures.
(2) Tax fees include fees for tax return preparation and technical tax advice.
(3) All other fees consist of a subscription to an on-line accounting research tool.
(4) For the year ended December 31, 2005, audit services were provided by KPMG, LLP and Deloitte & Touche, LLP as our principal accountants.
Pre-Approval of Audit and Permitted Non-Audit Services. The Audit Committee is responsible for appointing, setting compensation and overseeing the work of the independent public accountants. The Audit Committee established a policy that requires the Partnership to have the Audit Committee pre-approve all audit and permitted non-audit services from the independent public accountants. The Company’s management submits request to the Audit Committee for pre-approval of any such allowable services. The Audit Committee considers whether the provision of non-audit services by the independent public accountants is compatible with maintaining the accountants’ independence. The Audit Committee considers each engagement of the independent public accountants on a case-by-case basis. The Audit Committee pre-approved the performance of the services described above.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules (a) The following documents are filed as part of this report:
(1) Financial Statements:
You should read the Index to Consolidated Financial Statements included in Item 8 of this Form 10-K for a list of all financial statements filed as a part of this report, which is incorporated herein by reference.
(2) Financial Statement Schedules: All omitted schedules have been omitted because they are not required or because the required information is contained in the financial statements or notes thereto.
(3) Exhibits: See (b) below.
(b) Exhibits required by Item 601 of Regulation S-K.
Exhibit
Number
Description
2.1(6)
Purchase Agreement dated as of March 24, 2003, among PNG Corporation, Energy Spectrum Partners LP, MarkWest Energy GP, L.L.C., MW Texas Limited, L.L.C. and MarkWest Energy Partners, L.P.
2.2(6)
Plan of Merger entered into as of March 28, 2003, by and among MarkWest Blackhawk L.P., MarkWest Pinnacle L.P., MarkWest PNG Utility L.P., MarkWest Texas PNG Utility L.P., Pinnacle Natural Gas Company, Pinnacle Pipeline Company, PNG Transmission Company and Bright Star Gathering, Inc.
2.3(11)
Purchase and Sale Agreement, dated as of November 7, 2003, by and between Shell Pipeline Company, LP and Equilon Enterprises L.L.C., dba Shell Oil Products US, and MarkWest Michigan Pipeline Company, L.L.C.
2.4(10)
Asset Purchase and Sale Agreement dated as of November 18, 2003, by and between American Central Western Oklahoma Gas Company, L.L.C., MarkWest Western Oklahoma Gas Company, L.L.C. and American Central Gas Technologies, Inc.
2.5(13)
Asset Purchase and Sale Agreement and addendum, thereto, dated as of July 1, 2004 by and between American Central Eastern Texas Gas Company Limited Partnership, ACGC Gathering Company, L.L.C. and MarkWest Energy East Texas Gas Company’s L.P.
2.6(20)
Purchase and Sale Agreement dated as of September 16, 2005 by and between El Paso Corporation, as seller, and MarkWest Energy Partners, L.P. as buyer.
2.7(20)
Purchase and Sale Agreement dated as of September 16, 2005 by and between Kerr-McGee Corp., KM Investment Corp., and Javelina Holdings Corp., as joint sellers, and MarkWest Energy Partners, L.P. as buyer.
2.8(20)
Purchase and Sale Agreement dated as of September 16, 2005 by and between Valero Energy Corp., and Valero Javelina, L.P., as sellers, and MarkWest Energy Partners, L.P. as buyer.
3.1(1)
Certificate of Incorporation of MarkWest Hydrocarbon, Inc.
3.2(1)
Bylaws of MarkWest Hydrocarbon, Inc.
4.1(5)
Subordinated Unit Purchase Agreement among MarkWest Hydrocarbon, Inc. and Tortoise MWEP, L.P., dated as of November 20, 2002.
4.2(7)
Purchase Agreement dated as of June 13, 2003, by and among MarkWest Energy Partners, L.P. and Tortoise Capital Advisors, LLC as attorney-in-fact for the Purchasers.
4.3(7)
Registration Rights Agreement dated as of June 13, 2003, by and among MarkWest Energy Partners, L.P. and Tortoise Capital Advisors, LLC as attorney-in-fact for the Purchasers.
4.4(13)
Unit Purchase Agreement dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and MarkWest Energy GP, L.L.C. and each of Kayne Anderson Energy Fund II, L.P., and MarkWest Energy GP, L.L.C. and each of Kayne Anderson Energy Fund II, L.P., Kayne Anderson Capital Income Partners, L.P., Kayne Anderson MLP Fund, L.P., Kayne Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR RV Performance Master Trust, Tortoise Energy Infrastructure Corporation and Energy Income and Growth Fund as Purchasers.
4.5(13)
Registration Rights Agreement dated as of July 29, 2004 among MarkWest Energy Partners, L.P., and each of Kayne Anderson Energy Fund II, L.P., Kayne Anderson Capital Income Fund, LTD., Kayne Anderson Income Partners, L.P., HFR RV Performance Master Trust, Tortoise Energy Infrastructure Corporation and Energy Income and Growth Fund.
4.6(14)
Purchase Agreement dated October 19, 2004, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein.
4.7(14)
Registration Rights Agreement dated October 25, 2004, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein.
4.8(14)
Indenture dated as of October 25, 2004, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee.
4.9(14)
Form of 6.875% Series A Senior Notes due 2014 with attached notation of Guarantees (incorporated by Reference to Exhibits A and D of Exhibit 4.8 hereto).
4.10(27)
Registration Rights Agreement dated as of July 6, 2006 among MarkWest Energy Partners, L.P., with MarkWest Energy Finance Corporation as the Issuers, the Guarantors named therein, and each of RBC Capital Markets Corporation, J.P. Morgan Securities Inc., Wachovia Capital Markets, LLC, A.G. Edwards & Sons, Inc., Credit Suisse Securities (USA) LLC, Fortis Securities LLC, Mizuho International plc, Piper Jaffray & Co. and SG Americas Securities, LLC collectively as Initial Purchasers.
4.11(27)
Indenture dated as of July 6, 2006, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, as Issuers, the Guarantors named therein, and Wells Fargo Bank, National Association, as Trustee.
4.12(27)
Form of 8.5% Series A and Series B Senior Notes due 2016 with attached notation of Guarantees (incorporated by Reference to Exhibits A and D of Exhibit 4.11 hereto).
4.13(29)
Registration Rights Agreement dated as of October 20, 2006 among MarkWest Energy Partners, L.P., with MarkWest Energy Finance Corporation as the Issuers, the Guarantors named therein, and RBC Capital Markets Corporation as the Initial Purchaser.
10.1(1)^
1996 Incentive Compensation Plan.
10.2(1)^
1996 Stock Incentive Plan.
10.3(1)^
1996 Non-employee Director Stock Option Plan.
10.4(1)
Form of Non-Compete Agreement between John M. Fox and MarkWest Hydrocarbon, Inc.
10.5(2)^
MarkWest Hydrocarbon, Inc., 1997 Severance Plan.
10.6+
Amendment to Gas Processing Agreement (Maytown) dated as of March 26, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc.
10.7(3)
Contribution, Conveyance and Assumption Agreement dated as of May 24, 2002, among MarkWest Energy Partners, L.P.; MarkWest Energy Operating Company, L.L.C; MarkWest Energy GP, L.L.C.; MarkWest Michigan, Inc.; MarkWest Energy Appalachia, L.L.C.; West Shore Processing Company, L.L.C.; Basin Pipeline, L.L.C.; and MarkWest Hydrocarbon, Inc.
10.8(4)
Fifth Amended and Restated Credit Agreement among MarkWest Hydrocarbon, Inc. and Certain Financial Institutions as the Lenders, Bank of America, N.A., as the Administrative Agent of the Lenders, and Bank of America Securities, L.L.C., as Lead Arranger and Sole Book Manager, dated as of May 24, 2002.
10.9(3)
Omnibus Agreement dated as of May 24, 2002, among MarkWest Hydrocarbon, Inc.; MarkWest Energy GP, L.L.C.; MarkWest Energy Partners, L.P.; and MarkWest Energy Operating Company, L.L.C.
10.10(3)+
Fractionation, Storage and Loading Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
10.11(3) +
Gas Processing Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
10.12(3) +
Pipeline Liquids Transportation Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
10.13(3)
Natural Gas Liquids Purchase Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
10.14++
Gas Processing Agreement (Maytown) dated as of May 28, 2002, between Equitable Production Company and MarkWest Hydrocarbon, Inc.
10.15(8)
Purchase and Sale Agreement, dated as of June 5, 2003, by and among MarkWest Hydrocarbon, Inc., MarkWest Resources, Inc., and XTO Energy Inc.
10.16(9)
Purchase and Sale Agreement dated as of July 31, 2003, among Raptor Natural Plains Marketing LLC, Raptor Gas Transmission LLC, Power-Tex Joint Venture and MarkWest Pinnacle L.P.
10.17(10)
Amended and Restated Credit Agreement dated as of December 1, 2003, among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Bank One, NA, as Syndication Agent, and Fortis Capital Corp., as Documentation Agent, to the $140,000,000 Senior Credit Facility.
10.18(12) ^
Executive Employment Agreement effective November 1, 2003 between MarkWest Hydrocarbon, Inc. and Frank Semple.
10.19(13)
Second Amended and Restated Credit Agreement dated as of July 30, 2004 among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe Generale, as Documentation Agent to the $315,000,000 Senior Credit Facility.
10.20(13)
First Amendment to the Second Amended and Restated Credit Agreement dated as of August 20, 2004, among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Fortis Capital Corp., as Syndication Agent, Bank One, NA, as Documentation Agent and Societe Generale, as Documentation Agent.
10.21(15)
Third Amended and Restated Credit Agreement dated as of October 25, 2004 among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, Bank One, N.A., as Syndication Agent, Fortis Capital Corp., as Documentation Agent, U.S. Bank National Association, as Documentation Agent, Societe Generale, as Documentation Agent, and Wachovia Bank, National Association, as Documentation Agent, RBC Capital
Markets and J.P. Morgan Securities Inc., as Lead Arrangers and Joint Bookrunners, to the $200,000,000 Senior Credit Facility.
10.22(3) ^
MarkWest Energy Partners, L.P. Long-Term Incentive Plan.
10.23(3) ^
First Amendment to MarkWest Energy Partners, L.P. Long-Term Incentive Plan.
10.24(16)
Credit Agreement among MarkWest Hydrocarbon, Inc. as the Borrower, Royal Bank of Canada, as Administrative Agent and RBC Capital Markets, as Lead Arranger and Sole Bookrunner, to the $25,000,000 Senior Credit Facility.
10.25++
Purchase and Sale of Natural Gas Agreement dated as of September 24, 2004, between MarkWest Hydrocarbon, Inc. and Equitable Production Company.
10.26++
A Firm Natural Gas Processing Agreement dated as of September 24, 2004, between MarkWest Hydrocarbon, Inc. and Equitable Production Company.
10.27++
A Netting, Financial and Security Agreement dated as of September 24, 2004, between MarkWest Hydrocarbon, Inc. and Equitable Production Company.
10.28(17)
Purchase and Sale Agreement dated as of January 24, 2005 by and among Enterprise Products Operating, L.P., as seller and MarkWest Energy Partners, L.P., as buyer.
10.29(19)
Fourth Amended and Restated Credit Agreement, dated as of November 1, 2005, among MarkWest Energy Operating Company, L.LC., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent, JP Morgan Chase Bank, N.A., as Co-Syndication Agent, Fortis Capital Corp., as Co-Syndication Agent, Societe Generale, as Co-Documentation Agent, Wachovia Bank, National Association, as Co-Documentation Agent and RBC Capital Markets, as Sole Lead Arranger and Bookrunner to the $100,000,000 Revolver Facility and $400,000 Term Loan
10.30(21)
Fifth Amended and Restated Credit Agreement dated as of December 29, 2005, among MarkWest Energy Operating Company, L.L.C., as Borrower, MarkWest Energy Partners, L.P., as Guarantor, Royal Bank of Canada, as Administrative Agent and Collateral Agent, JP Morgan Chase Bank, N.A., as Syndication Agent, Fortis Capital Corp., as Co-Documentation Agent, U.S. Bank, National Association, as Co-Documentation Agent, Societe Generale, as Co-Documentation Agent, and Wachovia Bank, National Association, as Co-Documentation Agent, RBC Capital Markets and J.P. Morgan Securities Inc., as Lead Arrangers and Joint Bookrunners, to the $615,000,000 Senior Credit Facility.
10.31(21)
Third Amendment to Credit Agreement dated as of December 30, 2005, among MarkWest Hydrocarbon, Inc., as Borrower, MarkWest Energy, G.P., L.L.C., as Co-Guarantor, MarkWest Michigan, Inc., as Co-Guarantor, MarkWest Resources, Inc., as Co-Guarantor, Matrex, L.L.C., as Co-Guarantor, Royal Bank of Canada, as Administrative Agent for the Lenders, U.S. Bank, National Association and Bank of Oklahoma, N.A. as Lenders to the $25,000,000 Senior Credit Facility.
10.32(22)
First Amended and Restated Credit Agreement dated as of January 31, 2006, among MarkWest Hydrocarbon, Inc., as Borrower, Royal Bank of Canada, as Administrative Agent for the Lenders, U.S. Bank, National Association and Bank of Oklahoma, N.A. as Lenders to the $25,000,000 Senior Credit Facility.
10.33(23)
Amendment No. 1 to the First Amended and Restated Credit Agreement dated as of March 23, 2006, among MarkWest Hydrocarbon, Inc., as Borrower, Royal Bank of Canada, as Administrative Agent for the Lenders, U.S. Bank, National Association and Bank of Oklahoma, N.A. as Lenders to the $25,000,000 Senior Credit Facility.
10.34(24)
Lease Agreement dated as of April 19, 2006 between MarkWest Energy Partners, L.P., and Park Central Property, L.L.C.
10.35(25)^
2006 Stock Incentive Plan
10.36(26)+
Gas Processing Agreement dated as of May 10, 2006 between MarkWest Pinnacle, L.P., and Chesapeake Exploration, L.P.
10.37(28)
Second Amended and Restated Credit Agreement dated as of August 18, 2006 among MarkWest Hydrocarbon, Inc., as Borrower, Royal Bank of Canada, as Administrative Agent and Collateral Agent, and the Lenders party thereto the $65,000,000 Senior Credit Facility.
10.38(30)+
Construction, Operation and Gas Gathering Agreement dated as of September 21, 2006 between MarkWest Western Oklahoma Gas Company, L.L.C., and Newfield Exploration Mid-Continent, Inc.
10.39 *
Form of Indemnification Agreement between MarkWest Hydrocarbon, Inc. and each Non-employee Director and the following Officers of the Company: Frank Semple, President and Chief Executive Officer; Nancy Buese, Senior Vice President and Chief Financial Officer; Randy Nickerson, Senior Vice President and Chief Commercial Officer; John Mollenkopf, Senior Vice President and Chief Operations Officer; C. Corwin Bromley, Senior Vice President, General Counsel and Secretary; David Young, Senior Vice President of Corporate Services; Richard Ostberg, Vice President of Risk and Compliance, and Andrew Schroeder, Vice President and Treasurer dated as of January 26, 2007.
10.40(31)
First Amendment to the Second Amended and Restated Credit Agreement entered into as of February 16, 2007, among MarkWest Hydrocarbon, Inc., as borrower, the undersigned Guarantors, Royal Bank of Canada, as Administrative Agent and Collateral Agent and the undersigned Issuer and Lenders party thereto the $50,000,000 Revolving Credit Facility.
16.1(18)
Letter from KPMG, LLP regarding Change in Certifying Accountants.
21.1 *
List of Subsidiaries of MarkWest Hydrocarbon, Inc.
23.1 *
Consent of Deloitte & Touche, LLP.
23.2 *
Consent of KPMG, LLP.
31.1 *
Chief Executive Officer Certification Pursuant to Rule 13a-14(a) of the Securities Exchange Act.
31.2 *
Chief Financial Officer Certification Pursuant to Rule 13a-14(a) of the Securities Exchange Act.
32.1 *
Certification of the Chief Executive Officer Pursuant to 18 U.S. C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 *
Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(1)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Registration Statement on Form S-1, Registration No. 333-09513, filed with the Commission on August 2, 1996.
(2)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Quarterly Report on Form 10-Q for the three months ended September 30, 1997, filed with Commission on November 13, 1997.
(3)
Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K, filed with the Commission on June 7, 2002.
(4)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Quarterly Report on Form 10-Q for the three months ended June 30, 2002, filed with the Commission on August 14, 2002.
(5)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Current Report on Form 8-K, filed with the Commission on November 25, 2002.
(6)
Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K, filed with the Commission on April 14, 2003.
(7)
Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K filed with the Commission on June 19, 2003.
(8)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Current Report on Form 8-K, filed with the Commission on July 15, 2003.
(9)
Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K filed with the Commission on September 17, 2003.
(10)
Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K, filed with the Commission on December 16, 2003.
(11)
Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K, filed with the Commission on December 31, 2003.
(12)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Annual Report on Form 10-K filed with the Commission on March 30, 2004.
(13)
Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K/A filed with the Commission on September 13, 2004.
(14)
Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K filed with the Commission on October 25, 2004.
(15)
Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K filed with the Commission on October 29, 2004.
(16)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Current Report on Form 8-K filed with the Commission on October 29, 2004.
(17)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Current Report on Form 8-K filed with the Commission on April 6, 2005.
(18)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Current Report on Form 8-K, filed with the Commission on September 23, 2005.
(19)
Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K filed with the Commission on November 7, 2005.
(20)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Current Report on Form 8-K filed with the Commission on September 21, 2005.
(21)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Current Report on Form 8-K filed with the Commission on January 5, 2006.
(22)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Current Report on Form 8-K, filed with the Commission on February 6, 2006.
(23)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Current Report on Form 8-K, filed with the Commission on March 29, 2006.
(24)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Current Report on Form 8-K, filed with the Commission on April 25, 2006.
(25)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Definitive Proxy Statement, filed with the Commission on May 1, 2006.
(26)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Quarterly Report on Form 10-Q for the three months ended June 30, 2006, filed with the Commission on August 7, 2006.
(27)
Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K filed with the Commission on July 7, 2006.
(28)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Current Report on Form 8-K, filed with the Commission on August 23, 2006.
(29)
Incorporated by reference to MarkWest Energy Partners, L.P.’s Current Report on Form 8-K filed with the Commission on October 24, 2006.
(30)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Quarterly Report on Form 10-Q for the three months ended September 30, 2006, filed with the Commission on November 7, 2006.
(31)
Incorporated by reference to MarkWest Hydrocarbon, Inc.’s Current Report on Form 8-K, filed with the Commission on February 23, 2007.
+
Application has been made to the Securities and Exchange Commission for confidential treatment of certain provisions of these exhibits. Omitted material for which confidential treatment has been requested has been filed separately with the Securities and Exchange Commission.
++
Application has been made to the Securities and Exchange Commission for confidential treatment of these exhibits in their entirety. Each exhibit has been filed separately with the Securities and Exchange Commission.
*
Filed herewith.
^
Identifies each management contract or compensatory plan or arrangement.
(b)
The following exhibits are filed as part of this report: See Item 15(a)(2) above.
(c)
The following financial statement schedules are filed as part of this report: None required.
SIGNATURES
Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities with MarkWest Hydrocarbon Inc., the Registrant, and on the dates indicated.