-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, A0NYCqkxl7f9YBMswKLixIQYE+iZWlfiwCtWdRw6Ze2HRk+GRc4bkWld5XDEWopc bN0HXj5qSxxA3HVqqrMk2A== 0000927356-99-000506.txt : 19990331 0000927356-99-000506.hdr.sgml : 19990331 ACCESSION NUMBER: 0000927356-99-000506 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990330 FILER: COMPANY DATA: COMPANY CONFORMED NAME: MARKWEST HYDROCARBON INC CENTRAL INDEX KEY: 0001019756 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS DISTRIBUTION [4924] IRS NUMBER: 841352233 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-14841 FILM NUMBER: 99577130 BUSINESS ADDRESS: STREET 1: 155 INVERNESS DRIVE WEST STREET 2: SUITE 200 CITY: ENGLEWOOD STATE: CO ZIP: 80112-5004 BUSINESS PHONE: 3032908700 MAIL ADDRESS: STREET 1: 155 INVERNESS DRIVE WEST STREET 2: SUITE 200 CITY: ENGLEWOOD STATE: CO ZIP: 80112-5004 10-K405 1 FORM 10-K405 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [X] Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 1998. [ ] Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from __________ to ____________. COMMISSION FILE NUMBER 1-11566 MARKWEST HYDROCARBON, INC. (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) DELAWARE 84-1352233 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 155 INVERNESS DRIVE WEST, SUITE 200, ENGLEWOOD, CO 80112-5000 (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 303-290-8700 Securities registered pursuant to Section 12(b) of the Act: NONE Securities registered pursuant to Section 12(g) of the Act: COMMON STOCK, $0.01 par value Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ____ ---- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X ---- The aggregate market value of voting common stock held by non-affiliates of the registrant on February 28, 1999 was $27,998,768. DOCUMENTS INCORPORATED BY REFERENCE The information required by Part III of this Report (Items 10, 11, 12 and 13) is incorporated by reference from the registrant's proxy statement to be filed pursuant to Regulation 14A with respect to the annual meeting of stockholders scheduled to be held on May 13, 1999. 1 MARKWEST HYDROCARBON, INC. FORM 10-K TABLE OF CONTENTS
Page ---- PART I Items 1. and 2. Business and Properties General.......................................................................................................... 3 Processing and Related Services.................................................................................. 3 Exploration and Production....................................................................................... 6 Sales and Marketing.............................................................................................. 6 Competition...................................................................................................... 7 Operational Risks and Insurance.................................................................................. 7 Governmental Regulation.......................................................................................... 7 Environmental Matters............................................................................................ 8 Employees........................................................................................................ 8 Risk Factors..................................................................................................... 9 Item 3. Legal Proceedings........................................................................................... 9 Item 4. Submission of Matters to a Vote of Security Holders......................................................... 9 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters................................... 9 Item 6. Selected Financial Data..................................................................................... 10 Item 7. Management's Discussions and Analysis of Financial Condition and Results of Operations...................... 11 Item 7A. Quantitative and Qualitative Disclosures About Market Risk.................................................. 16 Item 8. Financial Statements and Supplementary Data................................................................. 17 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........................ 35 PART III Item 10. Directors and Executive Officers of the Registrant......................................................... 35 Item 11. Executive Compensation..................................................................................... 35 Item 12. Security Ownership of Certain Beneficial Owners and Management............................................. 35 Item 13. Certain Relationships and Related Transactions............................................................. 35 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K........................................... 35
GLOSSARY OF TERMS bbls barrels Btu British thermal unit, an energy measurement EBITDA earnings before interest income, interest expense, income taxes, depreciation, depletion and amortization; a cash flow financial measure commonly used in the oil and gas industry Mcf thousand cubic feet of natural gas Mcf/d thousand cubic feet of natural gas per day Mcfe thousand cubic feet equivalent, with oil and other hydrocarbons converted to Mcf MMBtu million British thermal units MMcf million cubic feet of natural gas MMcf/d million cubic feet of natural gas per day Mgal thousand gallons of natural gas liquids NGL natural gas liquids, such as propane, butanes and natural gasoline
2 PART I ITEMS 1. AND 2. BUSINESS AND PROPERTIES GENERAL MarkWest Hydrocarbon, Inc., and its subsidiaries (referred to collectively as the "Company" or "MarkWest") provide natural gas processing and related services. The Company's activities include compression, gathering, treatment and NGLs extraction services to natural gas producers and pipeline companies and fractionation of NGLs into marketable products. MarkWest also purchases and markets natural gas and NGLs and conducts strategic exploration for new natural gas sources for its processing services. MarkWest is the largest processor of natural gas in Appalachia and in 1996 established a new core area in Michigan. MarkWest also explores for and produces natural gas in the Rocky Mountains and is expanding its efforts there to encompass compression and gathering services. The Company's primary activities, processing and marketing, are concentrated in two core areas: the significant gas-producing basin in the southern Appalachian region of eastern Kentucky, southern West Virginia, and southern Ohio (the "Appalachian Core Area" or "Appalachia") and the developing basin in western Michigan (the "Michigan Core Area" or "Michigan"). At the Company's processing plants, natural gas is treated to remove contaminants, and NGLs are extracted and fractionated into propane, normal butane, isobutane, natural gasoline, and a butane-gasoline mix. The Company markets the fractionated NGLs to refiners, petrochemical companies, gasoline blenders, multistate and independent propane dealers, and propane resellers. In addition to processing and NGL marketing, the Company engages in terminaling and storage of NGLs in a number of NGL storage complexes in the central and eastern United States and operates propane terminals in Arkansas and Tennessee. In addition, MarkWest established a natural gas marketing group to provide more services to natural gas producers in its core areas and to assist with its business development efforts. For the year ended December 31, 1998, MarkWest reported a net loss of $1.2 million on revenues of $63.7 million. These results compare to net income of $7.8 million on revenues of $79.7 million for the same period in 1997. EBITDA was $4.5 million, down from $15.8 million reported for 1997. MarkWest continued to perform well operationally in 1998, but fell short of its financial objectives due to poor industrywide processing margins and warm weather in the winter months. The sharp decline in Appalachian processing margins has overshadowed the significant increase in 1998 Michigan volumes. In 1999, Michigan volumes are expected to increase by an additional 50%, and Rocky Mountain gas production is expected to increase by an additional 20%. The Company is actively pursuing opportunities for growth in each of its core areas, focusing on opportunities that could increase stable fee-based business. The Company's fee-based income increased steadily in 1998 and is expected to generate about 50% of MarkWest's income in 1999 (assuming normal processing margins in Appalachia). The Company's principal offices are located at 155 Inverness Drive West, Suite 200, Englewood, Colorado, 80112-5000, and its telephone number is (303) 290- 8700. The Company was founded as a partnership in 1988 and incorporated in Delaware in 1996. PROCESSING AND RELATED SERVICES Appalachian Core Area
YEAR ACQUIRED GAS NGL PRODUCTION OR PLACED THROUGHPUT THROUGHPUT THROUGHPUT INTO SERVICE CAPACITY (MCF/D)/(1)/ (GAL/YEAR)/(1)/ ----------------------------------------------------------------------- PROCESSING PLANTS Kenova Extraction Plant, Wayne County, WV 1996 120,000 Mcf/d 120,000 70,684,000 Boldman Extraction Plant, Pike County, KY 1991 70,000 Mcf/d 50,000 7,872,000 Siloam Fractionation Plant, South Shore, KY 1988 360,000 Gal/d N/A 102,921,000/(2)/ PIPELINE 38.5-mile NGL pipeline Wayne County, WV to South Shore, KY 1988 350,000 Gal/d N/A 70,684,000
YEAR ACQUIRED STORAGE OR PLACED CAPACITY ANNUAL SALES INTO SERVICE (GAL) (GAL/YEAR)/(2)/ ------------------------------------------------------ TERMINAL AND STORAGE Siloam Fractionation Storage, South Shore, KY 1988 14,000,000 100,900,000 Terminal and Storage, West Memphis, AR 1992 2,500,000 27,228,000 Terminal and Storage, Church Hill, TN 1995 240,000 4,985,000
_________________ /(1)/ For the year ended December 31, 1998. /(2)/ Includes fractionation of NGLs extracted at Kenova and Boldman listed above. The Company's direct operations in Appalachia consist of one gas processing facility, a fractionation plant, an NGL pipeline, terminals and related processing assets. The Company believes this region has favorable supply and demand characteristics. The Appalachian Core Area is geographically 3 situated between the TET pipeline to the north and the Dixie pipeline to the south. The historical demand for NGL products in Appalachia has exceeded local production and the capacity of these two lines during peak winter periods. This factor has enabled NGL suppliers in Appalachia (principally MarkWest, Marathon Ashland Petroleum LLC and CNG Transmission Corporation) to price their products (particularly propane) at a premium to Gulf Coast spot prices during times of supply shortages from other sources, especially during winter high demand periods. 1998 NGL production volumes totaled 103 million gallons, equivalent to 1997 production levels. Production would have increased by approximately 4 million gallons during 1998, had there not been scheduled repairs on a third party's natural gas transmission pipeline. These repairs caused a temporary shutdown of MarkWest's Boldman plant for 65 days during 1998 and reduced NGL volumes at the Company's Kenova plant. NGL plant marketing volumes for 1998 totaled 101 million gallons, down slightly from 1997's 103 million gallons. These decreases were primarily due to reduced demand resulting from a warm start to winter. Plants. The Kenova, Boldman and Cobb plants extract liquids from natural gas for further processing at the Company's Siloam fractionator. The Kenova plant, owned and operated by the Company, is situated on a main transmission line of Columbia Gas Transmission Corporation ("Columbia"). All of the Kenova plant's extracted NGLs are transported via the Company's 38.5-mile high-pressure pipeline to its Siloam fractionation facility. Because this pipeline was originally designed to handle a high-pressure ethane-rich stream, it has the capacity to handle almost twice as much product as it becomes available. The Boldman natural gas liquids extraction plant is currently leased to, and operated by, Columbia. The Cobb natural gas liquids extraction plant is owned and operated by Columbia. All of the NGLs recovered at the Boldman and Cobb plants are transported via tanker trucks to the Siloam plant for processing. The Company's fractionation services in the Appalachian Core Area are performed at its Siloam fractionation plant located in South Shore, Kentucky. At this facility, extracted NGLs are separated into NGL products, including propane, isobutane, normal butane and natural gasoline. Substantially all of the Company's fractionation services in its Appalachian Core Area are provided under keep-whole contracts (see further discussion under "Gas Processing Contracts"). Approximately 96% of the fractionation throughput at the Siloam plant comes from the Company's Kenova and Boldman plants and Columbia's Cobb plant. The remaining NGLs are purchased from third-party processors. Columbia Rate Case. In April 1997, the Federal Energy Regulatory Commission approved Columbia's rate case that included a preliminary agreement in which, among other things, Columbia agreed to sell its Cobb plant to MarkWest and to transfer from Columbia to MarkWest the operation of the Boldman plant. Issues arose during ongoing negotiations between MarkWest and Columbia to finalize the terms of the 1997 preliminary agreement. These issues also include matters regarding operations at the Kenova plant. In February 1998, MarkWest filed arbitration proceedings to resolve issues with Columbia regarding the natural gas processing plants in Appalachia. See further discussion under "Item 3--Legal Proceedings." Another major impact of Columbia's rate case is that in addition to having a single processing contract with Columbia, MarkWest now has direct processing contracts with approximately 290 producers delivering gas into Columbia transmission pipelines. Gas Processing Contracts. The Company currently processes natural gas under contracts containing both keep-whole and fee components. In keep-whole arrangements, the principal cost is the reimbursement to the natural gas producers for the Btus extracted from the gas stream in the form of liquids or consumed as fuel during processing. In such cases, the Company creates operating margins by maximizing the value of the NGLs extracted from the natural gas stream and minimizing the cost of replacement of Btus. While the Company maintains programs to minimize the cost to deliver the replacement Btus to the natural gas supplier, the Company's margins under keep-whole contracts can be negatively affected by either decreases in NGL prices or increases in prices of replacement natural gas. Processing contracts with producers also contain a fee component under which the producers pay MarkWest a fee to process their gas and provide a portion of their gas for fuel. At its Kenova plant, MarkWest has contracted with producers for the exclusive right to process the producers' hydrocarbon-rich gas currently delivered into Columbia's transmission pipelines upstream of the Kenova plant through January 2009. The Kenova Processing Agreement between Columbia and MarkWest expires in 2010. Existing NGL purchase agreements with Columbia for Boldman and Cobb have terms expiring in 2003. These agreements contain renewal provisions. Terminal and Storage Facilities. The Company owns and operates a propane terminal and storage facility in West Memphis, Arkansas. The terminal is capable of serving both railcar and trucking transportation. The Company has leased and operated a propane terminal and storage facility in Church Hill, Tennessee, since 1995. The terminal receives product by rail and redelivers the product to dealers and resellers by truck. Rocky Mountain Core Area In 1998, the Company decided to expand its exploration and production business in the Rocky Mountains (described further below) to encompass compression and gathering services. 4 Michigan Core Area
YEAR ACQUIRED GAS NGL PRODUCTION OR PLACED THROUGHPUT THROUGHPUT THROUGHPUT INTO SERVICE CAPACITY (MCF/D)/(1)/ (GAL/YEAR)/(1)/ ---------------------------------------------------------------------- PIPELINE 90-mile sour gas gathering pipeline, Manistee, Mason and Oceana Counties, MI 1996/(2)/ 35,000 Mcf/d 16,000 N/A PROCESSING PLANT Fisk Gas Plant, Manistee County, MI 1998 35,000 Mcf/d 16,000 10,553,000
_______________________ /(1)/ For the year ended December 31, 1998. /(2)/ Extended from 31 miles in 1996 to 63 miles in 1997 and 90 miles in 1998. The Company was attracted to the Michigan Core Area because of the potential for providing gathering and processing services in the area. Substantially all of the natural gas in the Michigan Core Area is sour (contains hydrogen sulfide) and, therefore, has limited outlets for processing. The Company's Michigan operations provide natural gas gathering, treatment, processing and NGL marketing throughout western Michigan. Effective May 6, 1996, the Company began to earn an interest in the Michigan Core Area by funding various capital programs, including a pipeline extension and a natural gas liquids plant. By June 1997, MarkWest completed its earn-in of a 60 percent interest after funding $16.8 million in capital programs. In November 1997, MarkWest acquired the remaining 40 percent joint venture interest in the Michigan Core Area from its previous partner, Michigan Energy Company, L.L.C., for $8.5 million plus contingent payments totaling up to $13.5 million. The future payments are contingent upon several factors, including a minimum internal rate of return and sustained increases in system throughput volumes, ranging from 45 MMcf/d to 75 MMcf/d. Pipeline. The gas gathering pipeline in Manistee and Mason Counties in Michigan gathers and transports sour gas to a treatment plant owned and operated by Shell Offshore, Inc. ("Shell"), in Manistee County. In May 1997, the Company completed the initial phase of the Michigan project, which included the construction of a 32-mile extension to the previously existing 31-mile pipeline. This extension provides an outlet for sour gas production from previously shut-in wells, as well as for gas from new wells to be drilled. During the fourth quarter of 1998, the Company completed the final third of its 27-mile southern pipeline extension. This provided for the connection of a 2 MMcf/d shut-in well in January 1999. An additional estimated 4 MMcf/d in total production remains to be connected in the first quarter of 1999, pending completion of wellhead facilities by the producer. Pipeline throughput volumes averaged 23 MMcf/d for the fourth quarter and 16 MMcf/d for the full year 1998, up 76% and 79% from 1997, respectively. Average daily throughput volumes for 1999, without taking into account any future drilling success, are estimated at 24 MMcf/d, up 50% over 1998. Recent low commodity prices have curtailed producer capital programs. Consequently, no drilling took place in this region in the fourth quarter of 1998. A high priority is being given to increasing the number of wells to be drilled in 1999. MarkWest is in active discussions with several companies to increase its direct involvement in 1999 drilling programs. The Company is also supporting producers for a limited time in 1999 by providing monetary incentives to promote new drilling for reserves that would be dedicated to its facilities. In addition, MarkWest has a 17.5% interest in one well to be drilled in the second quarter and other potential drilling projects later in the year. Other exploration and production companies have developed up to 50 leads and drillable prospects in this region. New drilling is critical to maintaining and increasing volumes. Drilling activity in the next few years will determine the sustainable production level for the project. Natural Gas Liquids Plant. The Fisk Gas Plant, which became fully operational in January 1998, is located adjacent to Shell's treating plant in Manistee, Michigan. This plant processes all of the natural gas gathered by the pipeline and treated by the Shell treating plant, producing propane and other liquid products. The plant also conditions the residue gas such that it can be sold directly into the Michigan Consolidated Gas Company dry distribution system serving western Michigan. Shell Treatment and Processing Agreement. To provide sulfur treatment for natural gas dedicated to the Fisk plant, the Company has entered into a gas treatment and processing agreement with Shell. The agreement, which has an automatic annual renewal unless six months' notice is provided by either party, currently extends through 2011. The agreement provides the Company with 35 MMcf/d of gas treatment capacity at Shell's facility in Manistee County, Michigan. The agreement also permits the Company to cause the expansion of Shell's treatment facilities. Gas Processing Contracts and Availability of Natural Gas Supply. The Company currently processes natural gas under contracts containing both fee and percent- of-proceeds components. The processing contracts with producers contain a fee component under which the producers pay MarkWest a fee to transport and treat their gas. Under the percent-of-proceeds component, the Company retains a portion of the NGLs as compensation for the processing services provided. Operating revenues earned by the Company under percent-of-proceeds contracts increase proportionately with the price of NGLs sold. The Company has exclusive gathering, treatment and processing agreements with four companies: Michigan Production Company ("MPC"); Dominion Midwest Energy, Inc. ("Dominion"); Oceana Exploration and Production Company, LLC ("Oceana"); and Longwood Exploration 5 Company ("Longwood") covering both existing and newly discovered natural gas in Manistee, Mason and Oceana Counties. All gas from these programs is dedicated to the Company's pipeline and is processed at the Company's Fisk Gas Plant. The terms of these agreements with each company are as follows: MPC, through 2016; Dominion, 25 years from initial delivery; Oceana, through 2018; Longwood, 25 years from initial delivery. Oceana has completed two successful wells and committed to drill two additional wells. Any gas produced from these wells will be dedicated to the Company's pipeline and will be processed at the Company's Fisk Gas Plant. The natural gas streams to be dedicated under these agreements will primarily be produced from an extension of the Northern Niagaran Reef trend in western Michigan. To date, over 2.5 trillion cubic feet equivalent of natural gas has been produced from the Northern Niagaran Reef trend. Substantially all of the natural gas produced from the western region of this trend, however, is sour. In the past, while several successful large wells were developed in the region, the natural gas producers lacked adequate gathering and treatment facilities for sour gas, and development of the trend stopped in northern Manistee County. However, with the Company's recently expanded infrastructure of the sour gas pipeline, treatment and processing facilities and increased capacity, the Company has seen and believes there could continue to be, increased development in the region. In addition, the Company believes that improvements in seismic technology may increase exploration and production efforts, as well as drilling success rates. The Michigan pipeline and the treating and processing facilities have a daily operating capacity of 35 MMcf/d, which could be expanded to 50 MMcf/d at an estimated cost of $3 million. Expansion will occur when necessary to meet future drilling success. EXPLORATION AND PRODUCTION Rocky Mountain Core Area Since 1992, MarkWest has invested in Rocky Mountain coal seam natural gas development--primarily in the San Juan Basin. In late 1994, the Company sold its interests for approximately $10.1 million, realizing a pre-tax profit of $4.3 million, and began a new program. Natural gas sold by MarkWest in 1998 totaled 850,042 Mcfe, a 72% increase over 1997 levels. These increases largely resulted from the Company's March 1998 acquisition of 40 producing wells in Colorado's San Juan Basin, building on MarkWest's existing assets in the region. During the fourth quarter of 1998 and early 1999, MarkWest sold or entered into agreements to sell its interests in three non-core properties for an aggregate of $1.2 million. The Company is investing $1.4 million in 1999 to acquire a 49% undivided interest in two separate San Juan Basin gas exploration and production projects located in La Plata County, Colorado. The Company's San Juan projects are now generating production from 28 Mesa Verde/Dakota and 14 Fruitland coal wells. Future projects include four or more deep Dakota drill wells, 20 or more Upper Mesa Verde/Lewis behind pipe recompletions, and more than 20 Fruitland coal wells. All future projects are behind MarkWest operated gathering and compression systems. To date, all Fruitland coal development has occurred on a 320-acre spacing. Due to recent Colorado Oil & Gas Conservation Commission (the "Commission") rulings, the right to drill one additional well per 320-acre spacing unit is now available to MarkWest, subject to approval by the Commission and the Southern Ute Indian Tribe. Upon receiving such approval, MarkWest has the right to drill up to 18 additional wells. Nearly $1 million will be spent in 1999 on high return workover activities on the wells purchased in 1998 to improve production. MarkWest also swapped its 24.5% interest in certain Piceance Basin properties for a 41.7% working interest and operatorship of approximately 40 producing wells in the same basin. The swap comes with a 14,000-acre land position for recompletion and development opportunities. These new projects are expected to increase the Rocky Mountain Core Area's natural gas production by nearly 20% in 1999. Michigan Core Area MarkWest's interests in Michigan exploration and production activities include a 17.5% interest in one well to be drilled in the second quarter of 1999 and other potential drilling projects later in the year. In addition, MarkWest is in active discussions with several companies to increase its direct involvement in 1999 drilling programs. SALES AND MARKETING The Company attempts to maximize the value of its NGL output by marketing directly to distributors, resellers, blenders, refiners and petrochemical companies. The Company minimizes the use of third-party brokers and instead supports a direct marketing staff focused on multistate and independent dealers. Additionally, the Company uses its own trailer and railcar fleet, as well as its own terminals and storage facilities, to enhance supply reliability to its customers. All of these efforts have allowed the Company to maintain premium pricing of its NGL products compared to Gulf Coast spot prices. The majority of the Company's sales of NGLs are based on spot prices at the time the NGLs are sold. Spot market prices are based upon prices and volumes negotiated for short terms, typically 30 days. Historically, the majority of the Company's operating income has been derived from gas processing, NGL fractionation and NGL sales in its Appalachian Core Area. Revenues from the sale of Appalachian NGLs represented 67%, 83% and 91% of total revenues in 1998, 1997 and 1996, respectively. An increasing portion of the Company's revenues is derived from transportation and treating from the Company's Michigan operations as production volumes and throughput have grown significantly in this area. 6 In 1998, the Company started a natural gas marketing group to provide more services to natural gas producers in its core areas and to assist with its business development efforts. COMPETITION The Company faces intense competition in obtaining natural gas supplies for its gathering and processing operations, in obtaining unprocessed NGLs for fractionation, and in marketing its products and services. The Company's principal competitors include major integrated oil and gas companies, major interstate pipeline companies, national and local gas gatherers, NGL processing companies, brokers, marketers and distributors of varying sizes, financial resources and experience. Many of the Company's competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than those of the Company. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. The Company competes against other companies in its gas processing business for supplies of natural gas, for provision of fractionation services, and for customers to which it sells its products. Competition for natural gas supplies is based primarily on location of gas gathering facilities and gas processing plants, operating efficiency and reliability, and ability to obtain a satisfactory price for products recovered. Competitive factors affecting the Company's fractionation services include availability of capacity, proximity to supply and to industry marketing centers, and cost efficiency and reliability of service. Competition for customers is based primarily on price, delivery capabilities, flexibility, and maintenance of quality customer relationships. OPERATIONAL RISKS AND INSURANCE The Company's operations are subject to the usual hazards incident to the exploration for and production, gathering, transmission, processing and storage of natural gas and NGLs, such as explosions, product spills, leaks, emissions and fires. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage, and may result in curtailment or suspension of operations at the affected facility. The Company maintains general public liability, property and business interruption insurance in amounts that it considers to be adequate for such risks. Such insurance is subject to deductibles that the Company considers reasonable and not excessive. Consistent with insurance coverage generally available to the NGL industry, the Company's insurance policies provide coverage for losses or liabilities related to sudden occurrences of pollution or other environmental damage. The occurrence of a significant event not fully insured or indemnified against, and/or the failure of a party to meet its indemnification obligations, could materially and adversely affect the Company's operations and financial condition. Moreover, no assurance can be given that the Company will be able to maintain adequate insurance in the future at rates it considers reasonable. To date, however, the Company has experienced no material uninsured losses or any difficulty in acquiring insurance coverage in amounts it believes are adequate. GOVERNMENT REGULATION Certain of the Company's pipeline activities and facilities are involved in the intrastate or interstate transportation of natural gas and NGLs and are subject to state and/or federal regulation. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 ("NGA"), the Natural Gas Policy Act of 1978 ("NGPA"), and the regulations promulgated thereunder by the Federal Energy Regulatory Commission ("FERC"). In the past, the federal government regulated the prices at which natural gas could be sold, as well as certain terms of service. However, the deregulation of natural gas sales pricing began under terms of the NGPA and was completed in January 1993 pursuant to the Natural Gas Wellhead Decontrol Act of 1989. Thus, all sales of natural gas by the Company currently can be made at unregulated market prices. There can be no assurance, however, that Congress will not reenact price controls in the future which could apply to, or substantially affect, these sales activities. The processing of natural gas for the removal of liquids by non-pipeline companies is not currently viewed by the FERC as an activity subject to its jurisdiction. FERC has made a specific declaration that the Company's gas processing operations or facilities on the Columbia system are exempt from FERC jurisdiction. In the Michigan Core Area, the Company owns and operates pipeline gathering facilities in conjunction with its processing plant. Under the NGA, facilities that have as their "primary function" the performance of gathering activities and are not owned by interstate gas pipeline companies are wholly exempt from FERC jurisdiction. State and local regulatory authorities oversee intrastate gathering and other natural gas pipeline operations. The Michigan Public Service Commission ("MPSC") regulates the construction, operation, rates and safety of certain natural gas gathering and transmission pipelines pursuant to state regulatory statutes. The Company conducts gas pipeline operations in Michigan through an affiliate, which is subject to this regulation by the MPSC. 7 The design, construction, operation, and maintenance of the Company's NGL pipeline facilities are subject to the safety regulations established by the Secretary of the Department of Transportation pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended ("1968 Act"), or by state agency regulations which meet or exceed the requirements of the 1968 Act. The Company's natural gas exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, meeting bonding requirements in order to drill or operate wells and regulating the location of wells, the methods of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with such operations. Production operations are also subject to various conservation laws and regulations. These typically include the regulation of the size of drilling and spacing or proration units and the density of wells which may be drilled therein and the unitization or pooling of oil and gas properties. Whether the state has forced pooling, or integration of smaller tracts to form a tract large enough to conduct drilling operations, or relies only on voluntary pooling can affect the ease with which a property can be developed. State conservation laws also typically establish maximum rates of production of natural gas, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production and the handling of non-hydrocarbon gases, such as carbon dioxide and hydrogen sulfide. The effect of these regulations may limit the amount of oil and gas available to the Company or which the Company can produce from its wells. They also substantially affect the cost and profitability of conducting natural gas exploration and production activities. In as much as such laws and regulations are frequently expanded, amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with these production-related regulations. Commencing in April 1992, the FERC issued a series of orders, generally referred to collectively as Order No. 636, which, among other things, require interstate pipelines to "restructure" to provide transportation services separate or "unbundled" from the interstate pipelines sales of gas. Order No. 636 also requires interstate pipelines to provide open-access transportation on a basis that is equal for all shippers and all suppliers of natural gas. This order was implemented through pipeline-by-pipeline restructuring proceedings. In many instances, the result has been to substantially reduce or bring to an end interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. On July 16, 1996, the United States Court of Appeals for the District of Columbia Circuit upheld the validity of most of the provisions and features of Order No. 636. However, in many instances, appeals remain outstanding in the individual pipeline restructuring proceedings. Order No. 636 is intended to foster increased competition within all phases of the natural gas industry. Additionally, the FERC has issued a number of other orders which are intended to supplement various facets of its open access program, all of which will continue to affect how and by whom natural gas production and associated NGLs will be transported and sold in the marketplace. In its current form, FERC's open access initiatives could provide the Company with additional access to gas supplies and markets and could assist the Company and its customers by mandating more fairly applied service rates, terms and conditions. On the other hand, it could also subject the Company and entities with which it does business to more restrictive pipeline imbalance tolerances, more complex operations and greater monetary penalties for violation of the pipelines tolerances and other tariff provisions. The Company does not believe, however, that it will be affected by any action taken with respect to Order No. 636 materially differently than any other producer, gatherer, processor or marketer with which it competes. ENVIRONMENTAL MATTERS The Company is subject to environmental risks normally incident to the operation and construction of gathering lines, pipelines, plants and other facilities for gathering, processing, treatment, storing and transporting natural gas and other products 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. The following is a discussion of certain environmental and safety concerns related to the Company. It is not intended to constitute a complete discussion of the various federal, state and local statutes, rules, regulations, or orders to which the Company's operations may be subject. For example, the Company, without regard to fault, could incur liability under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (also known as the "Superfund" law), 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. The Company's activities in connection with the operation and construction of gathering lines, pipelines, plants, injection wells, storage caverns, and other facilities for gathering, processing, treatment, storing, and transporting natural gas and other products 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 ("EPA"), which can increase the costs of designing, installing and operating such 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. Environmental laws and regulations may require a permit or other authorization before certain activities may be conducted by the Company. These laws also include fines and penalties for non-compliance. Further, these laws and regulations may limit or prohibit activities on certain lands lying within wilderness areas, wetlands, and areas providing habitat for certain species or other protected areas. The Company is also subject to other federal, state, and local laws covering the handling, storage or discharge of materials used by the Company, or otherwise relating to protection of the environment, safety and health. The Company believes that it is in material compliance with all applicable environmental laws and regulations. EMPLOYEES As of December 31, 1998, the Company had 98 employees. The Company considers labor relations to be satisfactory at this time. 8 RISK FACTORS This Annual Report on Form 10-K contains statements which, to the extent that they are not recitations of historical fact, constitute "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities and Exchange Act of 1934. All forward-looking statements involve risks and uncertainties. The forward-looking statements in this document are intended to be subject to the safe harbor protection provided by Sections 27A and 21E. Factors that most typically impact the Company's operating results and financial condition include: (i) changes in general economic conditions in regions in which the Company's products are located; (ii) the availability and prices of NGLs and competing commodities; (iii) the availability of raw natural gas supply; (iv) the ability of the Company to negotiate favorable marketing agreements; (v) the risks that natural gas exploration and production activities will not occur or be successful; (vi) the Company's dependence on certain significant customers, producers, gatherers, and transporters of natural gas; (vii) competition from other NGL processors, including major energy companies; (viii) the Company's ability to identify and consummate acquisitions complementary to its business; and (ix) winter weather conditions. For discussions identifying other important factors that could cause actual results to differ materially from those anticipated in the forward- looking statements, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this Form 10-K. ITEM 3. LEGAL PROCEEDINGS Reference is made to Note 5 of the Company's Consolidated Financial Statements in Item 8 of this Form 10-K. West Shore Processing Company, LLC ("West Shore"), and Basin Pipeline, LLC ("Basin"), indirect subsidiaries of the Company, filed a lawsuit against Michigan Production Company, LLC ("MPC"), on October 27, 1998, in District Court for the City and County of Denver, State of Colorado, for failure of MPC to convey a lateral pipeline and related rights of way in accordance with provisions of a Gas Gathering, Treating and Processing Agreement with West Shore dated May 2, 1996. In its response dated December 24, 1998, MPC acknowledges the contract but denies an obligation to convey the facilities by reason of alleged breaches of contract by West Shore. MPC also asserted counterclaims for breach of contract, tortious interference, breach of fiduciary duty and civil conspiracy against West Shore, Basin and MarkWest Michigan, Inc. ("MWM"). MPC seeks to join MWM, a subsidiary of MarkWest Hydrocarbon, Inc., as an involuntary Plaintiff in the litigation. MPC seeks unspecified damages for alleged construction delays. The MPC claims are primarily asserted as a purported third-party beneficiary of rights under the Participation, Ownership and Operating Agreement for West Shore, an agreement entered into between MWM and Michigan Energy Company ("MEC"), an affiliate of MPC. The interest of MEC in West Shore was acquired by MWM pursuant to a Purchase and Sale Agreement dated November 21, 1997. As part of that agreement, any and all claims of MEC were released. The MarkWest entities intend to vigorously defend against these counterclaims, which are believed to be without merit. In an unrelated matter, on February 1, 1999, MWM, West Shore and Basin, together with John Fox and Arthur Denney, were named as third-party defendants in connection with counterclaims asserted by MPC, Williams Energy Services Company, Millenium Energy Fund LLC, and MEF Production Payment Trust against KCS Michigan Resources, Inc., and DDD Energy, Inc., in the 27th Circuit Court for the County of Oceana, Michigan. KCS Michigan Resources, Inc., and DDD Energy, Inc., initiated that action as plaintiffs on or about October 7, 1998. Messrs. Fox and Denney are directors and officers of MarkWest. In this counterclaim, MPC and other parties who are defendants and counterclaimants assert valid title to certain leases in which the MarkWest entities have no interest. MPC and the other counterclaimants are also claiming slander of title to real and personal property, unjust enrichment, tortious interference with contract, civil conspiracy, breach of contracts, and breach of fiduciary duties, and they are seeking unspecified damages. The MarkWest entities are vigorously defending themselves against these claims, believing that they have been improperly named as third-party defendants and that the claims are without merit. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There were no matters submitted to a vote of security holders during the quarter ended December 31, 1998. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The American Stock Exchange began trading shares of MarkWest Hydrocarbon, Inc. under the ticker symbol NRG on Monday, February 22, 1999. The Company's stock formerly traded on the Nasdaq National Market under the ticker symbol MWHX. MarkWest's ticker symbol NRG was chosen to represent "energy." As of January 7, 1999, there were 8,531,206 shares of common stock outstanding held by 379 holders of record. The following table sets forth quarterly high and low sales prices as reported by the Nasdaq National Market for the periods indicated. 9
HIGH LOW ------- ------- 1998 Fourth Quarter....................... 11 1/2 7 Third Quarter........................ 15 3/4 8 3/4 Second Quarter....................... 22 1/2 14 3/4 First Quarter........................ 22 1/2 19 1997 Fourth Quarter....................... 23 3/4 18 1/4 Third Quarter........................ 25 14 1/2 Second Quarter....................... 16 12 First Quarter........................ 17 1/4 14
The Company has paid no dividends on the common stock and anticipates that, for the foreseeable future, it will continue to retain earnings for use in the operation of its business. Payment of cash dividends in the future will depend upon the Company's earnings, financial condition, any contractual restrictions, restrictions imposed by law and other factors deemed relevant by the Company's Board of Directors. ITEM 6. SELECTED FINANCIAL DATA The selected consolidated statement of operations and balance sheet data for the years ended December 31, 1998, 1997 and 1996, and as of December 31, 1998 and 1997, are derived from, and are qualified by reference to, audited consolidated financial statements of the Company included elsewhere in this Form 10-K. The selected consolidated statement of operations and balance sheet data set forth below for the year ended December 31, 1995 and 1994, and as of December 31, 1996, 1995 and 1994, have been derived from audited financial statements not included in this Form 10-K. The selected consolidated financial information set forth below should be read in conjunction with "Management's Discussions and Analysis of Financial Condition and Results of Operations" and the Company's Consolidated Financial Statements and related notes thereto included in this Form 10-K.
Year Ended December 31, ------------------------------------------------------------------- 1998 /(5)/ 1997 /(5)/ 1996 1995 1994 ------------------------------------------------------------------- (in thousands, except per share amounts and operating data) STATEMENT OF OPERATIONS: Revenues....................................... $ 63,698 $ 79,683 $ 71,952 $ 48,226 $ 52,963 Income (loss) before taxes, extraordinary item and cumulative effect of change in accounting.................................... (1,978) 12,397 14,760 7,824 5,120 Provision (benefit) for income taxes........... (767) 4,550 6,991 -- -- Income (loss) before extraordinary loss........ (1,211) 7,847 7,769 7,824 5,120 Extraordinary loss............................. -- -- -- (1,750) -- Net income (loss)............................. (1,211) 7,847 7,769 6,074 5,120 Basic earnings per share (historical information; see note /(1)/ for pro forma information assuming the Company had been a taxable entity)............................... (0.14) 0.92 1.21 1.06 0.89 Earnings per share assuming dilution (historical information; see note /(1)/ for pro forma information assuming the Company had been a taxable entity).................... (0.14) 0.91 1.20 1.06 0.89 Weighted average shares outstanding /(2)/...... 8,490 8,485 6,415 5,725 5,725 BALANCE SHEET DATA (AS OF DECEMBER 31): Working capital /(3)/ ......................... $ 11,463 $ 14,603 $ 11,896 $ 10,369 $ 10,634 Total assets .................................. 103,631 98,657 78,254 46,896 35,913 Long-term debt ................................ 38,597 33,931 11,257 17,500 9,887 Partners' capital ............................. -- -- -- 25,161 22,183 Stockholders' equity .......................... 50,035 51,548 43,664 -- --
10
Year Ended December 31, ------------------------------------------------------------------- 1998 /(5)/ 1997 /(5)/ 1996 1995 1994 ------------------------------------------------------------------- (in thousands, except per share amounts and operating data) OPERATING DATA: Appalachia: NGL production--Siloam plant (Mgal)............ 102,921 102,453 94,909 92,239 99,735 NGLs marketed--Siloam plant (Mgal)............. 100,900 103,424 94,595 95,484 97,848 NGL sales price: Per gallon ............................... 0.304 0.482 0.448 0.354 0.338 Per MMBtu ............................... 3.15 5.01 4.66 3.68 3.51 Natural gas cost (per MMBtu) /(4)/ ............ 2.45 2.65 2.44 1.88 2.29 Processing margin (per MMBtu) ................. 0.70 2.36 2.22 1.80 1.22 Terminal throughput (Mgal) .................... 32,213 30,332 37,851 31,206 32,665 Michigan: Pipeline throughput (MMcf)................... 5,829 3,247 1,161 -- -- NGLs marketed (Mgal) ........................ 10,554 -- -- -- -- Rocky Mountains: Natural gas sold (Mcfe)...................... 850,000 493,000 270,000 N/M N/M
_______________________ N/M--Not meaningful. /(1)/ Prior to October 7, 1996, the Company was organized as a partnership-- MarkWest Hydrocarbon Partners, Ltd. ("MarkWest Partnership")--and consequently, was not subject to income tax. Effective October 7, 1996, the Company reorganized (the "Reorganization"), and the existing general and limited partners exchanged 100% of their interests in MarkWest Partnership for 5,725,000 common shares of the Company. Pro forma information has been presented for purposes of comparability as if the Company had been a taxable entity for all periods presented:
Year ended December 31, -------------------------------- 1996 1995 1994 -------- -------- -------- Historical income before income taxes...................... $14,760 $ 7,824 $ 5,120 Pro forma provision for income taxes....................... 5,609 2,937 1,424 Pro forma net income....................................... 9,151 4,887 3,696 Pro forma basic earnings per share......................... 1.16 0.85 0.65 Pro forma earnings per share assuming dilution............. 1.15 0.85 0.65 Pro forma weighted average shares outstanding /(a)/........ 7,908 5,725 5,725
___________________ /(a)/ Pro forma weighted average shares outstanding for the year ended December 31, 1996, represents the weighted average of, for the period prior to the initial public offering (the "Offering"), the number of common shares issued in the Reorganization plus the number of shares issued in the Offering for which the net proceeds were used to repay outstanding indebtedness and, for the period subsequent to the Offering, the total number of common shares outstanding. Pro forma weighted average shares outstanding for the years ended December 31, 1995 and 1994, represent the weighted average number of common shares issued in the Reorganization. /(2)/ Weighted average shares outstanding for the year ended December 31, 1996, represents the weighted average of, for the period prior to the Company's initial public offering, the number of common shares issued in the Reorganization and, for the period subsequent to the Offering, the total number of common shares outstanding. Weighted average shares outstanding for the years ended December 31, 1995 and 1994, represent the weighted average number of common shares issued in the Reorganization. /(3)/ Includes cash of $2,055; $1,364; $4,401; $761; and $5,468, respectively. /(4)/ Represents cost of sales for Appalachia. Includes transportation cost of unfractionated liquids from Cobb and Boldman to Siloam and Cobb fuel charge, totaling approximately $0.20/MMBtu. /(5)/ 1998 and 1997 results reflect the Company's acquisition of the remaining 40 percent interest of the Michigan project in November 1997. ITEM 7. MANAGEMENT'S DISCUSSIONS AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following analysis should be read in conjunction with the selected financial data and the Company's Consolidated Financial Statements included in this Form 10-K. 11 RESULTS OF OPERATIONS - ---------------------- Year Ended December 31, 1998, Compared to Year Ended December 31, 1997 (in thousands of dollars)
For the year ended December 31, 1998 1997 Change ---------- ---------- ----------- Revenue................................... $63,698 $79,683 $(15,985) Gross profit /(1)/........................ $ 5,236 $18,833 $(13,597) Income (loss) before income taxes......... $(1,978) $12,397 $(14,375) Provision (benefit) for income taxes...... (767) 4,550 (5,317) ---------- ---------- ----------- Net income (loss)......................... $(1,211) $ 7,847 $ (9,058) ========== ========== ===========
______________________ /(1)/ Excludes interest income, general and administrative expense and interest expense. For the year ended December 31, 1998, MarkWest reported a net loss of $1.2 million, or $0.14 per share, on revenues of $63.7 million. These results compare to net income of $7.8 million, or $0.92 per share, on revenues of $79.7 million for the same period in 1997. The net loss in 1998, compared to net income in 1997, largely resulted from a reduction of $9.9 million, or $1.16 per share in after-tax gas processing margins (a $0.10 per MMBtu processing margin swing impacts MarkWest's after-tax earnings by approximately $600,000). Appalachia's full-year 1998 gas processing margin of $0.70 per MMBtu was more than 60% below its 10-year average of $1.80 per MMBtu and down by 70% compared to 1997's average of $2.36 per MMBtu. The decrease in margin was due to a combination of weak NGL prices, which resulted from 35% lower crude oil prices, and relatively strong natural gas costs that negatively impacted the entire natural gas processing industry. Michigan's after-tax operating income totaled $1.6 million for 1998, or $0.19 per share, up from break-even in 1997. Increases in depreciation, depletion and amortization, and net interest expense were largely offset by savings in operating costs and general and administrative costs. Gathering, processing and marketing revenue. Gathering, processing and marketing revenue decreased $15.5 million or 20% for the year ended December 31, 1998, compared to the year ended December 31, 1997. The Company's Appalachian operations accounted for the majority of the overall revenue decrease, primarily as a result of weak NGL prices in 1998 compared to 1997. In addition, fee gas processed in 1998 only includes volumes processed at the Company's Kenova plant beginning March 1, 1998. In 1997 and early 1998, fee gas processed included volumes at the Boldman and Cobb plants in addition to the Kenova plant. The loss of fee revenue is partly offset by cost savings realized from not operating Boldman and Cobb. The above factors were partially offset by an 80% increase in the volume of gas processed in the Company's Michigan operations during the year ended December 31, 1998, compared to the year ended December 31, 1997. Gas processed in the Company's Michigan operations contributed both fee-based processing income and revenues from the sale of propane and other liquids extracted at the Company's new NGL extraction plant, which began operations in January 1998. Oil and gas revenue. Oil and gas revenue increased $296,000 for the year ended December 31, 1998, compared to the year ended December 31, 1997. This increase was primarily attributable to an increase in gas production from the prior year. Interest income. Interest income decreased $461,000 for the year ended December 31, 1998, compared to the year ended December 31, 1997. During 1997, interest income was primarily derived from a note receivable, which accrued interest at a rate of 5.98%. The note was for the costs incurred by the Company for the construction of the 32-mile extension to the gas pipeline in Michigan, which was completed in 1997. During 1998, the note was forgiven in exchange for the title to the pipeline extension. Cost of sales. Cost of sales decreased $2.8 million, or 6%, for the year ended December 31, 1998, compared to the year ended December 31, 1997. The Company's Appalachian operations accounted for the majority of the decrease, primarily as a result of a decrease in the unit cost of propane at the Company's terminals. Operating expenses. Operating expenses decreased $501,000, or 4%, for the year ended December 31, 1998, compared to the year ended December 31, 1997. In response to low processing margins, the Company implemented cost-controlling measures and consequently reduced operating costs during 1998, compared to 1997. This decrease was partially offset by the introduction of operational costs from the Company's new NGL extraction plant in Michigan for a full year during 1998. General and administrative expenses. General and administrative expenses decreased $1.3 million, or 20%, for the year ended December 31, 1998, compared to the year ended December 31, 1997. General and administrative expenses incurred during 1997 included a continuation of many initial costs, including significant professional service fees, incurred in connection with the Company's reorganization into a public company following the initial public offering in October 1996. In addition, in response to low processing margins throughout 1998, the Company implemented cost-controlling measures and consequently reduced general and administrative expenses. 12 Depreciation, depletion and amortization. Depreciation, depletion and amortization increased $1.3 million, or 42%, for the year ended December 31, 1998, compared to the year ended December 31, 1997. This increase was principally due to increased depreciation attributable to the Company's new NGL extraction plant and pipeline extension in Michigan. Interest expense. Interest expense increased $1.3 million, or 154%, for the year ended December 31, 1998, compared to the year ended December 31, 1997. This increase was principally due to an increase in average outstanding long-term debt in 1998 compared to 1997. Year Ended December 31, 1997, Compared to Year Ended December 31, 1996 (in thousands of dollars)
For the year ended December 31, 1997 1996 Change ---------- ---------- --------- Revenue $79,683 $71,952 $ 7,731 Gross profit /(1)/ $18,833 $20,346 $(1,513) Income before income taxes $12,397 $14,760 $(2,363) Provision for income taxes 4,550 6,991 (2,441) ---------- ---------- --------- Net income $ 7,847 $ 7,769 $ 78 ========== ========== ========= Pro forma information /(2)/ Income before income taxes $12,397 $14,760 $(2,363) Provision for income taxes 4,550 5,609 (1,059) ---------- ---------- --------- Net income $ 7,847 $ 9,151 $(1,304) ========== ========= =========
_______________________ /(1)/ Excludes interest income, general and administrative expense and interest expense. /(2)/ 1996 information is pro forma for net income. Prior to a reorganization in October 1996, MarkWest was organized as a partnership and, consequently, was not subject to income tax. Pro forma net income for 1996 has been presented for purposes of comparability as if MarkWest had been a taxable entity. For the year ended December 31, 1997, income before income taxes was $12.4 million, compared to income before income taxes of $14.8 million, for the year ended December 31, 1996. The decrease in income before income taxes was primarily a result of the effect of an industrywide decrease in prices from 1996, when near record high levels had a positive impact on the Company's terminal operations. As a result, in 1996, the terminals recorded above average gross margins compared to relatively flat margins in 1997, when prices dropped significantly in the first quarter and margins remained low throughout the year. This factor was partially offset by increased volumes and margins at the Company's Appalachia plants. Gathering, processing and marketing revenue. Gathering, processing and marketing revenue increased $7.5 million, or 11%, for the year ended December 31, 1997, compared to 1996, due to a variety of reasons. The Company's Appalachian operations accounted for the majority of the overall revenue increase, primarily on the strength of favorable results recognized in 1997 from hedging positions put in place during the fourth quarter of 1996. Fee gas volumes processed in 1997, which includes fee gas processed at the Boldman and Cobb plants effective February 1997, as well as fee gas processed at the Kenova plant, increased because of a change in the structure of the Company's processing fee arrangements effective in early 1997. In addition, the Company's Siloam plant sold a record 103 million gallons in 1997, a 9% increase over the previous year. The above factors were substantially offset by a 20% decrease in throughput at the Company's terminals. Moreover, the terminals suffered price decreases up to 18% compared to 1996, especially during the fourth quarter at which time near record prices existed in the prior year. The Company's Michigan operations contributed the remaining increase in revenue in 1997 compared to the year ended December 31, 1996, principally as the result of a 180% increase in the volume of gas processed. The Company's activities in Michigan were operational for a full year for the first time in 1997. Additionally, the connection of another company's well to MarkWest's pipeline following the well's completion during the second quarter of 1997 also contributed to the volume increase. Oil and gas revenue. Oil and gas revenue increased $531,000, or 149%, for the year ended December 31, 1997, compared to 1996. This increase was directly attributable to an increase in production from nine new wells in 1997. Interest income. Interest income increased $469,000, or 244%, for the year ended December 31, 1997, compared to 1996. The increase was primarily due to interest earned on a note receivable, which accrued interest at a rate of 5.98%. The note was for the costs incurred by the Company for the construction of the 32-mile extension to the gas pipeline in Michigan. 13 Cost of sales. Cost of sales increased $4.8 million, or 12%, for the year ended December 31, 1997, compared to 1996. The Company's Appalachian operations accounted for the majority of the increase, primarily as a result of a 6% increase in unit costs and a 9% increase in volumes sold at the Company's Siloam plant. This increase was substantially offset by a 20% decrease in throughput at the Company's terminals. The remaining increase was a direct result of the increase in the volume of gas processed by the Company's Michigan operations. Operating expenses. Operating expenses increased $3.7 million, or 49%, for the year ended December 31, 1997, compared to 1996. The majority of the increase was driven by the Company's operations in Michigan, which commenced operations in May 1996. The remaining increase resulted from additional repair and maintenance and other operating costs at the Company's Appalachian facilities, including operating costs attributable to the Company's Boldman plant and Columbia's Cobb plant, pursuant to the change in fee structure described previously. General and administrative expenses. General and administrative expenses increased $1.9 million, or 40%, for the year ended December 31, 1997, compared to 1996. This increase was attributable to administrative support activities related to the new operations in Michigan and to costs incurred in connection with being a public company for a full year in 1997. Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense increased $336,000, or 12%, for the year ended December 31, 1997, compared to 1996. This increase was principally due to increased depreciation attributable to the Company's new Michigan operations. Provision for income taxes. The provision for income taxes decreased $2.4 million for the year ended December 31, 1997, compared to 1996. The decrease was primarily a result of the one-time charge of $3.7 million taken in the fourth quarter of 1996 in connection with the Company's reorganization from a partnership, together with reduced levels of pre-tax income. LIQUIDITY AND CAPITAL RESOURCES The Company's sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under its financing facilities, and in 1996, proceeds from an initial public offering of equity. In the past, these sources have been sufficient to meet its needs and finance the growth of its business. The following summary table reflects comparative cash flows for the Company for the years ended December 31, 1998, 1997 and 1996:
For the year ended December 31, 1998 1997 1996 ------------ ------------ ------------ Net cash provided by operating activities before change in working capital......................................... $ 4,795 $ 12,650 $ 14,702 Net cash provided by (used in) operating activities from change in working capital.................................. 3,638 (7,894) 2,113 Net cash used in investing activities....................... (11,559) (30,329) (17,516) Net cash provided by financing activities................... $ 3,817 $ 22,536 $ 4,341
For the year ended December 31, 1998, net cash provided by operating activities before adjustments for working capital decreased $7.9 million from the year ended December 31, 1997, to $4.8 million, primarily as a result of a decrease in gas processing margins at MarkWest's Appalachian plants since 1997. As shown above, this was enhanced by a $3.6 million net decrease in the Company's working capital accounts, excluding cash, for the year ended December 31, 1998, compared to a $7.9 million net increase in working capital accounts, excluding cash, for the year ended December 31, 1997. The change in working capital in 1998 was principally driven by decreases in accounts receivable, inventories, prepaid expenses and other assets. The change in working capital in 1997 was principally driven by increases in accounts receivable, prepaid expenses and other assets and decreases in inventories, accounts payable and accrued liabilities. Cash used in investing activities decreased $18.8 million to $11.6 million for the year ended December 31, 1998 compared to 1997, primarily related to fewer capital expenditures and acquisitions (see further discussion under "Capital Investment Program") for the year ended December 31, 1998, compared for the year ended December 31, 1997. In addition, cash used in investing activities was reduced by $4.3 million from proceeds received on the sale of equipment in the third quarter of 1998, when the Company sold and leased back three compressors at its Kenova facility. For the year ended December 31, 1998, cash provided by financing activities was $3.8 million, a decrease of approximately $18.7 million compared to the year ended December 31, 1997. The decrease was primarily attributable to paying down more debt in 1998. Capital Investment Program During 1998, the Company invested $15.9 million in capital expenditures, including $11 million in Michigan to fund the further extension of the pipeline. The remaining capital programs during 1998 included $2.3 million for various projects in Appalachia and $2.6 million for exploration and production activities, (net of dispositions of $0.7 million), including $2.4 million in the first quarter acquisition of 40 producing wells located in the northern San Juan Basin of southwest 14 Colorado. During 1997, the Company invested $19.3 million in capital expenditures, including $9.1 million in Michigan primarily to construct an NGL extraction plant. In addition, in 1997, the Company spent $8.5 million in Michigan to buy out its previous partner and an additional $1.9 million to complete a 32-mile gas pipeline extension in Michigan originally built on behalf of a producer. The Company's capital investment program for 1999 is currently estimated at $5.3 million. Rocky Mountain exploration and production activities will total $3.1 million, including a $1.4 million acquisition in the San Juan Basin and several exploitation projects. The remaining capital programs for 1999 include various maintenance projects in Appalachia and Michigan, completion of various 1998 Michigan projects, and funding of several drilling projects in Michigan. Financing Facilities The Company's financing facilities are described in Note 3 to the Company's Consolidated Financial Statements in Item 8 of this Form 10-K. At December 31, 1998, the Company had approximately $39.2 million of available credit, of which net debt of $36.6 million had been utilized as of December 31, 1998, and working capital of $11.5 million. The Company believes that cash provided by operating activities, together with amounts available to be borrowed under its financing facilities, will provide sufficient funds to maintain its existing facilities and fund its current capital expenditure program. As 1999 progresses, the Company's credit availability is expected to increase as its Michigan volumes contribute more to the trailing cash flow calculation, the determinant of the Company's available credit, even if processing margins continue to be low. In early 1999, the Company concluded the sale of non-core Rocky Mountain producing property interests generating $0.8 million, and plans to sell its corporate office building and other non-core assets for proceeds in excess of $10 million to increase its financial flexibility to pursue new processing opportunities. Depending on the timing and amount of the Company's future projects, it may be required to seek additional sources of capital. While the Company believes that it would be able to secure additional financing on terms acceptable to the Company, if required, no assurance can be given that it will be able to do so. 1999 OUTLOOK NGL prices in the fourth quarter of 1998 were below historical levels and are expected to remain so during the first quarter of 1999. These prices are often correlated with and driven by the price of crude oil, which has not recovered from its decline over the fourth quarter of 1997 and the first quarter of 1998. The Company anticipates that until a crude oil price recovery is underway and/or gas prices soften, the Company will continue to experience earnings pressures, like others in the industry. MarkWest's NGL commodity exposure is partially offset by selling liquids in a premium market, utilizing storage capability and its ability to prebuy some of its natural gas requirements. In addition, an increase of fee-based income, primarily a result of connecting new wells that increase system throughput in Michigan, and a growing volume of owned gas production help to offset the fluctuation of NGL and natural gas prices. Currently MarkWest's Michigan operations have an annual sensitivity to throughput volumes equal to approximately $350,000 in pretax income for every million cubic feet per day. The Company anticipates fee-based activity will generate approximately 50% of total gross margins in 1999 (assuming normal processing margins in Appalachia). This will provide an earnings mix that is less volatile to swings in commodity prices. A substantial portion of the Company's revenues and as a result, its gross margins, remains dependent upon the sales price of NGLs, particularly propane, which fluctuates with the winter weather conditions, and other supply and demand determinants. The strongest demand for propane and the highest propane sales margins generally occur during the winter heating season. As a result, the Company recognizes a substantial portion of its annual income during the first and fourth quarters of the year. RISK MANAGEMENT ACTIVITIES The Company's primary risk management objectives are to meet or exceed budgeted gross margins by locking in budgeted or above-budgeted prices in the financial derivatives and physical markets and to protect margins from precipitous declines. The Company maintains a committee, including members of senior management, which oversees all hedging activity. MarkWest achieves its goals utilizing a combination of fixed price forward contracts, New York Mercantile Exchange-traded futures, and fixed/floating price swaps on the over-the-counter ("OTC") market. First, the Company protects margins through purchases of natural gas forward contracts with predetermined BTU differentials based upon a basket of Gulf Coast NGL prices (or a substitute for propane, such as crude oil). Second, MarkWest protects margins by purchasing natural gas futures while simultaneously selling propane futures of approximately the same Btu value. Third, the Company manages its commodity price risk on terminal propane purchases and sales by purchasing and selling, respectively, propane futures contracts. Fourth, by purchasing propane futures contracts, the Company locks in desired prices on forward sales to certain customers. Fifth, the Company's wholly owned subsidiary, MarkWest Resources, Inc., enters into OTC swaps with certain other creditworthy companies to hedge exposure to changes in spot market prices on certain levels of production. Gains and losses related to qualifying hedges, as defined by Statement of Financial Accounting Standards No. 80, Accounting for Futures Contracts, of firm commitments or anticipated transactions are recognized in revenue and cost of sales upon execution of the hedged physical transaction. 15 The Company had no material notional quantities of natural gas, NGL, or crude oil futures or options at December 31, 1998 and 1997. During the years ended December 31, 1998 and 1997, a $32,000 gain and $989,000 gain, respectively, were recognized in operating income on the settlement of propane and natural gas futures. Financial instrument gains and losses on hedging activities were generally offset by amounts realized from the sale of the underlying products in the physical market. In addition to these risk management tools, MarkWest utilizes its liquids storage facilities and contracts for third party storage to build product inventories during historically lower-priced periods for resale during higher- priced periods. Also, MarkWest has contractual arrangements to purchase certain quantities of its natural gas feedstock in advance of physical needs. IMPACT OF THE YEAR 2000 ISSUE The Year 2000 Issue is the result of computer programs being written using two digits rather than four to define the applicable year. Unless the Company's computer programs are Year 2000 compliant, any of the Company's computer programs that have date-sensitive software may recognize a date using "00" as the year 1900 rather than the year 2000. This could result in a system failure or miscalculations causing disruptions of operations, including, among other things, a temporary inability to process transactions, send invoices, or engage in similar normal business activities. The Company's most significant risk related to the Year 2000 Issue is the worst-case scenario that its plants and pipelines, if not Year 2000 compliant, may not be operable, causing a loss of both gathering and processing volumes and associated revenues. In the first quarter of 1998, the Company began its preliminary assessment of the Year 2000 Issue. Many of the Company's computer systems, which include both financial systems and plant control systems, are purchased from third-party vendors who have represented to the Company that they are Year 2000 compliant. In some cases, the Company has upgraded or needs to upgrade to the most recent release. A complete analysis, including an evaluation of the extent to which the Company is vulnerable to the failure of significant customers and suppliers to properly remediate their own Year 2000 Issue, was completed in early 1999. Remediation has begun and is expected to be completed during the second quarter of 1999. A contingency plan to deal with unexpected Year 2000 issues will be completed in the second or third quarter of 1999. Based upon current information, the Company estimates that the total cost of its Year 2000 initiative will be approximately $110,000. The Year 2000 costs include all activities undertaken on Year 2000 related matters across the Company, including, but not limited to, remediation, testing, third-party review, risk mitigation and contingency planning. All Year 2000 costs have been and will continue to be funded through operating cash flow and are expensed in the period in which they are incurred. The Company believes that total Year 2000 project costs will not be material to the Company's results of operations, liquidity or capital resources, and that as a result of the Company's efforts, Year 2000 should have little impact on the Company's computer systems. ITEM 7A.-- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company faces market risk from commodity price variations, primarily in the NGLs it sells and in the natural gas it purchases. It also incurs, to a lesser extent, credit risks and risks related to interest rate variations. Commodity Price Risk. In the past, NGL prices and natural gas costs have fluctuated widely in response to changing market forces. The impacts of these price fluctuations on earnings from natural gas processing and marketing activities have been significant and have varied from year to year. Currently MarkWest's Appalachian operations have an annual sensitivity to NGL prices equal to $1.0 million in pretax income for every $0.01/gallon change in NGL prices and an annual sensitivity to natural gas prices equal to $1.0 million in pretax income for every $0.10/MMBtu change in natural gas prices. As discussed in Risk Management Activities, the Company occasionally uses futures contracts and fixed/floating price swaps to hedge a portion of its commodity price risk. See related discussion in Note 7 to the Company's Consolidated Financial Statements. Gains and losses experienced on hedging transactions are generally offset by the related gains or losses on the sale of the underlying product in the physical market. The Company had no material quantities of natural gas, NGL, or crude oil futures, swaps or options at December 31, 1998 and 1997. Credit Risk. The Company is exposed to potential losses as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company maintains credit policies with regard to its counterparties that management believes minimize overall credit risk. Such policies include the evaluation of a prospective counterparty's financial condition, collateral requirements where deemed necessary, and the use of standardized agreements which facilitate the netting of cash flows associated with a single counterparty. The Company also monitors the financial condition of existing counterparties on an ongoing basis. Considering the system of internal controls in place, the Company believes it is unlikely that a material adverse effect on its financial position, results of operations or cash flows would occur as a result of counterparty nonperformance. Interest Rate Risk. The Company is exposed to changes in interest rates, primarily as a result of its long-term debt with floating interest rates. The Company may make use of interest rate swap agreements to adjust the ratio of fixed and floating rates in the debt portfolio, although no such agreements are currently in place. The impact of a 100 basis point increase in interest rates on the Company's debt would result in an increase in interest expense and a decrease in income before taxes of approximately $386,600. This amount has been determined by considering the impact of the hypothetical interest rates on the Company's variable-rate debt balances as of December 31, 1998. 16 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page ---- Report of Independent Accountants................................................................ 17 Consolidated Balance Sheet at December 31, 1998 and 1997......................................... 18 Consolidated Statement of Operations for each of the three years ended December 31, 1998...................................................................... 19 Consolidated Statement of Cash Flows for each of the three years ended December 31, 1998...................................................................... 20 Consolidated Statement of Changes in Stockholders' Equity/Partners' Capital for each of the three years ended December 31, 1998............................ 21 Notes to Consolidated Financial Statements....................................................... 22
REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of MarkWest Hydrocarbon, Inc. In our opinion, the accompanying consolidated balance sheet and related consolidated statements of operations, of cash flows and of changes in stockholders' equity/partners' capital present fairly, in all material respects, the financial position of MarkWest Hydrocarbon, Inc., a Delaware corporation, and its subsidiaries at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. PricewaterhouseCoopers LLP Denver, Colorado February 10, 1999 17 MARKWEST HYDROCARBON, INC. CONSOLIDATED BALANCE SHEET (000S, EXCEPT SHARE DATA)
December 31, ASSETS 1998 1997 ------------ ------------ Current assets: Cash and cash equivalents....................................................................... $ 2,055 $ 1,364 Receivables, net of allowance for doubtful accounts of $120 and $120, respectively.............. 7,738 10,279 Inventories..................................................................................... 4,583 5,141 Prepaid feedstock............................................................................... 1,957 2,690 Receivable from income taxes paid............................................................... 2,763 -- Other assets.................................................................................... 289 2,698 ----------- ----------- Total current assets........................................................................... 19,385 22,172 Property and equipment: Gas processing, gathering, storage and marketing equipment..................................... 78,018 59,857 Oil and gas properties and equipment............................................................ 9,207 6,791 Land, buildings and other equipment............................................................. 11,240 9,363 Construction in progress........................................................................ 4,466 5,258 ----------- ----------- 102,931 81,269 Less: accumulated depreciation, depletion and amortization..................................... (19,609) (15,439) ----------- ----------- Total property and equipment, net.............................................................. 83,322 65,830 Intangible assets, net of accumulated amortization of $169 and $27, respectively................. 924 555 Note receivable and other assets................................................................. -- 10,100 ----------- ----------- Total assets..................................................................................... $103,631 $ 98,657 =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Trade accounts payable.......................................................................... $ 2,765 $ 3,074 Accrued liabilities............................................................................. 5,094 4,339 Current portion of long-term debt............................................................... 63 156 ----------- ---------- Total current liabilities...................................................................... 7,922 7,569 Deferred income taxes............................................................................ 7,077 5,609 Long-term debt................................................................................... 38,597 33,931 Commitments and contingencies (Note 5)........................................................... -- -- Stockholders' equity: Preferred stock, par value $0.01; 5,000,000 shares authorized, 0 shares outstanding............. -- -- Common stock, par value $0.01; 20,000,000 shares authorized, 8,531,206 and 8,519,724 shares issued, respectively........................................................................... 85 85 Additional paid-in capital...................................................................... 42,693 42,729 Retained earnings............................................................................... 7,978 9,189 Treasury stock; 60,300 and 27,511 shares, respectively.......................................... (721) (455) ----------- ---------- Total stockholders' equity.................................................................... 50,035 51,548 ----------- ---------- Total liabilities and stockholders' equity....................................................... $103,631 $ 98,657 =========== ==========
The accompanying notes are an integral part of these financial statements. 18 MARKWEST HYDROCARBON, INC. CONSOLIDATED STATEMENT OF OPERATIONS (000S, EXCEPT PER SHARE DATA)
For the Year Ended December 31, 1998 1997 1996 ------------ ------------ ------------ Revenue: Gathering, processing and marketing revenue................ $62,438 $77,938 $70,405 Oil and gas revenue, net of transportation and taxes....... 1,184 888 357 Interest income............................................ 200 661 192 Other income (expense)..................................... (124) 196 998 ------------ ------------ ------------ Total revenue.......................................... 63,698 79,683 71,952 ------------ ------------ ------------ Costs and expenses: Costs of sales............................................. 42,883 45,657 40,907 Operating expenses......................................... 10,785 11,286 7,597 General and administrative expenses........................ 5,319 6,651 4,753 Depreciation, depletion and amortization................... 4,594 3,246 2,910 Interest expense........................................... 2,095 826 1,090 ------------ ------------ ------------ Total costs and expenses............................... 65,676 67,666 57,257 ------------ ------------ ------------ Income (loss) before minority interest and income taxes........ (1,978) 12,017 14,695 Minority interest in net loss of subsidiary.................... -- 380 65 ------------ ------------ ------------ Income (loss) before income taxes.............................. (1,978) 12,397 14,760 Provision (benefit) for income taxes: Current.................................................... (2,235) 2,918 3,014 Deferred................................................... 1,468 1,632 232 Arising from reorganization................................ -- -- 3,745 ------------ ------------ ------------ Net income (loss).............................................. $(1,211) $ 7,847 $ 7,769 ============ ============ ============ Basic earnings (loss) per share................................ $ (0.14) $ 0.92 $ 1.21 ============ ============ ============ Earnings (loss) per share assuming dilution.................... $ (0.14) $ 0.91 $ 1.20 ============ ============ ============ Weighted average number of outstanding shares of common stock.. 8,490 8,485 6,415 ============ ============ ============
The accompanying notes are an integral part of these financial statements. 19 MARKWEST HYDROCARBON, INC. CONSOLIDATED STATEMENT OF CASH FLOWS (000S)
For the Year Ended December 31, 1998 1997 1996 --------------------------------- Cash flows from operating activities: Net income (loss)........................................................... $ (1,211) $ 7,847 $ 7,769 Add income items that do not affect working capital: Depreciation, depletion and amortization................................ 4,594 3,246 2,910 Deferred income taxes................................................... 1,468 1,632 3,977 (Gain) loss on disposition of assets.................................... (56) (75) 46 --------------------------------- 4,795 12,650 14,702 Adjustments to working capital: (Increase) decrease in receivables...................................... 2,541 (1,614) (846) (Increase) decrease in inventories...................................... 558 491 (2,802) (Increase) decrease in prepaid expenses and other assets................ 379 (3,099) (185) Increase (decrease) in accounts payable and accrued liabilities......... 160 (3,672) 5,946 --------------------------------- 3,638 (7,894) 2,113 Net cash flow provided by operating activities...................... 8,433 4,756 16,815 Cash flows from investing activities: Capital expenditures.................................................... (15,890) (19,323) (9,824) Proceeds from sale/leaseback transaction................................ 4,281 -- -- Acquisition of interest in Michigan project............................. -- (8,563) -- Change in note receivable and other..................................... 50 (2,443) (7,692) --------------------------------- Net cash used in investing activities............................... (11,559) (30,329) (17,516) Cash flows from financing activities: Proceeds from issuance of long-term debt................................ 39,200 39,920 47,124 Repayments of long-term debt............................................ (34,627) (17,246) (53,632) Debt issuance costs..................................................... (454) (175) -- Partners' distributions................................................. -- -- (14,150) Net purchases of treasury stock......................................... (394) (455) -- Proceeds from issuance of common stock.................................. -- -- 24,608 Proceeds from exercise of options and payment on share purchase notes... 92 492 391 --------------------------------- Net cash provided by financing activities........................... 3,817 22,536 4,341 Net increase (decrease) in cash and cash equivalents................ 691 (3,037) 3,640 Cash and cash equivalents at beginning of year.................................. 1,364 4,401 761 --------------------------------- Cash and cash equivalents at end of year........................................ $ 2,055 $ 1,364 $ 4,401 =================================
The accompanying notes are an integral part of these financial statements. 20 MARKWEST HYDROCARBON, INC. CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY/ PARTNERS' CAPITAL (000S)
SHARES OF SHARES OF ADDITIONAL TOTAL PARTNERS' COMMON TREASURY COMMON PAID-IN RETAINED TREASURY STOCKHOLDERS' CAPITAL STOCK STOCK STOCK CAPITAL EARNINGS STOCK EQUITY -------- --------- ----------- ------- ---------- -------- ---------- ------------- Balance, December 31, 1995...................... 25,161 -- -- -- -- -- -- 25,161 Net income prior to reorganization..... 6,427 -- -- -- -- -- -- 6,427 Notes receivable from partners, net, prior to reorganization............... 205 -- -- -- -- -- -- 205 Distributions prior to reorganization.. (14,150) -- -- -- -- -- -- (14,150) Exercise of options, prior to reorganization........................ 71 -- -- -- -- -- -- 71 Reorganization from a limited partnership to a corporation.......... (17,714) 5,725 -- 57 17,657 -- -- -- Deferred taxes relating to the reorganization........................ -- -- -- -- -- (3,745) -- (3,745) Common stock issued.................... -- 2,760 -- 28 24,580 -- -- 24,608 Net income after reorganization........ -- -- -- -- -- 5,087 -- 5,087 -------- --------- ----------- ------- ---------- -------- ---------- ---------- Balance, December 31, 1996...................... $ -- 8,485 -- 85 42,237 1,342 -- 43,664 ======== -- Net income............................. -- -- -- -- 7,847 -- 7,847 Payments received on notes receivable -- from partners......................... -- -- -- 192 -- -- 192 Exercise of options.................... 35 -- -- 300 -- -- 300 Acquisition of treasury stock.......... -- (28) -- -- -- (455) (455) --------- ----------- ------- ---------- -------- ---------- ---------- Balance, -- December 31, 1997...................... 8,520 (28) $ 85 $ 42,729 $ 9,189 $ (455) $ 51,548 Net loss............................... -- -- -- -- (1,211) -- (1,211) Exercise of options.................... 11 -- -- 89 -- -- 89 Acquisition of treasury stock.......... -- (63) -- -- -- (690) (690) Reissuance of treasury stock........... -- 31 -- (79) -- 375 296 Other.................................. -- -- -- (46) -- 49 3 --------- ----------- ------ ---------- -------- ---------- ---------- Balance, December 31, 1998...................... 8,531 (60) $ 85 $ 42,693 $ 7,978 $ (721) $ 50,035 ========= =========== ====== ========== ======== ========== ==========
The accompanying notes are an integral part of these financial statements. 21 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. NATURE OF OPERATIONS AND SIGNIFICANT BUSINESS ACQUISITIONS NATURE OF OPERATIONS MarkWest Hydrocarbon, Inc. ("MarkWest" or the "Company"), provides natural gas processing and related services. The Company's activities include compression, gathering, treatment and natural gas liquids ("NGLs") extraction services for natural gas producers and pipeline companies and fractionation of NGLs into marketable products. The Company also purchases, stores and markets natural gas and NGLs and conducts strategic exploration for new natural gas sources for its processing services. The Company's operations are concentrated in three core areas: the southern Appalachian region of eastern Kentucky, southern West Virginia, and southern Ohio; western Michigan; and the Rocky Mountains. 1996 REORGANIZATION The Company was incorporated in June 1996 to act as the successor to MarkWest Hydrocarbon Partners, Ltd. (the "Partnership"). Effective October 7, 1996, the Partnership reorganized and the existing general and limited partners exchanged 100% of their interests in the Partnership for 5,725,000 common shares of the Company. An additional 2,760,000 shares of common stock were offered for public sale, totaling 8,485,000 shares outstanding as of October 31, 1996. This transaction was a reorganization of entities under common control, and accordingly, it was accounted for at historical cost. SIGNIFICANT BUSINESS ACQUISITIONS The Company provides natural gas gathering, treatment, processing and NGL marketing in Manistee, Mason and Oceana Counties in Michigan. Effective May 6, 1996, the Company began to earn an interest in the Michigan core area by funding various capital programs. By June 1997, the Company completed its earn-in of a 60 percent interest after funding $16.8 million in capital programs. In November 1997, MarkWest acquired the remaining 40 percent interest from its partner, Michigan Energy Company, L.L.C., for a purchase price of $8.5 million plus up to $13.5 million in future contingent payments (see Note 5). NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. CASH AND CASH EQUIVALENTS The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Excess cash is used to pay down the credit facility. Accordingly, investments are limited to overnight investments of end-of-day cash balances. INVENTORIES Inventories comprise the following (in 000s): At December 31, 1998 1997 ----------- ------------ Product inventory............................ $ 4,064 $ 4,728 Materials and supplies inventory............. 519 413 ----------- ------------ $ 4,583 $ 5,141 =========== ============ Product inventory consists primarily of finished goods (propane, butane, isobutane, natural gasoline, and in 1997, natural gas) and is valued at the lower of cost, using the first-in, first-out method, or market. Inventory write-downs at December 31, 1998 and 1997, were $525,000 and $585,000, respectively. In addition, the Company recorded a write-down of $0 and $251,000 related to firm commitments held at December 31, 1998 and 1997, respectively, for the purchase of natural gas inventory. Capitalized overhead costs of $280,000 and $166,000 were included in product inventory at December 31, 1998 and 1997, respectively. Materials and supplies are valued at the lower of average cost or estimated net realizable value. PREPAID FEEDSTOCK Prepaid feedstock consists of natural gas purchased in advance of its actual use. It is valued using the first-in/first-out method. Prepaid feedstock write- downs at December 31, 1998 and 1997, were $0 and $160,000, respectively. 22 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is 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 significant long-term assets are capitalized and amortized over the related asset's estimated useful life. Depreciation is provided principally on the straight-line method over the following estimated useful lives: plant facilities and pipelines, 20 years; buildings, 40 years; furniture, leasehold improvements and other, 3 to 10 years. Depreciation for oil and gas properties is provided for using the units-of- production method. Oil and gas properties consist of leasehold costs, producing and non-producing properties, oil and gas wells, equipment and pipelines. The Company uses the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves are capitalized to the full cost pool. These capitalized costs, including estimated future costs to develop the reserves and estimated abandonment costs, net of salvage value, are amortized on a units-of-production basis using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment of such properties indicate that the properties are impaired, the amount of impairment is added to the capitalized cost base to be amortized. As of December 31, 1998 and 1997, approximately $489,000 and $967,000 of investments in unproved properties were excluded from amortization. The capitalized costs included in the full cost pool are subject to a "ceiling test," which limits such costs to the aggregate of the estimated present value, using a 10 percent discount rate, of the future net revenues from proved reserves, based on current economics and operating conditions. No impairment existed during the three years ended December 31, 1998. Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in the consolidated statement of operations. IMPAIRMENT OF LONG-LIVED ASSETS During 1996, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, which requires that an impairment loss be recognized when the carrying amount of an asset exceeds the expected future undiscounted net cash flows. There was no effect on the Company's financial statements for the three years ended December 31, 1998 as a result of adopting SFAS No. 121. INTANGIBLE ASSETS Intangible assets consist primarily of deferred financing costs that are amortized using the straight-line method over the term of the associated agreement. NOTE RECEIVABLE AND OTHER ASSETS Note receivable at December 31, 1997, consisted of a note receivable and related interest receivable due from Michigan Production Company, LLC ("MPC"). The note was for the costs incurred by the Company for the construction of a 32-mile pipeline extension in Michigan. During 1998, the note and related interest was forgiven in exchange for the title to the pipeline extension. HEDGING ACTIVITIES The Company limits its exposure to natural gas and propane price fluctuations related to future purchases and production with futures contracts. These contracts are accounted for as hedges in accordance with the provisions of SFAS No. 80, Accounting for Futures Contracts. Gains and losses on such hedge contracts are deferred and included as a component of revenues and cost of sales when the hedged production is sold, or gas supplies are purchased. FAIR VALUE OF FINANCIAL INSTRUMENTS The Company's financial instruments consist of cash and cash equivalents, receivables, accounts payable and other current liabilities, and long-term debt. Except for long-term debt, the carrying amounts of financial instruments approximate fair value due to their short maturities. At December 31, 1998 and 1997, based on rates available for similar types of debt, the fair value of long-term debt was not materially different from its carrying amount. 23 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS REVENUE RECOGNITION Revenue for sales or services is recognized at the time the product is shipped or at the time the service is performed. INCOME TAXES Deferred income taxes reflect the impact of "temporary differences" between amounts of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws. These temporary differences are determined in accordance with the liability method of accounting for income taxes as prescribed by SFAS No. 109, Accounting for Income Taxes. CONCENTRATION OF CREDIT RISK Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of trade accounts receivable. The trade accounts receivable risk is limited due to the large number of entities comprising the Company's customer base and their dispersion across industries and geographic locations. At December 31, 1998 and 1997, the Company had no significant concentrations of credit risk. STOCK COMPENSATION As permitted under SFAS No. 123, Accounting for Stock-Based Compensation, the Company has elected to continue to measure compensation costs for stock-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. See Note 9 for the applicable disclosures required by SFAS No. 123. EARNINGS PER SHARE (EPS) During 1997, the Company adopted SFAS No. 128, Earnings Per Share. SFAS No. 128 replaced the presentation of primary EPS with a presentation of basic EPS. Basic earnings per share are determined by dividing net income by the weighted- average number of common shares outstanding during the year. Earnings per share assuming dilution are determined by dividing net income by the weighted-average number of common shares and common stock equivalents outstanding. SEGMENT REPORTING In 1998, the Company adopted SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information. SFAS No. 131 supersedes SFAS No. 14, Financial Reporting for Segments of a Business Enterprise, replacing the "industry segment" approach with the "management" approach. The management approach designates the internal organization that is used by management for making operating decisions and assessing performance as the source of the Company's reportable segments. SFAS No. 131 also requires disclosures about products and services, geographic areas, and major customers. The adoption of SFAS No. 131 did not affect results of operations or financial position but did affect the disclosure of segment information (see Note 11, "Segment Reporting"). SUPPLEMENTAL CASH FLOW INFORMATION Interest of $2.4 million, $1.0 million and $1.0 million was paid during the years ended December 31, 1998, 1997 and 1996, respectively. Interest expense in 1998 is net of $298,000 capitalized to various construction projects. Income taxes of $596,000 and $7.0 million were paid during the years ended December 31, 1998 and 1997, respectively. There were no income taxes paid during the year ended December 31, 1996, because of the Company's partnership status. Non-cash investing activities included in 1998 the forgiveness of the note and related interest receivable valued at $10.1 million in exchange for the title to a 32-mile pipeline in Michigan and in 1996, the contribution of Basin Pipeline, LLC, by Michigan Energy Company, L.L.C. to the Company, valued at approximately $9.2 million. In 1996, non-cash financing activities included the purchase of certain assets from the Dow Chemical Company by the assumption of a note valued at approximately $421,000. RECENT ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board issued Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. This statement is effective for fiscal years beginning after June 15, 1999. Earlier application is encouraged; however, the Company does not anticipate adopting SFAS No. 133 until the fiscal year beginning January 1, 2000. SFAS No. 133 requires an entity to recognize all derivatives as assets or liabilities in the balance sheet and measure those instruments at fair value. Although the Company is currently evaluating SFAS No. 133, it is not expected to have a material impact on the financial condition or results of operations of the Company. 24 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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. RECLASSIFICATIONS Certain prior year amounts have been reclassified to conform to the 1998 presentation. NOTE 3. DEBT CREDIT FACILITY Effective June 20, 1997, the Company replaced its existing financing agreements with a new $85 million credit facility with three commercial banks, which expires in 2004. Actual borrowing limits may be a lesser amount, depending on trailing cash flow, as defined in the agreement. The credit facility permits the Company to borrow money using either a base rate loan or a London Interbank Offered Rate ("LIBOR") loan option, plus an applicable margin of between 0% and 2.5%, based on a certain Company debt to earnings ratio. At December 31, 1998, the Company had $35 million outstanding under the credit facility bearing interest at an average rate of 7.8%. At December 31, 1997, the Company had $33.9 million outstanding under the credit facility bearing interest at an average rate of 6.6%. The Company pays a fee at a rate between 0.25% and 0.75% per annum on the unused commitment, based on a certain Company debt to earnings ratio. The credit facility is secured by a first mortgage on the Company's major assets. The loan agreement restricts certain activities and requires the maintenance of certain financial ratios and other conditions. As a direct result of entering into the new credit facility, the Company wrote off to interest expense previously deferred financing costs associated with a previous credit facility of approximately $235,000 in the second quarter of 1997. 155 INVERNESS BUILDING FINANCING Effective January 14, 1998, the Company's wholly-owned subsidiary, 155 Inverness, Inc., obtained separate $3.7 million financing from an insurance company for the purchase of an office building. The 7.25% note matures on February 10, 2003, and is secured by the property's deed of trust and by a ten year master lease with the Company. As of December 31, 1998, approximately $3.65 million was outstanding under the note. SCHEDULED DEBT MATURITIES Scheduled debt maturities as of December 31, 1998, are as follows (in 000s): 1999 .................. $ 63 2000 .................. 3,812 2001 .................. 7,567 2002 .................. 9,447 2003 and thereafter.... 17,771 --------- Total.................. $ 38,660 ========= NOTE 4. RELATED PARTY TRANSACTIONS The Company, through its wholly owned subsidiary, MarkWest Resources, Inc. ("Resources"), holds a varied undivided interest in several exploration and production assets owned jointly with MAK-J Energy Partners Ltd. ("MAK-J"), which owns a 51% undivided interest in such properties. The general partner of MAK-J is a corporation owned and controlled by the President and Chief Executive Officer of the Company. The properties are held pursuant to joint venture agreements entered into between Resources and MAK-J. Resources is the operator under such agreements. As the operator, Resources is obligated to provide certain engineering, administrative and accounting services to the joint ventures. The joint venture agreements provide for a monthly fee payable to Resources for all such expenses. As of December 31, 1998 and 1997, the Company has receivables due from MAK-J for approximately $0 and $790,000, and payables to MAK-J for approximately $488,000 and $202,000, respectively. The Company made contributions of $164,000, $271,000 and $299,000 to a profit- sharing plan for the years ended December 31, 1998, 1997 and 1996, respectively. The plan is discretionary, with annual contributions determined by the Company's Board of Directors. The Company (formerly a Partnership) periodically extended offers to employees to purchase interests in the Company. The employees provided the Company with promissory notes as part of the exercise price. According to the terms of the notes, interest accrues at 7% and payments are required 25 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS for the greater of accrued interest or excess distributions and are payable in full on October 8, 1999. Notes in the amounts of $164,000 and $167,000 have been recorded as a reduction of additional paid-in capital at December 31, 1998 and 1997, respectively. Purchase of Company stock with financing provided by the Company was discontinued concurrent with the Company's public offering in October 1996. NOTE 5. COMMITMENTS AND CONTINGENCIES COLUMBIA GAS TRANSMISSION CORPORATION ARBITRATION MarkWest filed arbitration proceedings in February 1998 to resolve issues with Columbia Gas Transmission Corporation ("Columbia") regarding three Appalachia natural gas processing plants. These plants are governed by several contracts, the most important of which extends through the year 2010. In this arbitration, MarkWest requests a declaration of rights and status to clarify agreements between the companies and certain monetary relief. Issues arose during ongoing negotiations between MarkWest and Columbia to finalize terms of a 1997 preliminary agreement in which, among other things, Columbia agreed to sell its Cobb plant to MarkWest and to transfer from Columbia to MarkWest the operation of the Boldman plant. These issues also include matters regarding operations at the Kenova plant. MarkWest owns the Boldman and Kenova plants. In April 1998, Columbia filed a Complaint against MarkWest in the United States District Court for the Southern District of West Virginia. The Complaint seeks declaratory relief that certain agreements, or certain specified provisions thereof, are void and that MarkWest is in breach of the Federal Energy Regulatory Commission-approved settlement agreement under which MarkWest was to acquire the Cobb plant and operate the Boldman plant. The certain agreements concern, among other matters, Columbia's obligation to guarantee the delivery of natural gas or NGLs to MarkWest. In the Complaint, Columbia also seeks injunctive relief to enjoin MarkWest from interfering with arrangements Columbia may seek to undertake with natural gas producers and suppliers and with negotiations Columbia may pursue with third parties to terminate its interests in the products extraction business. In the third quarter of 1998, the District Court judge stayed proceedings pending the binding arbitration noted above. The arbitration is scheduled to begin in the second quarter of 1999. Management believes it will prevail in its position and, accordingly, the outcome of this dispute is not likely to have a material effect on the financial condition, results of operations or prospects of MarkWest. MICHIGAN ACQUISITION In connection with the Company's acquisition of the remaining 40 percent interest in its Michigan core area from its partner (see Note 1), the Company is committed to make additional future contingent payments of up to $13.5 million. The future contingent payments consist of nine payments ranging from $1.0 million to $2.7 million. The payments are contingent upon several factors, including substantial sustained increases in system throughput volumes to levels ranging from 45 million cubic feet per day ("MMcf/d") to 75 MMcf/d, and a minimum internal rate of return on the capital programs undertaken to expand throughput capacity. NOTE 6. SIGNIFICANT CUSTOMERS For the year ended December 31, 1998, 1997 and 1996, sales to one customer accounted for approximately 9%, 19% and 16% of total revenues. Management believes the loss of this customer would not adversely impact operations, because alternative markets are available. NOTE 7. FINANCIAL DERIVATIVES The Company uses futures contracts and fixed/floating price swaps to hedge a portion of its commodity price risk. FUTURES The Company enters into futures transactions on the New York Mercantile Exchange ("NYMEX") and is subject to margin requirement deposits. MarkWest may protect its processing gross margins by purchasing natural gas futures while simultaneously selling propane futures of approximately the same British thermal unit ("Btu") value. The Company may also use futures to fix or float its cost of natural gas purchases. The Company may also manage its commodity price risk on terminal propane purchases and/or sales by purchasing and/or selling, respectively, propane futures contracts. The Company may also use NYMEX futures to offset physical positions in its gas marketing activities. The Company had no material notional quantities of natural gas, NGL, or crude oil futures or options at December 31, 1998 and 1997. During the years ended December 31, 1998 and 1997, a $32,000 gain and $989,000 gain, respectively, were recognized in operating income on the settlement of propane and natural gas futures. Financial instrument gains and losses on hedging activities were generally offset by amounts realized from the sale of the underlying products in the physical market. The Company enters into speculative futures transactions on an infrequent basis. Specific approval by the Board of Directors is necessary prior to executing such transactions. Speculative futures are marked to market at the end of each accounting period, and any gain or loss is recognized in income for that period. Results from such speculative activities for the year ended December 31, 1998, were not material. No such transactions were executed for the year ended December 31, 1997. 26 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SWAPS The Company's wholly owned subsidiary, MarkWest Resources, Inc. ("Resources"), enters into OTC swaps with certain other creditworthy companies. Resources uses swap agreements to hedge exposure to changes in spot market prices on the amount of natural gas production covered in the agreement. At December 31, 1998, Resources had four open swap agreements that guaranteed Resources an average sales price of $2.00/Mcf for up to 1,720 Mcf/d of production ending at various times throughout 1999. At December 31, 1997, Resources had three open swap agreements that guaranteed Resources an average sales price of $2.22/Mcf for up to 956 Mcf/d of production ending at various times throughout 1998 and 1999. NOTE 8. INCOME TAXES In connection with the reorganization from a partnership to a corporation, the Company recorded deferred income taxes as of October 7, 1996, and a one-time charge to earnings of $3.7 million. The total income tax provision (benefit) has been allocated as follows (in 000s):
Year ended December 31, 1998 1997 1996 --------------------- ---------------------- --------------------- Arising from Reorganization....................... -- $ -- $ 3,745 Subsequent to Reorganization...................... (767) 4,550 3,246 --------------------- --------------------- --------------------- $ (767) $ 4,550 $ 6,991 ===================== ===================== =====================
The provision (benefit) for income taxes subsequent to reorganization is comprised of (in 000s):
October 7 Year Ended Year Ended through December 31, December 31, December 31, 1998 1997 1996 --------------------- --------------------- --------------------- Current: Federal............................... $ (1,921) $ 2,510 $ 2,616 State................................. (314) 408 398 --------------------- --------------------- --------------------- Total current......................... $ (2,235) 2,918 3,014 ===================== ===================== ===================== Deferred: Federal................................. 1,413 1,419 212 State................................... 55 213 20 Total deferred.......................... 1,468 1,632 232 --------------------- --------------------- --------------------- Total tax provision..................... $ (767) $ 4,550 $ 3,246 ===================== ===================== =====================
The deferred tax liabilities (assets) are comprised of the tax effect of the following (in 000s):
1998 1997 ------------------- ------------------- Property and equipment............................................... $ 6,934 $ 5,301 Other assets......................................................... 300 314 Total deferred income tax liabilities.......................... 7,234 5,615 ------------------- ------------------- State Net Operating Loss ("NOL") carryforwards....................... (151) -- Intangible assets.................................................... (6) (6) Total deferred income tax assets................................ (157) (6) ------------------- ------------------- Net deferred tax liability..................................... $ 7,077 $ 5,609 =================== ===================
The differences between the provision for income taxes at the statutory rate and the actual provision for income taxes for the years ended December 31, 1998, 1997 and 1996, are as follows (in 000s): 27 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1998 % 1997 % 1996 % ---------- --------- --------- --------- --------- --------- Income tax at statutory rate............. $ (672) (34.0%) $ 4,339 35.0% $ 2,916 35.0% State income taxes, net of federal benefit.......................... (102) (5.1%) 403 3.3% 140 1.7% Tax credits.............................. -- -- (204) (1.6%) (35) (0.4%) Other.................................... 7 0.3% 12 0.1% 225 2.7% ---------- --------- --------- --------- --------- --------- Total............................... $ (767) (38.8%) $ 4,550 36.8% $ 3,246 39.0% ========== ========= ========= ========= ========= =========
At December 31, 1998, the Company had state NOL carryforwards for federal and state income tax purposes of approximately $2.2 million. These carryforwards expire as follows (in 000s): 2004...................................... $ 565 2014...................................... 1,645 ---------- Total $2,210 ========== The Company believes that the carryforwards will be utilized prior to their expiration. They are expected to be realized by achieving future profitable operations based on the Company's dedicated and owned reserves, dedicated reserves behind its processing plants, past earnings history, and projections of future earnings. NOTE 9. STOCK COMPENSATION PLANS At December 31, 1998, the Company has two stock-based compensation plans, which are described below. The Company applies APB Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations in accounting for its plans. Accordingly, no compensation cost has been recognized for its fixed stock option plans. Had compensation cost for the Company's two stock-based compensation plans been determined based on the fair value at the grant dates under those plans consistent with the method prescribed by SFAS No. 123, Accounting for Stock-Based Compensation, the Company's pro forma net income and earnings per share would have been reduced to the pro forma amounts listed below (in 000s, except per share data):
1998 1997 1996 -------------- ------------- -------------- Net income (loss) As reported......... $(1,211) $7,847 $7,769 Pro forma........... (1,483) 7,732 7,714 Basic earnings (loss) per As reported......... $ (0.14) $ 0.92 $ 1.21 share Pro forma........... $ (0.17) 0.91 1.20 Earnings (loss) per share As reported......... $ (0.14) $ 0.91 $ 1.20 assuming dilution Pro forma........... $ (0.17) 0.89 1.19
The Company historically granted employees the right to purchase partnership interests in the Partnership. As part of the Reorganization, such employee options to purchase partnership interests were replaced by options to purchase shares pursuant to the Company's 1996 Stock Incentive Plan. Under the 1996 Stock Incentive Plan, the Company may grant options to its employees for up to 850,000 shares of common stock in the aggregate. Under this plan, the exercise price of each option equals the market price of the Company's stock on the date of the grant, and an option's maximum term is ten years. Options are granted periodically throughout the year and vest at the rate of 20% on the first anniversary of the option grant date and at the rate of 20% on each subsequent anniversary thereof until fully vested. Under the 1996 Non-employee Director Stock Option Plan, the Company may grant options to its non-employee directors for up to 20,000 shares of common stock in the aggregate. Under this plan, the exercise price of each option equals the market price of the Company's stock on the date of the grant, and an option's maximum term is three years. Options are granted upon either the date the director first becomes a director, or on the date of each Annual Meeting of Stockholders, provided that the director has served since the date of the last Annual Meeting of Stockholders. Options granted upon the date the director first becomes a director vest at the rate of 33.33% on the first anniversary of the option grant date and at the rate of 33.33% on each subsequent anniversary thereof until fully vested. Options granted on the date of each Annual Meeting vest 100% on the first anniversary of the option grant date. Effective October 1, 1998, the Company repriced all stock options granted in 1997 and mid-1998. The stock options were repriced at $10.75 per share, the fair market value on October 1, 1998. 28 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The fair value of each option is estimated on the date of grant using the Black- Scholes Option-Pricing model with the following weighted-average assumptions: dividend yield of $0/share for options granted in 1998, 1997 and 1996; expected volatility of 34% for 1998 option grants, 30% for 1997 option grants and 33% for 1996 option grants; risk-free interest rate of 4.35% for 1998 option grants, 5.83% for 1997 option grants and 6.55% for 1996 option grants; expected lives of 6 years for 1998, 1997 and 1996 option grants. A summary of the status of the Company's two fixed stock option plans as of December 31, 1998, 1997 and 1996, and changes during the years ended on those dates are presented below:
1998 1997 1996 --------------------- --------------------- --------------------- Weighted- Weighted- Weighted- Average Average Average Exercise Exercise Exercise Shares Price Shares Price Shares Price ---------- --------- ---------- --------- ---------- --------- FIXED OPTIONS Outstanding at beginning of year 383,490 $ 12.50 276,749 $ 8.30 140,863 $ 7.01 Granted................................... 374,162 11.53 159,374 18.21 137,032 9.62 Exercised................................. (11,482) 7.73 (34,724) 7.24 -- -- Canceled.................................. (231,667) 17.21 (17,909) 8.55 (1,146) -- ---------- --------- ---------- --------- ---------- ---------- Outstanding at end of year................ 514,503 $ 9.78 383,490 $ 12.50 276,749 $ 8.30 ========== ========= ========== ========= ========== ========== Options exercisable at December 31, 1998, 1997 and 1996, respectively.............. 148,840 88,926 63,069 Weighted-average fair value of options granted during the year.................. $ 4.72 $ 7.52 $ 4.27
The following table summarizes information about fixed stock options outstanding at December 31, 1998:
Options Outstanding Options Exercisable -------------------------------------------------------- ------------------------------------- Weighted- Average Weighted- Weighted- Number Remaining Average Number Average Outstanding Contractual Exercise Exercisable Exercise Range of Exercise Prices at 12/31/98 Life Price at 12/31/98 Price - ----------------------------- ------------------ ------------------ ---------------- ------------------- ---------------- $6.99 to $10.50.............. 292,748 6.06 $ 9.05 116,646 $ 8.06 $10.75....................... 221,755 8.72 $10.75 32,194 $ 10.75 ------------------ ------------------ 514,503 7.21 148,840 ================== ===================
NOTE 10. EARNINGS PER SHARE During 1997, the Company adopted SFAS No. 128, Earnings per Share. This statement requires that all periods presented be retroactively restated in accordance with SFAS No. 128. SFAS No. 128 dictates that the computation of earnings per share shall not assume conversion, exercise or contingent issuance of securities that would have an antidilutive effect on earnings (loss) per share. As a result, the denominator for the year ended December 31, 1998, is not adjusted to reflect the Company's stock options outstanding. The options are antidulutive as the incremental shares result in a decrease in loss per share. The following table shows the amounts used in computing earnings per share and weighted average number of shares of dilutive potential common stock for the years ended December 31, 1998, 1997 and 1996 (in 000s, except per share data): 29 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 1998 1997 1996 ---------------------- ---------------------- ---------------------- Net income (loss)..................................... $ (1,211) $ 7,847 $ 7,769 ===================== ====================== ====================== Weighted average number of outstanding shares of common stock used in earnings per share............. 8,490 8,485 6,415 Effect of dilutive securities: Stock options............................... -- 129 66 --------------------- ---------------------- ---------------------- Weighted average number of outstanding shares of common stock used in earnings per share assuming dilution............................................. 8,490 8,614 6,481 ===================== ======================= ======================
NOTE 11. SEGMENT REPORTING In 1998, the Company adopted SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information. The Company's operations are classified into two principal reportable segments, as follows: (1) Processing and Related Services--provides compression, gathering, treatment and NGL extraction, and fractionation services; also purchases and markets natural gas and NGLs; and (2) Exploration and Production--explores for and produces natural gas. The accounting policies of the segments are the same as those described in the "Summary of Significant Accounting Policies." There are no intersegment revenues. MarkWest evaluates the performance of its segments and allocates resources to them based on gross operating income. MarkWest's business is conducted solely in the United States. The table below presents information about gross operating income for the reported segments for the three years ended December 31, 1998. Asset information by reportable segment is not reported, since MarkWest does not produce such information internally.
Processing and Related Exploration and Services Production Total ---------------------- --------------- ------------ 1998 (in 000s): Revenues.................................. $ 62,438 $ 1,184 $ 63,622 Gross operating income.................... $ 9,593 $ 361 $ 9,954 1997 (in 000s): Revenues.................................. $ 77,938 $ 888 $ 78,826 Gross operating income.................... $ 21,792 $ 91 $ 21,883 1996 (in 000s): Revenues.................................. $ 70,405 $ 357 $ 70,762 Gross operating income (loss)............. $ 22,317 $ (59) $ 22,258
A reconciliation of total segment revenues to total consolidated revenues and of total segment gross operating income to total consolidated income, for the years ended December 31, 1998, 1997 and 1996, is as follows:
1998 1997 1996 ---------- ---------- ---------- Revenues: Total segment revenues..................................... $ 63,622 $ 78,826 $ 70,762 Interest income............................................ 200 661 192 Other income (expense)..................................... (124) 196 998 ------------- ---------- ---------- Total consolidated revenues.......................... $ 63,698 $ 79,683 $ 71,952 ============= ========== ==========
30 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Gross operating income: Total segment gross operating income....................... $ 9,954 $ 21,883 $ 22,258 General and administrative expenses........................ (5,319) (6,651) (4,753) Depreciation and amortization.............................. (4,594) (3,246) (2,910) Interest expense........................................... (2,095) (826) (1,090) Interest income............................................ 200 661 192 Other income (expense)..................................... (124) 196 998 Minority interest in net loss of subsidiary................ -- 380 65 --------------- --------------- --------------- Consolidated income (loss) before taxes.............. $ (1,978) $ 12,397 $ 14,760 =============== =============== ===============
NOTE 12. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) The following summarizes certain quarterly results of operations (in 000s):
First Second Third Fourth -------- --------- --------- --------- 1998 - ---- Revenue /(1)/...................................... $ 20,231 $ 11,010 $ 14,092 $ 18,165 Gross profit (loss) /(2)/.......................... 3,308 (53) 359 1,622 Net income (loss).................................. 917 (1,140) (876) (112) Basic earnings (loss) per share.................... $ 0.11 $ (0.13) $ (0.10) $ (0.01) Earnings (loss) per share assuming dilution........ $ 0.11 $ (0.13) $ (0.10) $ (0.01) 1997 - ---- Revenue /(1)/...................................... $ 28,604 $ 11,778 $ 14,947 $ 23,693 Gross profit /(2)/................................. 8,639 2,120 3,030 5,044 Net income......................................... 4,282 300 867 2,398 Basic earnings per share........................... $ 0.50 $ 0.04 $ 0.10 $ 0.28 Earnings per share assuming dilution............... $ 0.50 $ 0.03 $ 0.10 $ 0.28
- ------------------------- /(1)/ Excludes interest income. /(2)/ Excludes general and administrative expenses and interest expense. NOTE 13. SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) Costs The following tables set forth capitalized costs at December 31, 1998, 1997 and 1996, and costs incurred for oil and gas producing activities for the years ended December 31, 1998, 1997 and 1996 (in 000s):
1998 1997 1996 ---------- ---------- ---------- Capitalized costs: Proved properties........................................ $ 8,001 $ 5,329 $ 3,076 Unproved properties..................................... 1,206 1,462 655 ---------- ---------- ---------- Total..................................................... $ 9,207 $ 6,791 $ 3,731 Less accumulated depletion and depreciation.............. (690) (321) (142) ---------- ---------- ---------- Net capitalized costs..................................... $ 8,517 $ 6,470 $ 3,589 ========== ========== ========== Costs incurred: Acquisition of properties Proved................................................... $ 2,632 $ 180 $ 314 Unproved................................................. 12 1,016 214 Development costs......................................... 355 1,608 460 Exploration costs......................................... 284 250 845 ---------- ---------- ---------- Total costs incurred...................................... $ 3,283 $ 3,054 $ 1,833 ========== ========== ==========
31 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS RESULTS OF OPERATIONS The results of operations for oil and gas producing activities, excluding corporate overhead and interest costs, for the years ended December 31, 1998, 1997 and 1996, are as follows (in 000s):
1998/(1)/ 1997 1996 ---------- ---------- ---------- Revenues from sale of oil and gas: Sales.............................................................. $ 1,522 $ 1,102 $ 511 Other.............................................................. 70 24 (36) --------- --------- --------- Total.......................................................... 1,592 1,126 475 Production costs..................................................... Transportation and taxes........................................... (408) (238) (118) Lease operating expense and other.................................. (823) (797) (416) --------- --------- --------- Total.......................................................... (1,231) (1,035) (534) Gross operating income............................................... 361 91 (59) Depreciation, depletion and amortization............................. (431) (204) (132) Income tax benefit (expense)......................................... 27 323 87 --------- --------- --------- Results of operations................................................ $ (43) $ 210 $ (104) ========= ========= =========
/(1)/ The Company generated $206,000 in tax credits in 1998 that the Company was unable to utilize as a result of the Company's consolidated federal tax loss in 1998. RESERVE QUANTITY INFORMATION Reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and of future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in commodity prices and operating costs. Any significant revision of reserve estimates could materially adversely affect the Company's financial condition and results of operations. The following table sets forth information for the years ended December 31, 1998, 1997 and 1996, with respect to changes in the Company's proved reserves, all of which are in the United States.
1998 1997 1996/(1)/ -------------------------- ------------------------- -------------------------- Natural Gas Oil Natural Gas Oil Natural Gas Oil (Mcf) (bbls) (Mcf) (bbls) (Mcf) (bbls) ------------- ----------- ----------- --------- ------------ --------- Proved developed and undeveloped reserves: Beginning of year......... 23,155,910 6,736 6,231,005 21,748 6,500,560 21,748 Revisions of previous estimates.............. 1,164,111 (1,289) (548,185) (15,026) -- -- Purchase of minerals in place.................. 3,029,036 -- -- -- -- -- Extensions and discoveries............ 129,029 14 17,965,809 14 -- -- Production................ (850,041) -- (492,719) -- (269,555) -- Sale of minerals in place. (579,745) (5,461) -- -- -- -- ---------- -------- ---------- ------- ---------- -------- End of year............... 26,048,300 -- 23,155,910 6,736 6,231,005 21,748 ========== ======== ========== ======= ========== ========
32 MARKWEST HYDROCARBOR, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Proved developed reserves: Beginning of year......... 11,025,140 6,736 6,156,645 21,748 6,323,166 -- ========== ======== ========== ======= ========== ======== End of year............... 13,664,760 -- 11,025,140 6,736 6,156,645 21,748 ========== ======== ========== ======= ========== ========
/(1)/ As previously mentioned, the Company was incorporated in 1996. Prior to 1996, the Company did not require the preparation of an estimate of reserves. Accordingly, beginning of the year reserves for 1996 simply reflect 1996 end of the year reserves plus 1996 production. STANDARDIZED MEASURES OF DISCOUNTED FUTURE NET CASH FLOWS Estimated discounted future net cash flows and changes therein were determined in accordance with SFAS No. 69, Disclosures about Oil and Gas Producing Activities. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented. Future cash inflows are computed by applying year-end prices of oil and gas relating to the Company's proved reserves to the year-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements, including futures contracts in existence at year end. The assumptions used to compute estimated future net revenues do not necessarily reflect the Company's expectations of actual revenues or costs, or their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company's control, such as unintentional delays in development, changes in prices or regulatory controls. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized. Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the Company's proved oil and gas reserves. Permanent differences in oil and gas-related tax credits and allowances are recognized. An annual discount rate of 10% was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves. Information with respect to the Company's estimated discounted future cash flows from its oil and gas properties for the years ended December 31, 1998, 1997 and 1996, is as follows (in 000s):
1998 1997 1996 -------- -------- ------- Future cash inflows................................................... $ 51,055 $ 54,757 $ 9,445 Future production costs............................................... (26,886) (26,235) (3,757) Future development costs.............................................. (3,623) (3,650) (75) Future income tax expense............................................. (7,302) (7,464) (2,189) -------- -------- ------- Future net cash flows................................................. 13,244 17,408 3,424 10% annual discount for estimated timing of cash flows................ (8,271) (9,348) (1,408) Standardized measure of discounted future net cash flows relating to -------- -------- ------- proved oil and gas reserves........................................ $ 4,973 $ 8,060 $ 2,016 ======== ======== =======
33 Principal changes in the Company's estimated discounted future net cash flows for the years ended December 31, 1998, 1997 and 1996 are as follows (in 000s):
1998 1997 1996 -------- -------- -------- January 1 $ 8,060 $ 2,016 $ 1,728 Sales and transfers of oil and gas produced, net of production costs................. (304) (228) 10 Net changes in prices and production costs related to future production.............. (3,158) 871 -- Development costs incurred during the period......................................... 355 1,608 460 Changes in estimated future development costs........................................ (339) (1,471) -- Extensions and discoveries........................................................... 81 6,936 -- Revisions of previous quantity estimates............................................. 316 (428) -- Purchases of reserves in place....................................................... 1,471 -- -- Accretion of discount................................................................ 1,086 313 284 Net change in income taxes........................................................... 251 (1,696) (157) Sales of reserves in place........................................................... (673) -- -- Changes in production rates and other................................................ (2,173) 139 (309) ------- ------- ------- December 31............................................................................... $ 4,973 $ 8,060 $ 2,016 ======= ======= =======
34 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ITEM 11. EXECUTIVE COMPENSATION ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12 and 13 are omitted because the Company will file a definitive proxy statement pursuant to Regulation 14A under the Exchange Act of 1934 not later than 120 days after the close of the fiscal year. The information required by such Items will be included in the definitive proxy statement to be so filed for the Company's annual meeting of stockholders scheduled for May 13, 1999, and is hereby incorporated by reference. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) The following documents are filed as part of this report: (1) Financial Statements: Reference is made to the Index to Consolidated Financial Statements included in this Form 10-K for a list of all financial statements filed as a part of this report. (2) Financial Statement Schedules: None required. (3) Exhibits See (c) below. (b) Reports on Form 8-K: None filed in the fourth quarter of 1998. (c) Exhibits required by Item 601 of Regulation S-K. See (a) (3) above. 2.1 Purchase and Sale Agreement between MarkWest Hydrocarbon, Inc., and Michigan Energy Company, L.L.C., dated November 21, 1997 (filed as Exhibit 2.1 to MarkWest Hydrocarbon, Inc.'s Form 8-K filed on January 29, 1998, and incorporated herein by reference). 3.1 Certificate of Incorporation of MarkWest Hydrocarbon, Inc. (filed as Exhibit 3.1). /(1)/ 3.2 Bylaws of MarkWest Hydrocarbon, Inc. /(1)/ 10.1 Amended and Restated Reorganization Agreement made as of August 1, 1996, by and among MarkWest Hydrocarbon, Inc.; MarkWest Hydrocarbon Partners, Ltd.; MWHC Holding, Inc.; RIMCO Associates, Inc.; and each of the limited partners of MarkWest Hydrocarbon Partners, Ltd. /(1)/ 10.2 Participation, Ownership and Operating Agreement for West Shore Processing Company, L.L.C., dated May 2, 1996 (filed as Exhibit 10.7). /(1)/ 10.3 Gas Treating and Processing Agreement, dated May 1, 1996, between West Shore Processing Company, LLC, and Shell Offshore, Inc. (filed as Exhibit 10.10). /(1)/ 35 10.4 Processing Agreement (Kenova Processing Plant), dated March 15, 1995, between Columbia Gas Transmission Corporation and MarkWest Hydrocarbon Partners, Ltd. (filed as Exhibit 10.15). /(1)/ 10.5 Agreement to Design and Construct New Facilities, dated March 15, 1995, between Columbia Gas Transmission Corporation and MarkWest Hydrocarbon Partners, Ltd. (filed as Exhibit 10.19). /(1)/ 10.6 Natural Gas Liquids Purchase Agreement (Boldman Plant), dated December 24, 1990, between Columbia Gas Transmission Corporation and MarkWest Hydrocarbon Partners, Ltd. (filed as Exhibit 10.23). /(1)/ 10.7 1996 Incentive Compensation Plan (filed as Exhibit 10.25). /(1)/ 10.8 1996 Stock Incentive Plan (filed as Exhibit 10.26). /(1)/ 10.9 1996 Non-employee Director Stock Option Plan (filed as Exhibit 10.27). /(1)/ 10.10 Form of Non-Compete Agreement between John M. Fox and MarkWest Hydrocarbon, Inc. (filed as Exhibit 10.28). /(1)/ 10.11 Pipeline Construction and Operating Agreement between Michigan Production Company, L.L.C. and West Shore Processing Company, L.L.C., dated October 1, 1996 (filed as Exhibit 10.31). /(2)/ 10.12 Option and Agreement to Purchase and Sell Pipeline, dated October 1, 1996 (filed as Exhibit 10.34). /(2)/ 10.13 Amendment to Participation, Ownership and Operating Agreement for West Shore Processing Company, L.L.C., dated December 12, 1996 (filed as Exhibit 10.36). /(2)/ 10.14 Amended and Restated Credit Agreement, dated as of June 20, 1997, among MarkWest Hydrocarbon, Inc., as the Borrower; and Certain Commercial Lending Institutions as the Lenders; and Bank of Montreal, acting through certain U.S. branches or agencies, as the Agent for the Lenders (filed as Exhibit 10.1 to MarkWest Hydrocarbon, Inc.'s Form 10-Q for the three months ended June 30, 1997, and incorporated herein by reference). 10.15 MarkWest Hydrocarbon, Inc., 1997 Severance and Non-Compete Plan (filed as Exhibit 10.1 to MarkWest Hydrocarbon, Inc.'s Form 10- Q for the three months ended September 30, 1997, and incorporated herein by reference). 10.16 First Amendment dated as of December 24, 1997, to the Amended and Restated Credit Agreement dated as of June 20, 1997, between MarkWest Hydrocarbon, Inc., as the Borrower; and Certain Commercial Lending Institutions as the Lenders; and Bank of Montreal, acting through certain U.S. branches or agencies, as the Agent for the Lenders (filed as Exhibit 10.26) /(3)/ 10.17 Second Amendment dated as of May 6, 1998, to the Amended and Restated Credit Agreement dated as of June 20, 1997, between MarkWest Hydrocarbon, Inc., as the Borrower; and Certain Commercial Lending Institutions as the Lenders; and Bank of Montreal, acting through certain U.S. branches or agencies, as the Agent for the Lenders (filed as Exhibit 10.1 to MarkWest Hydrocarbon, Inc.'s Form 10-Q for the three months ended June 30, 1998, and incorporated herein by reference). 11. Statement regarding computation of earnings per share. 21. List of Subsidiaries of MarkWest Hydrocarbon, Inc. 23. Consent of PricewaterhouseCoopers LLP. 27. Financial Data Schedule. ________________________ /(1)/ Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513. /(2)/ Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Form 10-K for the year ended December 31, 1996. /(3)/ Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Form 10-K for the year ended December 31, 1997. 36 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, in the City of Englewood, State of Colorado, on March 24, 1999. MarkWest Hydrocarbon, Inc. (Registrant) BY: /s/ John M. Fox --------------------------- John M. Fox President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. /s/ John M. Fox March 24, 1999 ---------------------------- John M. Fox President, Chief Executive Officer and Director /s/ Brian T. O'Neill March 24, 1999 ---------------------------- Brian T. O'Neill Senior Vice President, Chief Operating Officer and Director /s/ Gerald A. Tywoniuk March 24, 1999 ---------------------------- Gerald A. Tywoniuk Chief Financial Officer and Vice President of Finance (Principal Financial and Accounting Officer) /s/ Arthur J. Denney March 24, 1999 ---------------------------- Arthur J. Denney Director /s/ Barry W. Spector March 24, 1999 ---------------------------- Barry W. Spector Director /s/ David R. Whitney March 24, 1999 ---------------------------- David R. Whitney Director 37 EX-11 2 COMPUTATION OF EARNINGS PER COMMON SHARE EXHIBIT 11 MARKWEST HYDROCARBON, INC. COMPUTATION OF EARNINGS PER COMMON SHARE (000S, EXCEPT PER SHARE DATA)
FOR THE YEAR ENDED DECEMBER 31, 1998 ----------------------- Net income (1,211) Weighted average number of outstanding shares of common stock 8,490 Basic earnings per share $ (0.14) ======================= Net income (1,211) Weighted average number of outstanding shares of common stock 8,490 Dilutive stock options 90 ----------------------- 8,580 Earnings per share assuming dilution $ (0.14) =======================
EX-21 3 LIST OF SUBSIDIARIES EXHIBIT 21 MARKWEST HYDROCARBON, INC. LIST OF SUBSIDIARIES
NAME OF SUBSIDIARY TYPE OF ENTITY RELATIONSHIP ------------------ -------------- ------------ 1) MarkWest Michigan, Inc. Colorado Corporation Wholly-owned subsidiary 2) West Shore Processing Company LLC Michigan Limited Liability Company Wholly-owned subsidiary 3) Basin Pipeline LLC Michigan Limited Liability Company Wholly-owned subsidiary 4) MarkWest Resources, Inc. Colorado Corporation Wholly-owned subsidiary 5) 155 Inverness, Inc. Colorado Corporation Wholly-owned subsidiary
EX-23 4 CONSENT OF INDEPENDENT ACCOUNTANTS EXHIBIT 23 Consent of Independent Accountants We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-20829 and No. 333-20833) of MarkWest Hydrocarbon, Inc. of our report dated February 10, 1999 appearing on page 17 of this Form 10-K. PricewaterhouseCoopers LLP Denver, Colorado March 24, 1999 EX-27 5 FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED BALANCE SHEET AND CONSOLIDATED STATEMENTS OF OPERATIONS OF THE COMPANY'S 1998 FORM 10-K AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. YEAR DEC-31-1998 JAN-01-1999 JAN-31-1998 2,055 0 7,858 120 4,583 19,385 102,931 (19,609) 103,631 7,922 38,597 0 0 85 49,950 103,631 63,622 63,698 42,883 42,833 20,698 0 2,095 (1,978) (767) (1,211) 0 0 0 (1,211) (0.14) (0.14)
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