-----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, FF6uZMDCB+/cL7oS2on5e/pr/dLPOZmhObI0p8tYmQob4kf6ZUupwc3hWqLrJw2S 0hoDkiNpXbeT7TZuCQKlMA== 0000912057-00-014402.txt : 20000411 0000912057-00-014402.hdr.sgml : 20000411 ACCESSION NUMBER: 0000912057-00-014402 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000329 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-K SEC ACT: SEC FILE NUMBER: 001-14841 FILM NUMBER: 583032 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-K 1 10-K 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, 1999. [ ] 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: COMMON STOCK, $0.01 PAR VALUE, AMERICAN STOCK EXCHANGE Securities registered pursuant to Section 12(g) of the Act: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes __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. ____ The aggregate market value of voting common stock held by non-affiliates of the registrant on February 29, 2000, was $28,545,586. The number of shares outstanding of the registrant's common stock as of February 29, 2000, was 8,449,816. 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 18, 2000. 1 MARKWEST HYDROCARBON, INC. FORM 10-K TABLE OF CONTENTS
PAGE ---- PART I Items 1. and 2. Business and Properties General.................................................................................................. 3 Strategy................................................................................................. 3 Significant 1999 Developments............................................................................ 3 Segments................................................................................................. 4 Processing and Related Services.......................................................................... 4 Exploration and Production............................................................................... 7 Seasonality.............................................................................................. 7 Competition ............................................................................................. 7 Operational Risks and Insurance.......................................................................... 7 Governmental Regulation.................................................................................. 8 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 Discussion and Analysis of Financial Condition and Results of Operations............. 12 Item 7A. Quantitative and Qualitative Disclosures About Market Risk........................................ 15 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 gain on sale, 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 Mcfd thousand cubic feet of natural gas per day MMBtu million British thermal units MMcf million cubic feet of natural gas MMcfd million cubic feet of natural gas per day 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 and conduct strategic exploration for new natural gas sources. The Company's natural gas processing and related activities include providing compression, gathering, treatment and NGLs extraction services to natural gas producers and pipeline companies. Additionally, MarkWest fractionates NGLs into marketable products and purchases and markets natural gas and NGLs. MarkWest provides natural gas processing and related services through its modern, efficient plant and pipeline systems. Increased drilling for natural gas to meet expanding demand is driving growth for MarkWest's specialized services. Natural gas producers are increasingly outsourcing the complex task of converting raw natural gas produced at the wellhead to marketable natural gas and natural gas liquids. MarkWest is the largest processor of natural gas in Appalachia and is growing rapidly, and the Company owns the only sour gas gathering and processing facilities in western Michigan. The Company also conducts strategic exploration for new natural gas sources for its processing services, primarily in the Rocky Mountains and Michigan. The Company was founded as a partnership in 1988 and incorporated in Delaware in 1996. The Company's principal executive office is located at 155 Inverness Drive West, Suite 200, Englewood, Colorado, 80112-5000, and its telephone number is (303) 290-8700. MarkWest maintains an NGL marketing office in Columbus, Ohio and a gas marketing and Appalachia producer relations office in Pittsburgh, Pennsylvania. STRATEGY MarkWest's strategy is to provide trend-line profit growth exceeding 15% annually by increasing volumes of natural gas processed and volumes of NGLs produced and marketed. The Company focuses on geographic core areas where natural gas production is expected to increase, providing opportunities for reinvestment. This focus allows MarkWest to capitalize on its infrastructure for the benefit of its customers and its shareholders. Innovative engineering, cost-efficient operations and effective NGL marketing are core competencies of the Company. MarkWest also uses exploration to enhance its gas processing business. The Company aims to reduce earnings volatility through emphasis on fee-based services not susceptible to changes in commodity prices and through increasing hedging activities in 2000 and beyond. Fee-based services have increased to account for approximately 50% of gross margins in 2000 from less than 10% six years ago. SIGNIFICANT 1999 DEVELOPMENTS During 1999, MarkWest signed two significant long-term agreements that will nearly double the Company's Appalachian production over the next two years. In order to accommodate the expected production increase, MarkWest launched a two-phase expansion of its Appalachian infrastructure. Phase I expansion was completed in February 2000, and, together with higher production from increased regional drilling, MarkWest expects to see NGL volumes increase from 310,000 gallons per day in 1999 to 460,000 gallons in 2000. This expansion added a new 75 MMcfd, mechanical refrigeration, NGL extraction plant ("Maytown") in southern Kentucky and nearly doubled the capacity, from 350,000 gallons per day to 600,000 gallons per day, of the Company's fractionator ("Siloam") in northern Kentucky. Revenues to be derived from the expansion are primarily fee and percent-of-proceeds based, which differ from MarkWest's historical commodity-based contracts. Finally, MarkWest acquired a 40-mile NGL pipeline in West Virginia. This pipeline, together with MarkWest's existing pipeline and a pipeline leased in 1999, forms a continuous 180-mile pipeline network through the southern portion of the Appalachia Basin. The pipeline connects MarkWest's new Maytown gas plant to MarkWest's Siloam fractionator and significantly reduces feedstock transportation costs from another of MarkWest's gas plants--Boldman. MarkWest's Kenova gas plant is already connected to the pipeline. Boldman and Kenova are located in Kentucky and West Virginia, respectively. Volumes to the Siloam fractionator will continue to grow as Phase II expansion proceeds. Phase II involves expanding MarkWest's Kenova NGL extraction plant, increasing MarkWest's total production to 550,000 gallons per day. Phase II construction is expected to commence mid-2000 for startup in mid-2001. Capital spending for the Phase I and II expansions is estimated at $26 million. In October 1999, all outstanding arbitration and litigation with Columbia Gas Transmission Corporation ("Columbia") was settled. As part of the settlement, MarkWest assumed operations of its Boldman plant--previously leased to and operated by Columbia--on February 1, 2000, and purchased the Cobb plant from Columbia on March 1, 2000, for $0.9 million. Both plants continue to provide unfractionated NGLs to the Company's Siloam fractionator. 3 The Company sold its propane terminal in West Memphis, Arkansas, for $5.5 million in May 1999 because the propane terminal was too remote from MarkWest's other Appalachian assets. In November 1999, the Company acquired a propane terminal in Lynchburg, Virginia, for $2.1 million. In February 2000, MarkWest sold its corporate office building for $5.0 million in net proceeds. In Arenac County in eastern Michigan, MarkWest announced in January 2000 the new Au Gres gas production and processing project. In the first phase of the project, MarkWest expects to bring an existing well into production by mid-second quarter 2000. The second phase of the project is expected to begin in late 2000 or early 2001 and will involve bringing another four wells into production. MarkWest also has a 25% working interest in the field. SEGMENTS The Company's business activities are segregated into two segments: processing and related services, and exploration and production. However, processing and related services are the Company's primary focus. The two segments are located in three core geographic areas: Appalachia, Michigan, and the Rocky Mountains. Processing and related services 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 basins in eastern and western Michigan (the "Michigan Core Area" or "Michigan"). Exploration and production activities are concentrated in the Rocky Mountains and Michigan. These segments are analyzed independently by management and derive revenue from different sources. For financial information related to each segment, see RESULTS OF OPERATIONS, in Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, as well as Note 11, SEGMENT REPORTING, in the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K. PROCESSING AND RELATED SERVICES APPALACHIAN CORE AREA The Company owns and operates in Appalachia four gas processing facilities, one fractionation plant, a NGL pipeline and two propane terminals. Certain information concerning the Appalachian assets is summarized in the following tables:
For the Year Ended Year December 31, 1999 Acquired ---------------------------------------- or Placed Gas NGL Production into Throughput Throughput Throughput Plant Facilities Location Service Capacity (Mcfd) (Gal/Year) - -------------------------------- ---------------------- ---------- ----------------- ----------------- ------------------ Boldman Extraction Plant (1) Pike County, KY 1991 70,000 Mcfd 50,000 10,462,000 Cobb Extraction Plant (2) Kanawha County,WV 2000 35,000 Mcfd 27,000 20,384,000 Kenova Extraction Plant Wayne County, WV 1996 120,000 Mcfd 120,000 74,897,000 Maytown Extraction Plant (4) Floyd County, KY 2000 55,000 Mcfd -- -- Siloam Fractionation Plant South Shore, KY 1988 600,000 Gal/d N/A 112,983,000 (3) Year Sales for the Acquired Year Ended or Placed Throughput Storage December 31, Storage and into Length Capacity Capacity 1999 Transmission Facilities Location Service in Miles (Gal/d) (Gal) (Gal) (3) - -------------------------------- --------------------- ----------- ---------- ------------- ------------ --------------- Siloam Fractionation Storage South Shore, KY 1988 N/A N/A 14,000,000 115,843,000 Terminal and Storage (5) Lynchburg, VA 1999 N/A N/A 270,000 3,352,000 Terminal and Storage Church Hill, TN 1995 N/A N/A 240,000 4,816,000 Kenova to Siloam pipeline Wayne County, WV to 1988 38.5 831,000 N/A N/A South Shore, KY Maytown to Kenova pipeline (6) Lincoln County to 2000 140.0 160,000 N/A N/A Wayne County, WV
(1) MarkWest assumed operations effective February 1, 2000. Previously, Boldman was leased to and operated by a third party. (2) Cobb was acquired March 1, 2000. Cobb was originally placed in service in 1968 and its extracted NGLs have historically been fractionated at Siloam. (3) Includes fractionation of NGLs extracted at Kenova, Boldman and Cobb listed above. 4 (4) Maytown was placed into service in February 2000. Maytown can be expanded to 75,000 Mcfd for a modest amount of capital. (5) Lynchburg was acquired on November 1, 1999. Sales volumes are for the November 1, 1999, through December 31, 1999, time period. (6) A portion of the pipeline is leased from a third party. The Company's Appalachian operations are in the midst of a sizable expansion, growing production from 310,000 gallons per day in 1999 to 550,000 gallons per day by mid-2001. See SIGNIFICANT 1999 DEVELOPMENTS earlier in this section for further information. The Company believes this region has favorable supply and demand characteristics. The Appalachian Core Area is geographically 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, especially during winter high demand periods. There are approximately 10,000 wells behind the Company's NGL extraction plants in Appalachia. This producing basin is one of the country's oldest, but is still one of the most prolific. In fact, gas volumes continue to grow to new records each year, as producers increase the number of new wells drilled each year. Growing production drilling can be attributed to higher gas prices in an area close to the high-demand northeast U.S., improved drilling technologies, and cost reductions, all of which add up to improved economic returns for producers. There are tens of thousands of proved but undrilled locations in Appalachia, which bodes well for future expansion of MarkWest's strategically-located, cost-effective processing and marketing assets. The Kenova, Boldman, Cobb and Maytown plants extract liquids from natural gas for further separation at the Company's Siloam fractionator. All of the NGLs recovered at the Kenova, Maytown and Boldman plants--beginning February 2000, Boldman NGLs are transported to Maytown via tanker trucks--are sent to Siloam via pipeline. Cobb liquids are transported to Siloam via tanker trucks. At the Company's Siloam fractionation plant, extracted NGLs are separated into NGL products, including propane, isobutane, normal butane and natural gasoline. 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 owns and operates propane terminals in Virginia, Tennessee, and, beginning March 2000, Ohio. MarkWest has contracted with producers for the exclusive right to process the producers' hydrocarbon-rich gas currently delivered into producer-owned and Columbia-owned transmission pipelines upstream of the Company's plants under long term contracts. MarkWest also has long term operating agreements with Columbia. The Company currently processes natural gas under contracts containing both keep-whole and fee components. In keep-whole arrangements, the Company's 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 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. The fee may be a per unit of throughput charge or a percentage of the resulting NGL sales ("percent-of-proceeds") or some combination of both. Until 2000, substantially all of the Company's fractionation services in its Appalachian Core Area are provided under keep-whole contracts. The contract for processing services at the new Maytown plant contains fee and percent-of-proceeds components. 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 for the majority 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. The Company is increasing its hedging activities as described in Note 7, COMMODITY PRICE RISK MANAGEMENT, in the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K. Historically, the majority of the Company's operating income has been derived from processing and related services in its Appalachian Core Area. Revenues from the sale of Appalachian NGLs represented 52%, 68%, and 85% of gathering, processing and marketing revenues for the years ended December 31, 1999, 1998, and 1997, respectively. In 1998, the Company started a natural gas marketing group to provide, primarily in Appalachia, more services to natural gas producers, source new gas for the Company's facilities, minimize its replacement Btu cost, and assist with its business development efforts. The Company's natural gas marketing 5 activities are fundamentally high volume, low margin transactions executed in support of MarkWest's processing business. Consequently, an increasing percentage of the Company's overall revenues stem from gas marketing. For the years ended December 31, 1999, 1998 and 1997, 33%, 9%, and 0%, respectively, of gathering, processing and marketing revenue stemmed from gas marketing.
MICHIGAN CORE AREA For the Year Ended Year December 31, 1999 Acquired ----------------------------------- or Placed Throughput Gas NGL Production into Capacity Throughput Throughput Facilities Location Service (Mcfd) (Mcfd) (Gal/Year) - ------------------------------- ---------------------- ----------- --------------- --------------- ---------------- 90-mile sour gas gathering Manistee, Mason and 1996 (1) 35,000 17,800 N/A pipeline Oceana Counties, MI Fisk Gas Plant Manistee County, MI 1998 35,000 17,800 13,500,000
(1) Extended from 31 miles in 1996 to 63 miles in 1997 and 90 miles in 1998. The Company's operations in western Michigan consist of a pipeline and processing plant. The Company's gas gathering pipeline gathers and transports sour gas to a treatment plant, used to remove sulphur, owned and operated by a third party. MarkWest's Fisk processing plant is located adjacent to the third party's treating plant. The Fisk plant processes all of the natural gas gathered by the pipeline and treated by the third party's 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. The Company currently processes natural gas in western Michigan 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 generally sells its propane production as soon as it is produced. The Company's butane-natural gasoline production is transported across the state via tanker trucks to the Marysville Fractionator, where it is separated into NGL products, including isobutane, normal butane and natural gasoline. Since commencing operations in 1996, throughput volumes have steadily risen. Throughput volumes in 1999 were 17.8 MMcfd, up 11% over 1998 volumes. Year 2000 throughput volumes are expected to be about the same as 1999's throughput volumes, without considering year 2000 drilling programs. Low commodity prices in 1998 and the first half of 1999 have curtailed producer capital programs. Consequently, little drilling took place in western Michigan in 1999. 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. While drilling activity and drilling success have been slow to develop, MarkWest's own exploration efforts, along with third-party partners, continue to identify good prospects along the 90-mile pipeline corridor. MarkWest expects to drill and evaluate a minimum of three additional reefs by the end of second quarter 2000. MarkWest has exclusive gathering, treatment and processing agreements with certain producers. Expected natural gas streams 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. In eastern Michigan, the Company contracted with a producer to provide gas processing services for a long-dormant sour gas formation. MarkWest also has a 25% working interest in the field. In the first phase of the project, MarkWest is obtaining required permits, constructing a well facility, modifying an existing gas plant and constructing a pipeline to bring an existing well into production from this formation. It is anticipated that the first phase will be completed by mid-second quarter 2000 at a cost to 6 MarkWest of $1.4 million. The second phase of the project is expected to begin in late 2000 or early 2001 and will involve bringing another four wells into production and constructing additional processing facilities. These wells have never produced from this formation due to the lack of infrastructure. Management believes the project has the potential to grow into a significant contributor to MarkWest. EXPLORATION AND PRODUCTION ROCKY MOUNTAIN CORE AREA MarkWest has focused its exploration and production business in Rocky Mountain coal seam natural gas development--primarily in the San Juan Basin. During the fourth quarter of 1998 and first quarter of 1999, MarkWest sold its interest in three non-core properties for $1.2 million, and reinvested $1.4 million for a 49% interest in properties and gathering systems that overlap its existing San Juan Basin properties. In 1999, nearly $1.3 million was spent, primarily in the second and third quarters, on high-return workover activities on the purchased wells to improve production. Net natural gas sold in the fourth quarter of 1999 averaged 2.7 MMcfd, representing a 69 percent increase from the same period last year, and for the year averaged 2.5 MMcfd, up 32 percent. This increase reflects production acquired in the first quarter of 1999 (net of disposed production) and the benefit realized from the 1999 capital program. During the fourth quarter, MarkWest received approval for additional down-spaced coal wells in the San Juan Basin resulting in approximately twenty additional development locations. As these wells are completed over the next two years, MarkWest expects an additional 1.5-2.0 MMcfd net to its 49 percent interest. It is anticipated that future spacing requests for other producing horizons in MarkWest's San Juan Basin properties could yield another twenty development locations. MICHIGAN CORE AREA For discussion on drilling programs, see PROCESSING AND RELATED SERVICES - MICHIGAN CORE AREA appearing earlier in Items 1 and 2 of this Form 10-K. SEASONALITY 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. COMPETITION The Company faces competition in obtaining natural gas supplies for its processing and related services operations, in obtaining unprocessed NGLs for fractionation, and in marketing its products and services. 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. 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 that of the Company. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. Drilling activity behind the Company's systems varies with industry conditions, commodity prices, and effectively competes for capital with producers' other drilling opportunities. 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. 7 Consistent with insurance coverage generally available to the 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 to be adequate. GOVERNMENT REGULATION In the Michigan Core Area, the Company owns and operates a gathering pipeline in conjunction with its processing plant. Under the Natural Gas Act of 1938, 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 Federal Energy Regulatory Commission 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. The design, construction, operation and maintenance of the Company's pipeline is also subject to safety regulations. Natural gas exploration and production operations are subject to various types of regulation at the federal, state and local levels. The effect of these regulations may limit the amount of gas available to the Company's systems 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. ENVIRONMENTAL MATTERS The Company is subject to environmental risks normally incident to its operations and construction activities including, but not limited to, uncontrollable flows of natural gas, fluids and other substances into the environment, explosions, fires, pollution, and other environmental and safety risks. The following 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 are subject to environmental and safety regulation by federal and state authorities, including, without limitation, the state environmental agencies and the federal Environmental Protection Agency, which can increase the costs of designing, installing and operating its facilities. In most instances, the regulatory requirements relate to the discharge of substances into the environment and include measures to control water and air pollution. Laws and regulations may require a permit or other authorization before certain activities may be conducted by the Company and include fines and penalties for non-compliance. Further, these rules may limit or prohibit activities 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. The Company believes that it is in material compliance with all applicable laws and regulations. EMPLOYEES As of December 31, 1999, the Company had 105 employees. Eleven employees at the Company's Siloam fractionation facility in South Shore, Kentucky, are represented by the Oil, Chemical and Atomic Workers International Union, Local 3-372 (Siloam Sub-Local). The Company's collective bargaining agreement with this Union expires on April 30, 2000. The agreement covers only hourly, non-supervisory 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 and prices of raw natural gas supply; (iv) the ability of the Company to negotiate favorable marketing agreements; (v) the risks that third party or company natural gas exploration and production activities will not occur or be successful; (vi) the Company's dependence on certain significant customers, producers, gatherers, treaters, and transporters of natural gas; (vii) competition from other NGL processors, including major energy companies; (viii) the Company's ability to identify and consummate grassroots projects or 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 Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations included in this Form 10-K. Forward-looking statements involve many uncertainties that are beyond the Company's ability to control and in many cases the Company cannot predict what factors would cause actual results to differ materially from those indicated by the forward-looking statements. ITEM 3. LEGAL PROCEEDINGS The Company is currently involved in litigation arising in the ordinary course of business. Management believes that costs of settlements or judgements, if any, arising from such suits will not have a material adverse effect on the Company's consolidated financial position or results of operations. 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, 1999. 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 December 31, 1999, there were 8,461,702 shares of common stock outstanding held by 506 holders of record. The following table sets forth quarterly high and low sales prices as reported by the American Stock Exchange (and previously the Nasdaq National Market) for the periods indicated.
1998 1999 ------------------------ ----------------------- HIGH LOW HIGH LOW ---- --- ---- --- First Quarter........................... 22 1/2 19 9 1/4 5 3/4 Second Quarter.......................... 22 1/2 14 3/4 11 3/8 7 Third Quarter........................... 15 3/4 8 3/4 8 7/8 5 Fourth Quarter.......................... 11 1/2 7 7 7/8 4 3/4
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; contractual restrictions, if any; restrictions imposed by law and other factors deemed relevant by the Company's Board of Directors. 9 ITEM 6. SELECTED FINANCIAL DATA The selected consolidated statement of operations and balance sheet data for the years ended December 31, 1999, 1998 and 1997, and as of December 31, 1999 and 1998, 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 years ended December 31, 1996 and 1995, and as of December 31, 1997, 1996 and 1995, 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 Item 7 - 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, -------------------------------------------------------------------------------------- 1999 1998 1997 1996 1995 -------------- --------------- ---------------- ---------------- ---------------- (in thousands, except per share amounts and operating data) STATEMENT OF OPERATIONS: Revenues (1),(2)......................... $ 108,634 $ 63,698 $ 79,683 $ 71,952 $ 48,226 Gross margin (3)......................... 29,696 20,739 33,169 29,855 18,825 Operating expenses....................... 12,657 10,785 11,286 7,597 4,706 Cash operating margin (4) ............... 17,039 9,954 21,883 22,258 14,119 General and administrative expenses...... 6,986 5,319 6,651 5,302 4,189 Net income (loss) (1), (10).............. 2,823 (1,211) 7,847 7,769 6,074 Basic earnings per share (1), (5) ....... 0.33 (0.14) 0.92 1.21 1.06 Earnings per share assuming dilution (1), (5)............................. $ 0.33 $ (0.14) $ 0.91 $ 1.20 $ 1.06 Weighted average shares outstanding (6).. 8,475 8,490 8,485 6,415 5,725 CASH FLOW DATA: Cash flows from operating activities, before working capital changes..................... $ 6,393 $ 4,795 $ 12,650 $ 14,702 $ 8,878 Capital and acquisition expenditures..... 17,898 15,890 30,329 17,516 12,426 OTHER FINANCIAL DATA: EBITDA (7)............................... $ 9,777 $ 4,511 $ 15,808 $ 18,568 $ 9,930 BALANCE SHEET DATA (AS OF DECEMBER 31): Working capital (8)...................... $ 11,511 $ 11,463 $ 14,603 $ 11,896 $ 10,369 Property and equipment, gross............ 115,100 102,931 81,269 60,456 41,515 Property and equipment, net.............. 92,311 83,322 65,830 48,140 31,947 Total assets ............................ 119,243 103,631 98,657 78,254 46,896 Long-term debt........................... 44,035 38,597 33,931 11,257 17,500 Partners' capital........................ -- -- -- -- 25,161 Stockholders' equity .................... 52,719 50,035 51,548 43,664 --
10
Year Ended December 31, ------------------------------------------------------------------------------------- 1999 1998 1997 1996 1995 --------------- --------------- ---------------- ---------------- ---------------- OPERATING DATA: Appalachia: NGL production--Siloam plant (Gal)......................... 113,000,000 102,900,000 102,500,000 94,900,000 92,200,000 NGLs marketed--Siloam plant (Gal)......................... 115,800,000 100,900,000 103,400,000 94,600,000 95,500,000 Processing margin per gallon: Average NGL sales price........... $ 0.379 $ 0.304 $ 0.482 $ 0.448 $ 0.354 Average natural gas cost....... 0.266 0.236 0.255 0.235 0.181 --------------- --------------- ---------------- ---------------- ---------------- Average margin................. $ 0.113 $ 0.068 $ 0.227 $ 0.213 $ 0.173 Michigan:(9) Pipeline throughput (Mcfd)........ 17,800 16,000 8,900 4,800 -- NGLs marketed (Gal)............... 13,500,000 10,600,000 -- -- -- Rocky Mountains: Natural gas sold (Mcfd)........... 2,500 1,900 1,400 700 N/M
- ----------------------- N/M--Not meaningful. (1) In 1999, includes $2,509 gain ($1,566, or $0.18 per share, after-tax) from the sale of the Company's West Memphis terminal. (2) Includes gas marketing revenues of $34,100 and $5,600 for the years ended December 31, 1999 and 1998, respectively. The Company's gas marketing business originated in 1998. Gas marketing activities are low margin; these activities are done in support of MarkWest's processing business. (3) Includes gathering, processing, and marketing revenue; oil and gas revenue; and cost of sales. (4) Includes gathering, processing, and marketing revenue; oil and gas revenue; cost of sales; and operating expenses. (5) 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 -------------- -------------- Historical income before income taxes.............. $ 14,760 $ 7,824 Pro forma provision for income taxes............... 5,609 2,937 Pro forma net income............................... 9,151 4,887 Pro forma basic earnings per share................. 1.16 0.85 Pro forma earnings per share assuming dilution..... $ 1.15 $ 0.85 Pro forma weighted average shares outstanding (a).. 7,908 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 year ended December 31, 1995, represent the weighted average number of common shares issued in the Reorganization. (6) 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 year ended December 31, 1995, represent the weighted average number of common shares issued in the Reorganization. (7) Earnings (loss) before interest income; interest expense; income taxes; depreciation, depletion, and amortization; and gain on sale of West Memphis terminal. (8) Includes cash of $1,356; $2,055; $1,364; $4,401; and $761, respectively. (9) 1999, 1998 and 1997 results reflect the Company's acquisition of the remaining percent interest of the Michigan operations in November 1997. Prior to November 1997, MarkWest owned 60 percent of the Michigan operations. Pipeline operations commenced in 1996; the Fisk processing plant commenced operations in 1998. (10) 1995 net income includes a $1,750 extraordinary loss on extinguishment of debt. 11 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following analysis should be read in conjunction with Item 6 - Selected Financial Data and the Company's Consolidated Financial Statements included in this Form 10-K. RESULTS OF OPERATIONS YEAR ENDED DECEMBER 31, 1999, COMPARED TO YEAR ENDED DECEMBER 31, 1998 OVERVIEW. For the year ended December 31, 1999, MarkWest reported net income of $2.8 million, or $0.33 per share, on revenues of $108.6 million, a $4.0 million increase in net income over 1998's net loss of $1.2 million, or $0.14 per share, on revenues of $63.7 million. Aside from the Company's $1.5 million, or $0.18 per share, after-tax gain on the sale of the Company's West Memphis terminal, record NGL production and sales in Appalachia, contributing an incremental $0.6 million after-tax in 1999, coupled with improving Appalachian processing margins, contributing an incremental $3.2 million after-tax in 1999, were the primary reasons behind the Company's return to profitability in 1999. MarkWest sold 115.8 million gallons of NGLs in 1999, a 15% increase over 1998 levels, as gas production increased behind the Company's facilities. Appalachian processing margins averaged $0.113 per gallon in 1999, up 66% over 1998, but still significantly below the Company's $0.165 per gallon ten-year historical average. Increased NGL prices contributed to improving margins. Increased profitability from MarkWest's terminals, due to increased NGL sales prices, and Michigan operations, due to increased throughput and NGL sales prices, contributed an incremental $1.6 million after-tax in 1999. Expected increases in operating, general and administrative, interest and depreciation, depletion and amortization expenses reduced after-tax results an incremental $2.9 million in 1999. GATHERING, PROCESSING AND MARKETING REVENUE. Gathering, processing and marketing revenue increased $42.4 million, or 68%, for the year ended December 31, 1999, compared to the year ended December 31, 1998. The revenue increase was principally attributable to a $28.5 million increase in the Company's gas marketing operations. At the Company's Siloam fractionation facility, higher NGL sales prices and larger volumes of NGLs marketed contributed an incremental $8.7 million and $4.5 million, respectively, to 1999 revenues. OIL AND GAS REVENUE. Oil and gas revenue increased $0.4 million for the year ended December 31, 1999, compared to the year ended December 31, 1998. This increase was primarily attributable to an increase in gas production from the prior year. COST OF SALES. Cost of sales increased $33.8 million, or 79%, for the year ended December 31, 1999, compared to the year ended December 31, 1998. This increase was primarily caused by a $28.5 million increase in gas marketing purchases. At the Company's Siloam fractionation facility, both higher natural gas costs and larger volumes of natural gas purchased contributed an incremental $3.4 million and $3.5 million, respectively, to 1999 cost of sales. OPERATING EXPENSES. Operating expenses increased $1.9 million, or 17%, for the year ended December 31, 1999, compared to the year ended December 31, 1998. The increase in operating expenses was principally attributable to four factors. First, certain expenses increased with volumes in Appalachia, Michigan and the Rocky Mountains. Second, MarkWest sold and leased back three compressors at its Kenova processing plant beginning in the third quarter of 1998. Consequently, 1999 operating expenses include twelve full months of lease expense whereas the results from the comparable time period in 1998 do not. Further, these compressors were overhauled in 1999. Third, 1998 operating expenses were lower due to a sales and use tax refund during that period. Last, performance-based incentive compensation increased in 1999; MarkWest did not pay bonuses in 1998 due to the Company's overall net loss. GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses increased $1.7 million, or 31%, for the year ended December 31, 1999, compared to the year ended December 31, 1998. This increase is attributable to increased performance-based incentive compensation (MarkWest did not pay bonuses in 1998 due to the Company's overall net loss); professional service fees also increased in 1999 due to the Company's arbitration with Columbia, now since settled; and to increased business development expenditures. DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and amortization increased $0.5 million, or 10%, for the year ended December 31, 1999, compared to the year ended December 31, 1998. This increase was principally due to the Company's pipeline extension in Michigan placed in service during mid-1998. INTEREST EXPENSE. Interest expense increased $0.7 million for the year ended December 31, 1999, compared to the year ended December 31, 1998, due to increased average outstanding debt and higher interest rates. 12 YEAR ENDED DECEMBER 31, 1998, COMPARED TO YEAR ENDED DECEMBER 31, 1997 OVERVIEW. 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. Appalachia's full-year 1998 gas processing margin of $0.068 per gallon was approximately 60% below its ten-year average and down by 70% compared to 1997's average of $0.227 per gallon. 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 $0.3 million 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 $0.5 million 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 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 $0.5 million, 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. Additionally, the Company had lower performance-based incentive compensation expense in 1998 due to the Company's overall net loss. These decreases were 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. Finally, the Company had lower performance-based incentive compensation expense in 1998 due to the Company's overall net loss. 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. 13 LIQUIDITY AND CAPITAL RESOURCES For the past three years, the Company's sources of liquidity and capital resources have been internal cash flow; its revolving line of credit; and, in 1999, proceeds from the sale of the Company's West Memphis terminal. MarkWest believes its ability to generate cash from operations to reinvest in its business is one of its fundamental financial strengths. The Company anticipates that its operating activities in 2000, coupled with selective asset sales and existing bank credit arrangements, will continue to provide adequate cash flows for its business expansion and to meet its financial commitments. The consolidated statements of our cash flows, detailed in the Consolidated Financial Statements in Item 8 of this Form 10-K, are summarized as follows (in 000s):
For the Year Ended December 31, ------------------------------------------------------ 1999 1998 1997 --------------- --------------- --------------- Net cash provided by operating activities before change in working capital.............................. $ 6,393 $ 4,795 $ 12,650 Net cash provided by operating activities from change in working capital ............................. (253) 3,638 (7,894) Net cash used in investing activities.............. (11,884) (11,559) (30,329) Net cash provided by financing activities.......... $ 5,045 $ 3,817 $ 22,536
Cash provided by operating activities before change in working capital in 1999 amounted to $6.4 million, a 33% increase from 1998, primarily due to increased gas processing margins and volumes at the Company's Appalachian facilities. In 1998, cash provided by operating activities before change in working capital amounted to $4.8 million, a 62% decrease from 1997. This increase resulted from a decrease in gas processing margins at MarkWest's Appalachian plants in 1998. CAPITAL INVESTMENT PROGRAM Investing activities consist primarily of capital and acquisition expenditures and sales of assets. 1999 and 1998 programs were of similar size. The Company's capital expenditures are summarized as follows (in 000s):
For the Year Ended December 31, ----------------------------------------------------- 1999 1998 1997 -------------- --------------- --------------- Appalachia: Phase I expansion................................... $ 9.3 $ -- $ -- Terminal and storage facilities..................... 2.1 -- -- Rocky Mountains: Exploration and production.......................... 3.6 2.9 3.6 Western Michigan: Pipeline expansion.................................. 0.1 10.7 1.9 Fisk extraction plant............................... -- -- 7.2 Exploration and production.......................... 0.8 0.1 -- Eastern Michigan: Au Gres project..................................... 0.2 -- -- Purchase of office building............................... -- -- 4.6 Maintenance capital and other............................. 1.8 2.2 2.0 -------------- --------------- --------------- Total capital expenditures.......................... $ 17.9 $ 15.9 $ 19.3 ============== =============== ===============
Looking ahead, MarkWest is anticipating a baseline capital budget of $16 million in 2000 and $12 million in 2001. This budget will fund the completion of Phase I and Phase II expansion in Appalachia and other requirements, including Michigan drilling and maintenance capital. In addition, MarkWest is targeting another $20 million in other new projects and acquisitions. Management believes that funds generated from operations, the February 2000 sale of the Company's office building for $5.0 million in net cash proceeds, and unused borrowing capacity will enable the Company to fund its 2000-2001 capital expenditure programs. 14 FINANCING FACILITIES Financing activities consist primarily of net borrowings under the Company's credit facility, which is described in Note 3 to the Company's Consolidated Financial Statements in Item 8 of this Form 10-K. At December 31, 1999, the Company had approximately $46.9 million of available credit, of which net debt of $42.8 million had been utilized as of December 31, 1999, and working capital of $11.5 million. As 2000 progressed, the Company's credit availability increased as the trailing cash flow calculation, the determinant of the Company's available credit, rose because of improvements in Appalachia processing margins. In addition, the Company sold its corporate office building in February 2000 for $5.0 million in net proceeds to further increase its financial flexibility. As of February 29, 2000, unutilized credit had increased to approximately $18 million. Depending on the timing and amount of the Company's future projects beyond the level described above, it may be required to seek additional sources of capital. While the Company believes that it will 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. 2000 OUTLOOK Overall, Company earnings volatility will be diminished in 2000, compared to 1999, as additional fee-based revenues, a result of long-term agreements signed with a large Appalachian producer in mid-1999 for new facilities coming on-line in early 2000, become a part of MarkWest's revenue mix. Assuming normal processing margins in Appalachia, the Company anticipates fee-based activity will generate approximately 50% of total gross margins in 2000. It is anticipated that facility expansion, coupled with increased producer drilling behind Company-owned facilities, should push Appalachian production and sales volumes to record levels in 2000. NGL prices in the fourth quarter of 1999 were above historical levels and are expected to remain so during the first quarter of 2000. These prices are often correlated with and driven by the price of crude oil, which appears to have recovered from its decline in 1998 through mid-1999. MarkWest has implemented as of February 29, 2000, hedges to lock in approximately 60% of its year 2000 Appalachian liquid volumes subject to keep-whole contracts at a $0.20 per gallon margin. For further risk management information, see Note 7, COMMODITY PRICE RISK MANAGEMENT, in the Notes to the Company's Consolidated Financial Statements in Item 8 of this Form 10-K. Throughput volumes in Michigan for 2000 are expected to remain near 1999 levels. Drilling by the Company and third parties is scheduled for the first half of 2000. Rocky Mountain production is expected to increase 20% in 2000 compared to 1999 as a result of the Company's capital investment program. COMMODITY PRICE RISK MANAGEMENT ACTIVITIES Reference is made to Note 7 of the Company's Consolidated Financial Statements in Item 8 of this Form 10-K. IMPACT OF THE YEAR 2000 ISSUE The Year 2000 Issue was the result of computer programs being written using two digits rather than four to define the applicable year. Unless computer programs were Year 2000 compliant, any computer programs that had date-sensitive software could have recognized a date using "00" as the year 1900 rather than the year 2000. This could have resulted 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 experienced no Year 2000 related problems in any of the Company's systems. MarkWest conducted a thorough evaluation of all systems well in advance of December 31, 1999, and met Company objectives with total expenditures of approximately $0.1 million. 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. 15 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 $1.2 million in pretax income for every $0.01 per gallon change in NGL prices and an annual sensitivity to natural gas prices equal to $1.2 million in pretax income for every $0.10/MMBtu change in natural gas prices. For 2000, the Company has hedged approximately 60% of its Appalachian keep-whole volumes as of February 29, 2000, reducing the annual sensitivity accordingly. The Company typically hedges a portion of its commodity price risk. 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. See related discussion in Note 7 to the Company's Consolidated Financial Statements. 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. 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 $0.4 million. 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, 1999. 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, 1999 and 1998...................................... 18 Consolidated Statement of Operations for each of the three years in the period ended December 31, 1999............................................................ 19 Consolidated Statement of Cash Flows for each of the three years in the period ended December 31, 1999............................................................ 20 Consolidated Statement of Changes in Stockholders' Equity for each of the three years in the period ended December 31, 1999..................................................... 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 sheets and related consolidated statements of operations, of cash flows and of changes in stockholders' equity present fairly, in all material respects, the financial position of MarkWest Hydrocarbon, Inc., a Delaware corporation, and its subsidiaries at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. 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 auditing standards generally accepted in the United States 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 9, 2000 17 MARKWEST HYDROCARBON, INC. CONSOLIDATED BALANCE SHEET (000S, EXCEPT PER SHARE DATA)
December 31, ------------------------------ ASSETS 1999 1998 --------------- ------------- Current assets: Cash and cash equivalents.............................. $ 1,356 $ 2,055 Receivables, net of allowance for doubtful accounts of $0 and $120, respectively............................ 16,360 7,738 Inventories ........................................... 6,043 4,583 Prepaid feedstock ..................................... 1,895 1,957 Receivable from income taxes paid...................... -- 2,763 Other assets........................................... 327 289 --------------- ------------- Total current assets........................... 25,981 19,385 Property and equipment: Gas processing, gathering, storage and marketing equipment............................................ 78,476 76,659 Oil and gas properties and equipment................... 14,518 10,566 Land, buildings and other equipment.................... 11,409 11,240 Construction in progress............................... 10,697 4,466 -------------- ------------- 115,100 102,931 Less: accumulated depreciation, depletion and amortization......................................... (22,789) (19,609) --------------- ------------- Total property and equipment, net.............. 92,311 83,322 Intangible assets, net of accumulated amortization of $438 and $169, respectively.................................. 951 924 --------------- ------------- Total assets................................... $119,243 $103,631 =============== ============= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Trade accounts payable................................. $ 4,997 $ 2,765 Accrued liabilities.................................... 9,369 5,094 Current portion of long-term debt...................... 104 63 --------------- ------------- Total current liabilities...................... 14,470 7,922 Deferred income taxes...................................... 8,019 7,077 Long-term debt............................................. 44,035 38,597 Commitments and contingencies.............................. -- -- 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 8,531,206 shares issued, respectively........................................ 85 85 Additional paid-in capital............................. 42,222 42,693 Retained earnings...................................... 10,801 7,978 Treasury stock; 69,504 and 60,300 shares, respectively......................................... (389) (721) --------------- ------------- Total stockholders' equity..................... 52,719 50,035 --------------- ------------- Total liabilities and stockholders' equity..... $119,243 $ 103,631 =============== =============
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, ----------------------------------------------------------- 1999 1998 1997 ---------------- ----------------- ----------------- Revenue: Gathering, processing and marketing revenue.................. $ 104,810 $ 62,438 $ 77,938 Oil and gas revenue, net of transportation and taxes......... 1,538 1,184 888 Interest income.............................................. 53 200 661 Gain on sale of West Memphis terminal........................ 2,509 -- -- Other income (expense)....................................... (276) (124) 196 ---------------- ----------------- ----------------- Total revenue........................................... 108,634 63,698 79,683 ---------------- ----------------- ----------------- Costs and expenses: Cost of sales ............................................... 76,652 42,883 45,657 Operating expenses........................................... 12,657 10,785 11,286 General and administrative expenses.......................... 6,986 5,319 6,651 Depreciation, depletion and amortization..................... 5,070 4,594 3,246 Interest expense............................................. 2,745 2,095 826 ---------------- ----------------- ----------------- Total costs and expenses................................ 104,110 65,676 67,666 ---------------- ----------------- ----------------- Income (loss) before minority interest and income taxes.......... 4,524 (1,978) 12,017 Minority interest in net loss of subsidiary...................... -- -- 380 ---------------- ----------------- ----------------- Income (loss) before income taxes................................ 4,524 (1,978) 12,397 Provision (benefit) for income taxes: Current...................................................... 759 (2,235) 2,918 Deferred..................................................... 942 1,468 1,632 ---------------- ----------------- ----------------- Net income (loss)................................................ $ 2,823 $ (1,211) $ 7,847 ================ ================= ================= Basic earnings (loss) per share ................................. $ 0.33 $ (0.14) $ 0.92 ================ ================= ================= Earnings (loss) per share assuming dilution ..................... $ 0.33 $ (0.14) $ 0.91 ================ ================= ================= Weighted average number of outstanding shares of common stock: Basic........................................................ 8,475 8,490 8,485 ================ ================= ================= Assuming dilution............................................ 8,481 8,490 8,614 ================ ================= =================
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, ------------------------------------------------ 1999 1998 1997 ------------- ------------- ------------- Cash flows from operating activities: Net income (loss)..................................................... $ 2,823 $ (1,211) $ 7,847 Add income items that do not affect working capital: Depreciation, depletion and amortization.......................... 5,070 4,594 3,246 Deferred income taxes............................................. 942 1,468 1,632 (Gain) loss on disposition of assets.............................. 67 (56) (75) Gain on sale of West Memphis terminal............................. (2,509) -- -- ------------- ------------- ------------- 6,393 4,795 12,650 Adjustments to working capital: (Increase) decrease in receivables................................ (8,622) 2,541 (1,614) (Increase) decrease in inventories................................ (1,460) 558 491 (Increase) decrease in prepaid expenses and other assets.......... 2,787 379 (3,099) Increase (decrease) in accounts payable and accrued liabilities... 7,042 160 (3,672) ------------- ------------- ------------- (253) 3,638 (7,894) Net cash flow provided by operating activities................. 6,140 8,433 4,756 Cash flows from investing activities: Capital expenditures.............................................. (17,898) (15,890) (19,323) Proceeds from sale/leaseback transaction.......................... -- 4,281 -- Proceeds from sale of assets...................................... 6,014 -- -- Acquisition of interest in Michigan project....................... -- -- (8,563) Change in note receivable and other............................... -- 50 (2,443) ------------- ------------- ------------- Net cash used in investing activities.......................... (11,884) (11,559) (30,329) Cash flows from financing activities: Proceeds from issuance of long-term debt.......................... 48,056 39,200 39,920 Repayments of long-term debt...................................... (42,577) (34,627) (17,246) Debt issuance costs............................................... (295) (454) (175) Net acquisition of treasury stock................................. (139) (394) (455) Proceeds from exercise of options and payment on share purchase notes................................................. -- 92 492 ------------- ------------- ------------- Net cash provided by financing activities...................... 5,045 3,817 22,536 ------------- ------------- ------------- Net increase (decrease) in cash and cash equivalents........... (699) 691 (3,037) Cash and cash equivalents at beginning of year............................ 2,055 1,364 4,401 ------------- ------------- ------------- Cash and cash equivalents at end of year.................................. $ 1,356 $ 2,055 $ 1,364 ============= ============= =============
The accompanying notes are an integral part of these financial statements. 20 MARKWEST HYDROCARBON, INC. CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (000S)
SHARES OF SHARES OF ADDITIONAL TOTAL COMMON TREASURY COMMON PAID-IN RETAINED TREASURY STOCKHOLDERS' STOCK STOCK STOCK CAPITAL EARNINGS STOCK EQUITY ------------------------------------------------------------------------------------------------- Balance, December 31, 1996....... 8,485 -- $ 85 $ 42,237 $ 1,342 $ -- $ 43,664 Net income....................... -- -- -- -- 7,847 -- 7,847 Payments received on notes receivable..................... -- -- -- 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 Net income....................... -- -- -- -- 2,823 -- 2,823 Acquisition of treasury stock.... -- (156) -- -- -- (1,035) (1,035) Reissuance of treasury stock..... -- 147 -- (471) -- 1,367 896 ------------------------------------------------------------------------------------------------- Balance, December 31, 1999....... 8,531 (69) $ 85 $ 42,222 $ 10,801 $ (389) $ 52,719 ==================================================================================================
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 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. 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: MarkWest Resources, Inc.; MarkWest Michigan, Inc.; and 155 Inverness, Inc. 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, ----------------------- 1999 1998 --------- --------- Product inventory.................................... $5,629 $4,064 Materials and supplies inventory..................... 414 519 --------- --------- $6,043 $4,583 ========= =========
Product inventory consists primarily of finished goods (propane, butane, isobutane, natural gasoline and, in 1999, 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, 1999 and 1998, were $20,000 and $525,000, 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. PROPERTY AND EQUIPMENT Property 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. Depletion 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 22 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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, 1999 and 1998, approximately $1.2 million and $0.5 million 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, 1999. 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. 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. 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 Statement of Financial Accounting Standards ("SFAS") No. 80, ACCOUNTING FOR FUTURES CONTRACTS. Gains and losses on such hedge contracts are deferred and included as a component of revenues or cost of sales when the hedged production is sold. 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, 1999 and 1998, based on rates available for similar types of debt, the fair value of long-term debt was not materially different from its carrying amount. 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, 1999 and 1998, 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 8 for the applicable disclosures required by SFAS No. 123. EARNINGS PER SHARE (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. 23 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEGMENT REPORTING In accordance with SFAS No. 131, DISCLOSURES ABOUT SEGMENTS OF AN ENTERPRISE AND RELATED INFORMATION, the internal organization that is used by management for making operating decisions and assessing performance is the source of the Company's reportable segments (see Note 11, SEGMENT REPORTING). SUPPLEMENTAL CASH FLOW INFORMATION
Year Ended December 31, ---------------------------------------------------------- 1999 1998 1997 ----------------- ----------------- ----------------- Interest paid.......................................... $ 2.7 million $ 2.4 million $ 1.0 million Interest expense capitalized to various construction projects................................ $ 0.2 million $ 0.3 million -- Income taxes paid...................................... $ 0.6 million $ 0.6 million $ 7.0 million
Non-cash investing activities in 1998 included the forgiveness of a note and related interest receivable valued at $10.1 million in exchange for the title to a 32-mile pipeline in Michigan. RECENT ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board issued Statement No. 133, ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES. This statement, as amended by SFAS No. 137, is effective for fiscal years beginning after June 15, 2000. Earlier application is encouraged; however, the Company does not anticipate adopting SFAS No. 133 until the fiscal year beginning January 1, 2001. 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. 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 1999 presentation. NOTE 3. DEBT CREDIT FACILITY Effective September 29, 1999, the Company amended and restated its existing credit agreement. The amended and restated agreement with two commercial banks extends through the year 2005 and provides for a maximum borrowing amount of $50 million pursuant to a revolving loan commitment. 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 loan option, plus an applicable margin of between 0% and 2.75%, based on a certain Company debt to earnings ratio. At December 31, 1999, the Company had $40.5 million outstanding under the credit facility bearing interest at an average rate of 9.25%. At December 31, 1998, the Company had $35 million outstanding under the credit facility bearing interest at an average rate of 7.8%. The Company pays a fee at a rate between 0.25% and 0.50% 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. 155 INVERNESS BUILDING LOAN Effective January 14, 1998, the Company's wholly owned subsidiary, 155 Inverness, Inc., obtained a $3.7 million loan from an insurance company to refinance an office building. As of December 31, 1999, approximately $3.6 million was outstanding under the note. The Company sold the office building in February 2000 for net cash proceeds of $5.0 million, resulting in a loss of 24 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS approximately $0.1 million. In accordance with SFAS No. 121, ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED OF, the Company recognized this loss in 1999. SCHEDULED DEBT MATURITIES Scheduled debt maturities, excluding the Company's building loan paid off in February 2000, as of December 31, 1999, are as follows (in 000s): 2000 .................... $ 42 2001 .................... -- 2002 .................... 3,000 2003..................... 12,500 2004 and thereafter...... 25,000 ---------- Total.................... $40,542 ==========
NOTE 4. RELATED PARTY TRANSACTIONS The Company, through its wholly owned subsidiary, MarkWest Resources, Inc. ("Resources"), holds varied undivided interests 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 operating 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, 1999 and 1998, the Company has receivables due from MAK-J for approximately $426,000 and $0, and payables to MAK-J for approximately $400,000 and $488,000, respectively. The Company made contributions of $328,000, $164,000 and $271,000 to a profit-sharing plan for the years ended December 31, 1999, 1998 and 1997, respectively. The plan is discretionary, with annual contributions determined by the Company's Board of Directors. NOTE 5. LEASE OBLIGATIONS The Company has various non-cancelable operating lease agreements for equipment and office space expiring at various times though fiscal 2010. Rent expense under these operating leases was approximately $615,000 and $222,000 for the years ended December 31, 1999 and 1998, respectively. The Company's minimum future lease payments under these operating leases as of December 31, 1999, are as follows (in 000s): 2000 .................... $1,119 2001 .................... 1,210 2002 .................... 1,210 2003..................... 1,220 2004 and thereafter...... 5,517 ---------- Total.................... $10,276 ==========
NOTE 6. SIGNIFICANT CUSTOMERS For the years ended December 31, 1998 and 1997, sales to one customer accounted for approximately 9% and 19% of total revenues. There were no significant customers for the year ended December 31, 1999. NOTE 7. COMMODITY PRICE RISK MANAGEMENT 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. Hedging levels increase with capital commitments and debt levels and when above-average margins exist. 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- ("NYMEX") traded futures, and fixed/floating price swaps on the over-the-counter ("OTC") market. Futures and swaps allow the Company to 25 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS protect margins, because gains or losses in the physical market are generally offset by corresponding losses or gains in the value of financial instruments. The Company enters into futures transactions on NYMEX and through OTC swaps with various counterparties, consisting primarily of other energy companies. The Company conducts its standard credit review of OTC counterparties and has agreements with such parties that contain collateral requirements. The Company generally uses standardized swap agreements that allow for offset of positive and negative exposures. OTC exposure is marked to market daily for the credit review process. The Company's OTC credit risk exposure is partially limited by its ability to require a margin deposit from its major counterparties based upon the mark-to-market value of their net exposure. The Company is subject to margin deposit requirements under NYMEX and OTC agreements. The use of financial instruments may expose the Company to the risk of financial loss in certain circumstances, including instances when (a) equity volumes are less than expected, or (b) the Company's OTC counterparties fail to purchase or deliver the contracted quantities of natural gas, NGLs, or crude oil or otherwise fail to perform. To the extent that the Company engages in hedging activities, it may be prevented from realizing the benefits of favorable price changes in the physical market. However, it is similarly insulated against decreases in such prices. MarkWest seeks to reduce its basis risk for natural gas but is generally unable to do so for NGLs. Basis is the difference in price between the physical commodity being hedged and the price of the futures or physical contract used for hedging. Basis risk is the risk that an adverse change in the futures or physical market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. The Company's basis risk primarily stems from the geographic price differentials between MarkWest's sales locations and futures or OTC contract delivery locations. The Company protects Appalachia processing margins using a combination of three different methods. MarkWest protects margins by purchasing natural gas priced on predetermined Btu differentials to propane or crude prices. As of December 31, 1999, the Company had no open positions of this transaction type. MarkWest also protects margins by purchasing natural gas while simultaneously selling propane of approximately the same Btu value. As of December 31, 1999, the Company had locked in an approximate margin of $0.23 per gallon on 7.6 million gallons of the Company's expected production through February 2000. Finally, MarkWest protects its margins by selling crude and purchasing natural gas. As of December 31, 1999, the Company had locked in an approximate margin of $0.15 per gallon on 26.9 million gallons of the Company's expected production through December 2000. Crude oil is highly correlated with certain NGL products. All projected margins on open positions at December 31, 1999, assume the basis differentials between the Company's sales location and the hedging contract's specified location and between crude oil and NGLs are consistent with historical averages. No basis risk was hedged except for a portion of the natural gas. Given the size of the Company's capital expenditure program, the Company's primary hedging strategy in 1999 was designed to protect a portion of its Appalachian margins against a further decline in product prices from those experienced in the first quarter of that year. This strategy limited the benefit to MarkWest of the increase in margins seen in the second half of 1999. Consequently, net income would have been higher by approximately $0.9 million for 1999 had the hedge positions not been in place. The Company hedges exposure to changes in spot market prices on certain levels of natural gas production. As of December 31, 1999, the Company locked in an average sales price of $1.97/Mcf on 4,000 Mcfd of production through October 2000, an average sales price of $2.29/Mcf on 3,000 Mcfd of November 2000 to October 2001 production, and an average sales price of $2.39/Mcf on 1,000 Mcfd of November 2001 to October 2002 production. 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 years ended December 31, 1999 and 1998, were not material. In addition to these risk management tools, MarkWest utilizes its NGL 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. 26 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 8. INCOME TAXES The provision (benefit) for income taxes is comprised of (in 000s):
Year Ended December 31, ---------------------------------------- 1999 1998 1997 ------------ ------------ ------------ Current: Federal...................... $ 788 $(1,921) $ 2,510 State........................ (29) (314) 408 ------------ ------------ ------------ Total current................ 759 (2,235) 2,918 ------------ ------------ ------------ Deferred: Federal...................... 664 1,413 1,419 State........................ 278 55 213 ------------ ------------ ------------ Total deferred............... 942 1,468 1,632 ------------ ------------ ------------ Total tax provision.......... $ 1,701 $ (767) $ 4,550 ============ ============ ============
The deferred tax liabilities (assets) are comprised of the tax effect of the following (in 000s):
1999 1998 ----------- ---------- Property and equipment........................ $ 9,840 $6,934 Other assets.................................. 224 300 ----------- ---------- Total deferred income tax liabilities.... 10,064 7,234 ----------- ---------- Alternative minimum tax ("AMT") credit carryforward................................ (1,888) -- State net operating loss ("NOL") carryforwards (151) (151) Intangible assets............................. (6) (6) ----------- ---------- Total deferred income tax assets......... (2,045) (157) ----------- ---------- Net deferred tax liability............... $ 8,019 $7,077 =========== ==========
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, 1999, 1998 and 1997, are as follows (in 000s):
1999 % 1998 % 1997 % ---------- ---------- ----------- --------- ------------ ---------- Income tax at statutory rate...... $1,583 35.0% $(672) (34.0%) $4,339 35.0% State income taxes, net of federal benefit....................... 168 3.7% (102) (5.1%) 403 3.3% Credits........................... (75) (1.7%) -- -- (204) (1.6%) Other............................. 25 0.6% 7 0.3% 12 0.1% ---------- ---------- ----------- --------- ------------ ---------- Total......................... $1,701 37.6% $(767) 38.8% $4,550 36.8% ========== ========== =========== ========= ============ ==========
27 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS At December 31, 1999, the Company had NOL carryforwards for state income tax purposes and AMT credit carryforwards for federal income tax purposes of approximately $2.2 million and $1.9 million, respectively. These carryforwards expire as follows (000s):
Expiration Dates NOL AMT ------------- ---------- ----------- 2004............ $ 565 $ -- 2014............ 1,645 -- No expiration... -- 1,888 ---------- ----------- Total $ 2,210 $ 1,888 ========== ===========
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, 1999, 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):
1999 1998 1997 ------------- ------------- ------------- Net income (loss) As reported.......... $ 2,823 $ (1,211) $ 7,847 Pro forma............ 2,428 (1,483) 7,732 Basic earnings (loss) per share As reported.......... $ 0.33 $ (0.14) $ 0.92 Pro forma............ 0.29 (0.17) 0.91 Earnings (loss) per share As reported.......... $ 0.33 $ (0.14) $ 0.91 assuming dilution Pro forma............ 0.29 $ (0.17) $ 0.89
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 25% per year for 1999 option grants and 20% per year for options granted prior to 1999. 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 the date the director first becomes a director and biannually thereafter. Options granted upon the date the director first becomes a director vest at the rate of 33.33% per year. Biannual options 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. 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 1999, 1998 and 1997; expected volatility of 40% for the 1999 option grants, 34% for 1998 option grants and 30% for 1997 option grants; risk-free interest rate of 6.22% for 1999 option grants, 4.35% for 1998 option grants, 5.83% for 1997 option grants; expected lives of 6 years for 1999, 1998 and 1997 option grants. 28 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A summary of the status of the Company's two fixed stock option plans as of December 31, 1999, 1998 and 1997, and changes during the years ended on those dates are presented below:
1999 1998 1997 ---------------------------- ----------------------------- ----------------------------- Weighted- Weighted- Weighted Average Average -Average Exercise Exercise Exercise Shares Price Shares Price Shares Price ---------- ---------------- ------------ ---------------- ----------- --------------- FIXED OPTIONS Outstanding at beginning of year....... 514,503 $ 9.78 383,490 $ 12.50 276,749 $ 8.30 Granted................................ 141,672 7.03 374,162 11.53 159,374 18.21 Exercised.............................. -- -- (11,482) 7.73 (34,724) 7.24 Canceled............................... (35,058) 9.86 (231,667) 17.21 (17,909) 8.55 ------------ ------------ ------------ ------------- ------------- --------- Outstanding at end of year............. 621,117 $ 9.15 514,503 $ 9.78 383,490 $ 12.50 ============ ============ ============ ============= ============= ========= Options exercisable at December 31, 1999, 1998 and 1997, respectively.... 230,808 148,840 88,926 Weighted-average fair value of options granted during the year...... $ 3.42 $ 4.72 $ 7.52
The following table summarizes information about fixed stock options outstanding at December 31, 1999:
Options Outstanding Options Exercisable ------------------------------------------------- ----------------------------- Weighted- Average Weighted- Weighted- Number Remaining Average Number Average Outstanding Contractual Exercise Exercisable Exercise Range of Exercise Prices at 12/31/99 Life Price At 12/31/99 Price - ----------------------------- -------------- -------------- ------------- -------------- ------------ $5.38 to $8.63.............. 243,870 7.0 $ 7.05 88,882 $ 7.09 $9.13 to $10.50............. 170,660 6.7 $10.20 69,244 $ 10.10 $10.75 ..................... 206,587 7.7 $10.75 72,682 $ 10.75 -------------- -------------- 621,117 7.2 230,808 ============== ==============
NOTE 10. EARNINGS 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, 1999, 1998 and 1997 (in 000s, except per share data):
For the Year Ended December 31, ------------------------------------------ 1999 1998 1997 ------------- ------------- ------------ Net income (loss)................ $2,823 $(1,211) $7,847 ============= ============= ============ Weighted average number of outstanding shares of common stock used in earnings per share......................... 8,475 8,490 8,485 Effect of dilutive securities: Stock options................. 6 -- 129 ------------- ------------- ------------ Weighted average number of outstanding shares of common stock used in earnings per share assuming dilution....... 8,481 8,490 8,614 ============= ============= ============
29 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 11. SEGMENT REPORTING 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; (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, 1999. Asset information by reportable segment is not reported, since MarkWest does not produce such information internally.
Processing and Exploration and Related Services Production Total ----------------- ----------------- -------------- 1999 (in 000s): Revenues.................. $ 104,810 $1,538 $106,348 Gross operating income.... $ 16,419 $ 620 $17,039 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
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, 1999, 1998 and 1997, is as follows:
1999 1998 1997 ------------ ------------- ------------ Revenues: Total segment revenues............. $106,348 $ 63,622 $78,826 Interest income.................... 53 200 661 Other income (expense)............. 2,233 (124) 196 ------------ ------------- ------------ Total consolidated revenues.. $108,634 $ 63,698 $79,683 ============ ============= ============ Gross operating income: Total segment gross operating income $17,039 $ 9,954 $21,883 General and administrative expenses (6,986) (5,319) (6,651) Depreciation and amortization...... (5,070) (4,594) (3,246) Interest expense................... (2,745) (2,095) (826) Interest income.................... 53 200 661 Other income (expense)............. 2,233 (124) 196 Minority interest in net loss of subsidiary....................... -- -- 380 ------------ ------------- ------------ Consolidated income (loss) before taxes............... $ 4,524 $ (1,978) $12,397 ============ ============= ============
30 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 12. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) The following summarizes certain quarterly results of operations (in 000s):
First Second Third Fourth ----- ------ ----- ------ 1999 (1) - ---- Revenue (2)................... $ 22,077 $ 20,458 $ 30,436 $ 35,610 Gross profit (loss) (3)....... 2,524 3,254 2,129 6,295 Net income (loss)............. 111 577 59 2,076 Basic earnings (loss) per share ...................... $ 0.01 $ 0.07 $ 0.01 $ 0.24 Earnings (loss) per share assuming dilution .......... $ 0.01 $ 0.07 $ 0.01 $ 0.24 1998 - ---- Revenue (2)................... $ 20,231 $ 11,010 $ 14,092 $ 18,165 Gross profit (loss) (3)....... 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)
- -------------------------- (1) Includes $2.5 million gain ($1.5 million, or $0.18 per share, after tax) on the sale of the Company's West Memphis terminal in the second quarter of 1999. (2) Excludes interest income. (3) Excludes interest income, 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, 1999, 1998 and 1997, and costs incurred for oil and gas producing activities for the years ended December 31, 1999, 1998 and 1997 (in 000s):
1999 1998 1997 --------- --------- --------- Capitalized costs: Proved properties...................... $11,167 $ 8,001 $5,308 Unproved properties.................... 1,972 1,206 1,462 Equipment and facilities............... 1,379 1,349 1,145 --------- --------- --------- Total..................................... 14,518 10,556 7,915 Less accumulated depreciation, depletion and amortization......... (1,362) (801) (406) ========= ========= ========= Net capitalized costs..................... $13,156 $ 9,755 $7,509 ========= ========= ========= Costs incurred: Acquisition of properties Proved................................. $ 1,503 $ 2,632 $ 180 Unproved............................... 728 12 1,016 Development costs......................... 1,776 559 2,170 Exploration costs......................... 435 284 250 --------- --------- --------- Total costs incurred...................... $ 4,442 $ 3,487 $3,616 ========= ========= =========
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, 1999, 1998 and 1997, are as follows (in 000s):
1999 1998 1997 --------- --------- --------- Revenues from sale of oil and gas: Sales.................................. $1,804 $1,552 $ 918 Other.................................. 182 40 208 --------- --------- --------- Total............................ 1,986 1,592 1,126 Production costs: Transportation and taxes............... (448) (408) (238) Lease operating expense and other...... (918) (823) (797) --------- --------- --------- Total............................... (1,366) (1,231) (1,035) Gross operating income.................... 620 361 91 Depreciation, depletion and amortization.. (561) (431) (204) Income tax benefit........................ 53 27 323 --------- --------- --------- Results of operations..................... $ 112 $ (43) $ 210 ========= ========= =========
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, 1999, 1998 and 1997, with respect to changes in the Company's proved reserves, all of which are in the United States.
1999 1998 1997 --------------------------- ---------------------------- ---------------------------- Natural Gas Oil Natural Gas Oil Natural Gas Oil (Mcf) (bbls) (Mcf) (bbls) (Mcf) (bbls) -------------- --------- -------------- --------- ------------- ----------- Proved developed and undeveloped reserves: Beginning of year........ 26,048,300 -- 23,155,910 6,736 6,231,005 21,748 Revisions of previous estimates............. 1,031,719 -- 1,164,111 (1,289) (548,185) (15,026) Purchase of minerals in place.............. 2,252,853 -- 3,029,036 -- -- -- Extensions and discoveries........... 4,355,359 -- 129,029 14 17,965,809 14 Production............... (968,671) -- (850,041) -- (492,719) -- Sale of minerals in place................. -- -- (579,745) (5,461) -- -- -------------- --------- -------------- --------- ------------- ----------- End of year.............. 32,719,560 -- 26,048,300 -- 23,155,910 6,736 ============== ========= ============== ========= ============= ===========
32 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1999 1998 1997 --------------------------- ---------------------------- ---------------------------- Natural Gas Oil Natural Gas Oil Natural Gas Oil (Mcf) (bbls) (Mcf) (bbls) (Mcf) (bbls) -------------- --------- -------------- --------- ------------- ----------- Proved developed reserves: Beginning of year........ 13,664,760 -- 11,025,140 6,736 6,156,645 21,748 ============== ========= ============== ========= ============= =========== End of year.............. 22,113,900 -- 13,664,760 -- 11,025,140 6,736 ============== ========= ============== ========= ============= ===========
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 net cash flows from its oil and gas properties for the years ended December 31, 1999, 1998 and 1997, is as follows (in 000s):
1999 1998 1997 ------------ ------------ ------------ Future cash inflows....................... $ 75,290 $ 51,055 $ 54,757 Future production costs................... (32,541) (26,886) (26,235) Future development costs.................. (2,970) (3,623) (3,650) Future income tax expense................. (12,982) (7,302) (7,464) ------------ ------------ ------------ Future net cash flows..................... 26,797 13,244 17,408 10% annual discount for estimated timing of cash flows........................... (15,332) (8,271) (9,348) ------------ ------------ ------------ Standardized measure of discounted future net cash flows relating to proved oil and gas reserves................... $ 11,465 $ 4,973 $ 8,060 ============ ============ ============
33 MARKWEST HYDROCARBON, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Principal changes in the Company's estimated discounted future net cash flows for the years ended December 31, 1999, 1998 and 1997, are as follows (in 000s):
1999 1998 1997 ---------- ---------- ---------- January 1....................................... $4,973 $8,060 $2,016 Sales and transfers of oil and gas produced, net of production costs................... (620) (361) (91) Net changes in prices and production costs related to future production.............. 3,332 (3,158) 871 Previously estimated development costs incurred during the period................ 654 355 1,608 Changes in estimated future development costs -- (339) (1,471) Extensions and discoveries................... 3,260 81 6,936 Revisions of previous quantity estimates..... 492 316 (428) Purchases of reserves in place............... 1,432 1,471 -- Sales of reserves in place .................. -- (673) -- Changes in production rates and other ....... (708) (2,116) 2 Accretion of discount........................ 753 1,086 313 Net change in income taxes................... (2,103) 251 (1,696) ---------- ---------- ---------- December 31..................................... $11,465 $4,973 $8,060 ========== ========== ==========
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 18, 2000, 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: A report on Form 8-K was filed on October 25, 1999, announcing the settlement of all outstanding arbitration and litigation between MarkWest and Columbia Gas Transmission Corporation, and announcing the expected expansion of its Kenova NGL extraction plant. (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 1996 Incentive Compensation Plan (filed as Exhibit 10.25). (1) 10.3 1996 Stock Incentive Plan (filed as Exhibit 10.26). (1) 10.4 1996 Non-employee Director Stock Option Plan (filed as Exhibit 10.27). (1) 10.5 Form of Non-Compete Agreement between John M. Fox and MarkWest Hydrocarbon, Inc. (filed as Exhibit 10.28). (1) 10.6 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). 10.7 Second Amended and Restated Credit Agreement, dated as of September 29, 1999, among MarkWest Hydrocarbon, Inc., as the Borrower; and Certain Commercial Lending Institutions as the Lenders; and Bank of America, N.A., as the Administrative Agent and the Syndication Agent for the Lenders (filed as Exhibit 10 to MarkWest Hydrocarbon, Inc.'s Form 10-Q for the three months ended September 30, 1999, 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. 35 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 20, 2000. 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 20, 2000 -------------------------------- John M. Fox President, Chief Executive Officer and Director /s/ Brian T. O'neill March 20, 2000 -------------------------------- Brian T. O'Neill Senior Vice President, Chief Operating Officer and Director /s/ Gerald A. Tywoniuk March 20, 2000 -------------------------------- Gerald A. Tywoniuk Chief Financial Officer and Vice President of Finance (Principal Financial and Accounting Officer) /s/ Arthur J. Denney March 20, 2000 -------------------------------- Arthur J. Denney Director /s/ Barry W. Spector March 20, 2000 -------------------------------- Barry W. Spector Director /s/ Donald D. Wolf March 20, 2000 -------------------------------- Donald D. Wolf Director 36 EX-11 2 EXHIBIT 11 EXHIBIT 11 MARKWEST HYDROCARBON, INC. COMPUTATION OF EARNINGS PER COMMON SHARE (000S, EXCEPT PER SHARE DATA)
FOR THE YEAR ENDED DECEMBER 31, 1999 ------------------------ Net income $ 2,823 Weighted average number of outstanding shares of common stock 8,475 Basic earnings per share $ 0.33 ============ Net income $ 2,823 Weighted average number of outstanding shares of common stock 8,475 Dilutive stock options 6 ------------ 8,481 Earnings per share assuming dilution $ 0.33 ============
EX-21 3 EXHIBIT 21 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 EXHIBIT 23 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 9, 2000 relating to the financial statements, which appears in this Form 10-K. PricewaterhouseCoopers LLP Denver, Colorado March 20, 2000 EX-27 5 EXHIBIT 27
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED BALANCE SHEET AND CONSOLIDATED STATEMENTS OF OPERATIONS OF THE COMPANY'S 1999 FORM 10-K AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 YEAR DEC-31-1999 JAN-01-1999 DEC-31-1999 1,356 0 16,360 0 6,043 25,981 115,100 (22,789) 119,243 14,470 44,035 0 0 85 52,634 119,243 106,348 108,634 76,652 76,652 24,713 0 2,745 4,524 1,701 2,823 0 0 0 2,823 0.33 0.33
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