================================================================================ 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 [ Fee Required ] for the fiscal year ended December 31, 1996 [ ] Transition report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934 [No Fee Required] 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.) 5613 DTC PARKWAY, SUITE 400, ENGLEWOOD, COLORADO 80111 (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: TITLE OF EACH CLASS NAME OF EXCHANGE ON WHICH REGISTERED ------------------- ------------------------------------ Common Stock, $.01 par value Nasdaq National Market 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 --- --- The aggregate market value of voting common stock held by non-affiliates of the registrant on March 17, 1997 was $48,695,252. 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 June 6, 1997. Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] ================================================================================ MARKWEST HYDROCARBON, INC. FORM 10-K TABLE OF CONTENTS Page ---- PART I Items 1. and 2. Business and Properties........................... 3 Item 3. Legal Proceedings......................................... 14 Item 4. Submission of Matters to a Vote of Security Holders....... 14 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters............................................ 15 Item 6. Selected Financial Data................................... 16 Item 7. Management's Discussions and Analysis of Financial Condition and Results of Operation............................. 17 Item 8. Financial Statements and Supplementary Data............... 22 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............................ 40 PART III Item 10. Directors and Executive Officers of the Registrant....... 40 Item 11. Executive Compensation................................... 40 Item 12. Security Ownership of Certain Beneficial Owners and Management..................................................... 40 Item 13. Certain Relationships and Related Transactions........... 40 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K....................................................... 40 2 PART I ITEMS 1. AND 2. BUSINESS AND PROPERTIES GENERAL . MarkWest Hydrocarbon, Inc. (the "Company" or "MarkWest") is engaged in natural gas processing and related services. The Company, which has grown substantially since its founding in 1988, is the largest processor of natural gas in Appalachia, and recently established a venture to provide natural gas processing services in western Michigan. The independent gas processing industry has grown rapidly in the last 10 years, and the Company believes there will be substantial opportunities to grow its gas processing operations within these existing core regions and in new markets. The Company provides compression, gathering, treatment, and natural gas liquids (NGL) extraction services to natural gas producers and pipeline companies and fractionates NGLs into marketable products for sale to third parties. The Company also purchases, stores and markets natural gas and NGLs and has begun to conduct strategic exploration for new natural gas sources for its processing activities. For the year ended December 31, 1996, MarkWest produced approximately 95 million gallons of NGLs and marketed approximately 137 million gallons of NGLs. The Company's processing and marketing operations are concentrated in two core areas that are significant gas-producing basins: the southern Appalachian region of eastern Kentucky, southern West Virginia, and southern Ohio (the "Appalachian Core Area"), and western Michigan (the "Michigan Core Area"). At the Company's processing plants, natural gas is treated to remove contaminants, and NGLs are extracted and fractionated into propane, normal butane, isobutane and natural gasoline. The Company then markets the fractionated NGLs to refiners, petrochemical companies, gasoline blenders, multistate and independent propane dealers, and propane resellers. In addition to processing and NGL marketing, the Company engages in terminalling and storage of NGLs in a number of NGL storage complexes in the central and eastern United States and operates propane terminals in Arkansas and Tennessee. During 1996, the Company took several key steps to expand its operations. In January 1996, the Company commissioned a new natural gas liquids extraction plant in Wayne County, West Virginia. In May 1996, the Company established West Shore Processing Company, LLC ("West Shore"), a venture in western Michigan, which the Company will develop as the Michigan Core Area. The Company has identified opportunities, and has entered into agreements, to expand its gas gathering operations and to commence gas processing operations in the Michigan Core Area in the near future. See "Natural Gas Processing and Related Services." The Company's principal offices are located at 5613 DTC Parkway, Suite 400, Englewood, Colorado 80111, and its telephone number is (303) 290-8700. The Company was incorporated in Delaware in 1996. NATURAL GAS PROCESSING AND RELATED SERVICES The Company's processing operations are located in its Appalachian Core Area consisting of eastern Kentucky, southern West Virginia, and southern Ohio, and its Michigan Core Area consisting of the area of western Michigan north of Grand Rapids and south of Traverse City. The Company's operations in Appalachia date from the Company's founding in 1988. At present, the Company is the largest processor of natural gas in Appalachia based on the volume of natural gas processed at its owned facilities, including those it leases to third parties. The Company began development of the Michigan Core Area in June 1996. 3 APPALACHIAN CORE AREA The Company's operations in Appalachia consist of two extraction facilities, a fractionation plant, an NGL pipeline, rail terminals and related processing assets. Since 1988, the volume of natural gas processed by the Company in the Appalachian Core Area has grown to approximately 170 MMcf/D, and the Company's NGL production has grown to approximately 275 MGal/D. The Company believes that 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. In addition to Appalachia, the TET pipeline serves the upper midwestern and eastern United States, and the Dixie pipeline serves the southeast. Because the areas directly served by these two pipelines are experiencing significant population growth, the demand for NGL products exceeds the capacity of these two lines. The demand for propane from the TET and Dixie pipelines is such that the pipelines allocate supply to purchasers during peak wintertime periods, thereby limiting the available supply to Appalachia. There are few sources of propane to the Appalachian Core Area other than the Company's facilities, the TET and Dixie pipelines, and propane shipped by rail cars from other producing areas. In addition, the Appalachian mountain range limits access to the Dixie pipeline by distributors in the Appalachian Core Area. These factors enable producers in Appalachia (principally MarkWest, Ashland Oil Company and CNG Transmission Corporation) to price their products (particularly propane) at a premium to Gulf Coast spot prices during times of supply shortages from other sources, especially during winter high demand periods. The underground storage caverns at the Company's Siloam location allow the Company to defer sales of NGLs to the winter months when peak demand periods often lead to higher product prices and provide local consumers with needed wintertime supplies. The Company also believes that there are significant growth opportunities in this region both from the improvement of gas processing efficiencies for existing gas production in the area and the Company's capacity to process natural gas streams from areas that are not currently processed. NGL Extraction. The Company currently owns two NGL extraction plants in Appalachia, one which it operates and one which it leases to Columbia Gas Transmission Company ("Columbia Gas"). Extraction plants remove NGLs, as well as water vapor, solids and other contaminants, such as hydrogen sulfide or carbon dioxide, contained in the natural gas stream. The Company provides NGL extraction services under a fee-based arrangement. Kenova Plant. The Company began construction of its Kenova natural gas liquids extraction plant, located in Wayne County, West Virginia, in 1995. The Kenova plant was commissioned in January 1996 and replaced a 1958 extraction facility owned and operated by Columbia Gas. Because the Company owns and operates this new facility, which is situated on a main gathering line of Columbia Gas, the Company will generate fee revenues related to the processing operations. In addition, the Company believes that this new facility will generate greater NGL recovery from natural gas, reduce downtime for maintenance, and significantly reduce fuel costs compared to the replaced facility. Construction and related costs for development of the Kenova plant were approximately $12.2 million. To date, substantially all of Kenova's processing throughput has been obtained from Columbia Gas. Substantially all of the Kenova plant's extracted NGLs are transported via the Company's 38.5 mile high pressure pipeline to its Siloam fractionation facility located in South Shore, Kentucky, for separation into marketable NGL products. Boldman Plant. The Company constructed the Boldman natural gas liquids extraction plant, located in Pike County, Kentucky, in 1991. Construction and related costs for development of the Boldman plant were approximately $4.0 million. The Boldman plant is currently leased to, and operated by, Columbia Gas. Under such lease, the Company receives a monthly rental fee ranging from $40,000 to $47,000. Columbia Gas also has an option to purchase the Boldman plant at set prices during the term and upon expiration of the lease. Columbia Gas has dedicated all NGLs recovered at the Boldman plant to the Company's Siloam facility for fractionation under a contract which runs through December 31, 2003. This production is transported via tanker trucks from the Boldman plant to the Siloam plant for processing. 4 NGL Pipeline. The Company owns a 38.5 mile, high pressure steel pipeline that connects its Kenova processing plant to the Company's Siloam fractionation facility. The pipeline currently delivers approximately 70 million gallons per year to the Siloam facility from the Kenova processing plant. Because this pipeline was originally designed to handle a high pressure ethane-rich stream, it has the capacity to handle almost twice as much product if it becomes available. Fractionation. The Company's fractionation services in the Appalachian Core Area are performed at its Siloam fractionation plant located in South Shore, Kentucky. At this facility, extracted NGLs are subjected to various processes that cause the natural gas to separate, or fractionate, into separate NGL products, including propane, isobutane, normal butane and natural gasoline. The Siloam facility is one of only two fractionation plants in the Appalachian Core Area producing over 6,500 barrels, or 275,000 gallons, per day of NGLs. Substantially all of the Company's fractionation services in its Appalachian Core Area are provided under keep-whole contracts with Columbia Gas. The Company acquired the Siloam plant in April 1988 from Columbia Gas for $3.5 million. During 1989, the Company began an approximately $11.0 million expansion program at the Siloam plant. The expansion program, among other enhancements, included the construction of additional storage facilities, improvements to existing electrical and control systems and the addition of loading facilities. The expansion was fully operational in early 1991. Approximately 77% of the fractionation throughput at the Siloam plant comes from the production of the Company's Kenova and Boldman plants. The Company also makes purchases of NGLs from third-party processors and of additional production from Columbia Gas. The Company's most significant purchase contract for NGLs is with Columbia Gas. In addition to the approximately 9.0 MMGal per year of Columbia Gas NGL production from the Boldman plant, Columbia Gas dedicates approximately 17.0 MMGal per year from its Cobb, West Virginia extraction plant. Pursuant to the Columbia Gas purchase agreements, the Company is committed to purchase substantially all of the NGLs produced at Columbia Gas' own processing plants, as well as those produced by the Company for Columbia Gas. Under these contracts, the Company is required to compensate Columbia Gas for the BTU energy equivalent of NGLs and fuel removed from the natural gas as a result of processing. In 1996, the Company's cost for purchases under these contracts was $23 million, and such purchases represented 95% of all NGLs fractionated by the Company. MICHIGAN CORE AREA The Company was attracted to the Michigan Core Area because of the potential for providing gathering and processing services in the area. Substantially all of the natural gas in the Michigan Core Area is sour and, therefore, has limited outlets for processing. West Shore was formed in May 1996 and is governed by an operating agreement between MarkWest Michigan, Inc. and Michigan Energy Company ("MEC"). West Shore is a venture dedicated to natural gas gathering, treatment, processing and NGL marketing in Manistee, Mason and Oceana Counties in Michigan. As a result of availability of large shut-in sour gas wells and the expected increase in drilling by producers who previously had no outlet for sour gas production in the area, the Company entered into several related agreements in May 1996 providing for the development of gathering, treatment and processing facilities in western Michigan. Through West Shore, the Company expects to be able to gather and process this sour gas. The most significant assets of West Shore currently include the Basin Pipeline, a 31-mile sour gas pipeline which is situated in Manistee and Mason Counties, rights to obtain a sour gas treatment plant located in Manistee County, Michigan, and various agreements that dedicate natural gas production to West Shore for processing. Until completion of the second phase of the Michigan Project, West Shore's revenues will be derived from fees generated by gathering of natural gas on the Basin Pipeline and by treatment of sour gas. Following completion of the second phase, revenues will be derived from fees generated by gathering, treatment and extraction and fractionation of NGLs. 5 The Michigan Project is completing its first phase of development, which includes construction of a two-mile pipeline from one of West Shore's main gathering locations to a treatment plant owned and operated by Shell Offshore, Inc. ("Shell") in Manistee County. The purpose of this pipeline is to deliver sour gas to Shell for treatment. The first phase also includes the construction of a 30-mile pipeline that will connect the Slocum natural gas well owned by MPC in Oceana County to the Basin Pipeline. Initially West Shore will operate this pipeline for Michigan Production Company, L.L.C. ("MPC") as an individual well pipeline. Following approval from the Michigan Public Service Commission, Basin will acquire the pipeline from MPC and will operate it to gather gas from additional wells in Mason and Oceana counties. The Slocum well has estimated reserves of approximately 13 Bcf, and estimated initial well deliverabilities of approximately 8 MMcf/D. The first phase of the Michigan Project will cost approximately $11 million. The second phase of the Michigan Project includes construction of a two-mile residue return line from the Shell treatment plant to the natural gas transmission line of Michigan Consolidated Gas Company ("MichCon") and construction of approximately 18 miles of pipeline to connect natural gas wells in southern Oceana County, including the Claybanks wells owned by MPC, with estimated reserves of approximately 7.5 Bcf and estimated initial well deliverabilities of approximately 8 MMcf/D, to the Basin Pipeline. The second phase will also include the construction of an NGL extraction and fractionation facility at the site of the Shell treatment plant. The facility will be owned by West Shore and operated by Shell. The Company currently expects that the second phase of the Michigan Project will be completed by the end of the fourth quarter of 1997. The second phase of the Michigan Project is expected to cost approximately $9 million. When the first two phases of the Michigan Project are complete, the Company will own a 60% interest in West Shore. As of December 31, 1996, the Company had made contributions of approximately $10.4 million and owns a 47% interest. Upon completion of the first two phases of development, West Shore's treating and processing operations are expected to have 30 MMcf/D of capacity and approximately 25 MMcf/D of dedicated production from currently drilled and proven wells. With a current pipeline capacity of 35 MMcf/D and deliverabilities of individual wells commonly exceeding 5 MMcf/D, the Company expects that demand at West Shore could exceed capacity. As a result, the Company is already planning to expand West Shore to increase capacity in the second phase of the Michigan Project. There can be no assurance, however, that demand for West Shore's services will reach the levels anticipated by the Company. Availability of Natural Gas Supply. West Shore has exclusive gathering, treatment and processing agreements with Michigan Production Company ("MPC") covering the natural gas production from all wells and leases presently owned by MPC within Manistee, Mason and Oceana Counties, Michigan. In addition, West Shore has a gathering, treating and processing agreement with Oceana Acquisition Company ("Oceana") covering the production from the initial phase of Oceana's drilling program in Oceana County, Michigan. West Shore also is negotiating an agreement with Longwood Exploration Company ("Longwood") that may result in the dedication of its natural gas production to the pipeline, treatment and processing facilities of West Shore. The Company believes that the expansion of the Basin Pipeline southward will provide an outlet for sour gas production in the area and may stimulate new drilling activity in the area. Both MPC and Longwood are considering initiating drilling programs in the area, to begin by early 1997. Production from the MPC program has been dedicated to the Basin Pipeline, and West Shore is negotiating with Longwood for dedication of its production to the Basin Pipeline. MarkWest Resources, Inc. ("Resources"), a wholly owned subsidiary of the Company, has agreed to purchase a 17.5% working interest in the Longwood drilling program. MarkWest also has had discussions with other exploration companies that are evaluating possible exploration and production activities in the corridor to be serviced by the expanded Basin Pipeline. MarkWest currently is evaluating various drilling programs and expects to participate actively in drilling wells in the area. 6 The natural gas streams to be dedicated to West Shore 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. 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. With the sour gas pipeline, treatment and processing facilities and capacity to be provided by West Shore, the Company believes there could 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. Shell Treatment and Processing Agreement. In addition to the establishment of West Shore, the Michigan Project includes a number of related agreements. To provide treatment for natural gas dedicated to West Shore, West Shore has entered into a gas treatment and processing agreement with Shell. Currently, the agreement provides West Shore with 30 MMcf/D of gas treatment capacity at Shell's facility in Manistee County, Michigan. The agreement also permits West Shore to cause the expansion of Shell's treatment facilities. In addition, the agreement grants West Shore the right to construct and install an NGL processing plant at the site of Shell's treatment plant. Following completion of the new processing plant, Shell will act as contract operator for West Shore. GAS PROCESSING CONTRACTS AND NATURAL GAS SUPPLY The Company historically has processed natural gas under two types of arrangements: keep-whole and fee-based processing. While the Company has been heavily dependent upon keep-whole contracts in the past, it intends to pursue fee-based processing contracts in the future to reduce the fluctuations in margins inherent in processing natural gas under keep-whole arrangements. Keep-Whole Contracts. Under keep-whole contracts, the principal cost is the reimbursement to the natural gas producers for the BTUs extracted from the gas stream in the form of liquids or consumed as fuel during processing. In such cases, the Company creates operating margins by maximizing the value of the NGLs extracted from the natural gas stream and minimizing the cost of replacement of BTUs. While the Company maintains programs to minimize the cost to deliver the replacement of fuel and shrinkage 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. Approximately 59% of the Company's total revenue during 1996 resulted from keep- whole contracts. Fee Contracts. The Company has entered into a fee-based contract with Columbia Gas, which expires December 31, 2010, pursuant to which Columbia Gas has agreed to use its best efforts to deliver a minimum of 115 MMcf/D of natural gas to the Company's Kenova processing plant, and the Company has agreed to process all natural gas made available by Columbia Gas to the Company at the Kenova plant. In 1996, deliveries by Columbia Gas to the Kenova plant under this contract represented approximately 95% of all throughput processed by the Company. Under the agreement, Columbia Gas pays the Company a fee per MMbtu of processed natural gas. The terms of the contract provide for automatic two-year extensions after 2010, unless either party gives notice to terminate the contract at least one year in advance of an expiration date. In its Michigan Core Area, West Shore has entered into a fee-based contract with MPC, which expires December 2016, pursuant to which MPC has agreed to use its best efforts to deliver all of its natural gas to West Shore's pipeline and treating facilities. Under the agreement, MPC pays West Shore a fee per MMbtu of transported and treated natural gas. Approximately 5% of the Company's total revenues during 1996 resulted from fee-based contracts. Percent-of-Proceeds Contracts. Under percent-of-proceeds contracts, the Company retains a portion of NGLs and/or natural gas 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 and natural gas sold. While historically the Company has not entered into percent-of- proceeds contracts, 7 recently the Company offered to process natural gas for certain suppliers in the Appalachian Core Area under percent-of-proceeds arrangements. The Company and Columbia Gas are in the process of negotiating fee and/or percent-of-proceeds arrangements whereby the Company will process natural gas directly for third-party shippers who utilize Columbia Gas's pipeline and distribution system. In addition, part of the fee structure for transporting and treating natural gas in the Michigan Core Area includes retaining a portion of extracted NGLs. SALES AND MARKETING The Company attempts to maximize the value of its NGL output by marketing 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 truck and tank car fleet, as well as its own terminals and storage facilities, to enhance supply reliability to its customers. All of these efforts have allowed the Company to maintain premium pricing of its NGL products compared to Gulf Coast spot prices. Substantially all of the Company's revenue is derived from sales of NGLs, particularly propane. Revenues from NGLs represented 91%, 98% and 88% of total revenues, excluding gains on sale of property, in each of 1996, 1995 and 1994, respectively. The Company markets and sells NGLs to numerous customers, including refiners, petrochemical companies, gasoline blenders, multistate and independent propane distributors and propane resellers. 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. EXPLORATION AND PRODUCTION The Company maintains a strategic gas exploration effort intended to permit the Company to gain a foothold position in production areas that have strong potential to create demand for its processing services. The Company, through Resources, currently owns interests in several exploration and production assets. Such assets include the following: . A 49% undivided interest in two separate exploration and production projects in La Plata County, Colorado, situated on the Fruitland Formation coal seam. One project currently contains nine coal seam wells that produce approximately 2,300 Mcf/D of natural gas. It is estimated that full development of these two projects will cost the Company approximately $3.2 million through the end of 1997. . A 5.4% working interest in a 66-well drilling program operated by Conley Smith, Denver, Colorado. The majority of these well sites are in Oklahoma, Kansas, Nevada and Texas. MarkWest believes it may have a future opportunity to provide its processing expertise to Conley Smith in the areas with successful drilling sites. There can be no assurance, however, that Conley Smith will use the Company's processing services. . A 25% working interest in a 31,000-acre project to be developed in the Piceance Basin of Colorado. The project includes both the exploration for conventional natural gas and the development of the Cameo Coal Formation utilizing tax credit qualified existing well bores. While there can be no assurance that these projects will generate substantial natural gas volumes, MarkWest believes that this area could generate increased demand for processing services. . A 17.5% working interest in the drilling program of the Niagran Reef Trend in the Michigan Core Area. Longwood intends to conduct a 25-square-mile three- dimensional seismic survey in the prospective area and thereafter acquire acreage and conduct drilling activities. 8 PROPERTIES The following table provides information concerning the Company's principal gas processing plants and gathering facilities. YEAR ACQUIRED GAS NGL PRODUCTION OR PLACED THROUGHPOUT THROUGHPUT THROUGHPUT INTO SERVICE CAPACITY (Mcf/D)/a, b/ (Gal/YEAR)/b/ --------------------------------------------------------------------- PROCESSING PLANTS Siloam Fractionation Plant, South Shore, KY (1)..................... 1988 360,000 Gal/D NA 94,909,000 Boldman Extraction Plant, Pike County, KY (2)..................... 1991 70,000 Mcf/D 55,000 8,461,000 Kenova Extraction Plant, Wayne County, WV (3).................... 1996 120,000 Mcf/D 115,000 65,443,000 PIPELINES 38.5-mile Kenova--Siloam NGL pipeline Wayne County, WV to South Shore, KY (4)..................... 1988 350,000 Gal/D NA 65,443,000 31-mile sour gas gathering line Manistee County, MI (3)................. 1996 35,000 Mcf/D 5,500 NA YEAR ACQUIRED STORAGE OR PLACED CAPACITY ANNUAL SALES INTO SERVICE (Gal) (Gal/YEAR)/b/ ------------------------------------------------ TERMINAL AND STORAGE Siloam Fractionation Storage South Shore, KY (1).................................... 1988 14,000,000 94,909,000 Terminal and Storage West Memphis, AR (5)................................... 1992 2,500,000 33,798,000 Terminal and Storage Church Hill, TN (6).................................... 1995 240,000 4,053,000 - ------------ /a/ Mcf/D = cubic feet per day /b/ For the year ended December 31, 1996 (1) At the Siloam Fractionation Plant facility, extracted NGLs are subjected to various processes that cause the natural gas to separate, or fractionate, into separate NGL products, including propane, isobutane, normal butane and natural gasoline. The Siloam plant, situated on approximately 290 Company- owned acres, also has over 14.0 million gallons of on-site product storage, including an 8.4-million-gallon propane underground storage cavern, a 3.1- million-gallon butane underground storage cavern, and approximately 3.0 million gallons of above-ground storage tanks. The Siloam plant is served by the following modern loading and unloading facilities: four automated truck loading docks for propane/butane; two automated truck unloading docks for mixed feedstock; one automated bottom-loading dock for natural gasoline; truck scales; a rail siding capable of holding over 20 railcars and simultaneously loading or unloading eight cars; and barge facilities for the loading of natural gasoline and butanes. 9 (2) The Boldman plant is a refrigeration plant that extracts NGLs by cooling natural gas down to minus 20 degrees Fahrenheit. The plant includes two 60,000-gallon product storage tanks and truck-loading facilities. The Boldman plant is currently leased to, and operated by, Columbia Gas. (3) See "Natural Gas Processing and Related Services". (4) The Company owns a 38.5-mile, high-pressure steel pipeline that connects its Kenova processing plant to the Company's Siloam fractionation facility. Because this liquids pipeline was originally designed to handle a high- pressure ethane-rich stream, it has the capacity to handle almost twice as much product if it becomes available. (5) At the West Memphis terminal (a seven-acre propane terminal and storage facility), the Company maintains 45 pressurized storage tanks that have a storage capacity of just over 2.5 million gallons of NGLs. The terminal has an automated loading facility with two loading docks for propane, operating 24 hours per day, seven days per week. The West Memphis terminal is capable of serving railcar and trucking transportation. An adjoining Union Pacific rail siding holds up to 17 railcars and has 6 loading/unloading stations. The terminal is located approximately 1/4 mile from the Mississippi River and is secured by a long-term lease held by the Company. (6) The Company leases and operates a propane terminal in Church Hill, Tennessee, which principally receives product by rail and redelivers the product to dealers and resellers by truck. The Church Hill terminal has 240,000 gallons of pressurized storage, an automated truck loading station and a rail siding that can hold four cars and has two unloading stations. Executive Offices. MarkWest occupies approximately 12,000 square feet of space at its executive offices in Denver, Colorado under a lease expiring in March 1997. While the Company will require additional office space as its business expands, the Company believes that its existing facilities are adequate to meet its needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed. COMPETITION The Company faces intense competition in obtaining natural gas supplies for its gathering and processing operations, in obtaining processed NGLs for fractionation and in marketing its products and services. The Company's principal competitors include major integrated oil and gas companies, such as Ashland and Amoco Oil Co.; major interstate pipeline companies, such as CNG Transmission Corporation; NGL processing companies, such as Natural Gas Clearinghouse; and national and local gas gatherers, brokers, marketers and distributors of varying sizes, financial resources and experience. Many of the Company's competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than those of the Company. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. The Company competes against other companies in its gas processing business both for supplies of natural gas and for customers to which it sells its products. Competition for natural gas supplies is based primarily on location of gas gathering facilities and gas processing plants, operating efficiency and reliability, and ability to obtain a satisfactory price for products recovered. Competition for customers is based primarily on price, delivery capabilities, and maintenance of quality customer relationships. The Company's fractionation business competes against other fractionation facilities that serve local markets. Competitive factors affecting the Company's fractionation business include proximity to industry marketing centers and efficiency and reliability of service. In marketing its products and services, the Company has numerous competitors, including interstate pipelines and their marketing affiliates, major producers, and local and national gatherers, brokers, and marketers of widely varying sizes, financial resources and experience. Marketing competition is primarily based upon reliability, transportation, flexibility and price. OPERATIONAL RISKS AND INSURANCE The Company's operations are subject to the usual hazards incident to the exploration for and production, transmission, processing and storage of natural gas and NGLs, such as explosions, product spills, leaks, 10 emissions and fires. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage, and may result in curtailment or suspension of operations at the affected facility. The Company maintains general public liability, property and business interruption insurance in amounts that it considers to be adequate for such risks. Such insurance is subject to deductibles that the Company considers reasonable and not excessive. Consistent with insurance coverage generally available to the NGL industry, the Company's insurance policies do not provide coverage for losses or liabilities related to pollution or other environmental damage, except for sudden and accidental occurrences. 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. GOVERNMENT REGULATION Certain of the Company's pipeline activities and facilities are involved in the intrastate or interstate transportation of natural gas and NGLs and are subject to state and/or federal regulation. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 ("NGA"), the Natural Gas Policy Act of 1978 ("NGPA"), and the regulations promulgated thereunder by the Federal Energy Regulatory Commission ("FERC"). In the past, the federal government regulated the prices at which oil and gas could be sold, as well as certain terms of service. However, the deregulation of natural gas sales pricing began under terms of the NGPA and was completed in January 1993 pursuant to the Natural Gas Wellhead Decontrol Act of 1989 (the "Decontrol Act"). Thus, all sales by the Company of NGLs and natural gas currently can be made at uncontrolled market prices. There can be no assurance, however, that Congress will not reenact price controls in the future which could apply to, or substantially affect, these sales activities. FERC's jurisdiction over the interstate transportation of natural gas was not removed or limited by the NGPA or the Decontrol Act. FERC also retains jurisdiction over the interstate transportation of liquid hydrocarbons, such as NGLs and product streams derived therefrom. The processing of natural gas for the removal of liquids currently is not viewed by the FERC as an activity subject to its jurisdiction. If a processing plant's primary function is extraction of NGLs and not natural gas transportation, the FERC has traditionally maintained that the plant is not a facility for transportation or sale for resale of natural gas in interstate commerce and therefore is not subject to jurisdiction under the Natural Gas Act. Although the FERC has not been requested to and has made no specific declaration as to the jurisdictional status of the Company's gas processing operations or facilities, the Company believes that because its gas processing plants are primarily involved in removing NGLs, their processing activities are exempt from FERC jurisdiction. Notwithstanding the foregoing, Columbia Gas is seeking abandonment approval of the processing plant that was replaced by the Company's Kenova extraction plant. The previous Columbia Gas processing plant was considered by FERC to be transportation-related and was included in Columbia Gas's certificated facilities. Because of this prior regulatory classification when owned by Columbia Gas, the Company has specifically requested a ruling from FERC confirming that the new Kenova extraction plant is exempt from FERC jurisdiction. While there can be no assurance that FERC will issue such a ruling, the Company believes, based upon opinions of legal counsel to the Company, that such a ruling will be forthcoming. In the event FERC does not confirm such exemption, the rates charged by the Company for processing services at the Kenova plant would be subject to regulation by FERC, and such rates and regulation could affect the volume of natural gas delivered to the facility by producers. If imposed, such regulation could have a material adverse effect on the Company's results of operations. As part of the Michigan Project, the Company will own and operate pipeline gathering facilities in conjunction with its processing plants. Under the NGA, facilities which have as their "primary function" 11 the performance of gathering activities and are not owned by interstate gas pipeline companies are wholly exempt from FERC jurisdiction. Interstate transmission facilities, on the other hand, are subject to FERC jurisdiction. The FERC distinguishes between these two types of activities on a fact-specific basis, which may make it difficult to state with certainty the status of the Company's pipeline gathering facilities. Although the FERC has not been requested to or issued any order or opinion declaring the Company's facilities as gathering rather than transmission facilities, based on opinion of legal counsel, management believes these systems are NGA-exempt gathering facilities. In addition, state and local regulatory authorities oversee intrastate gathering and other natural gas pipeline operations. Because the Company's NGL pipeline facilities do not transport liquids in continuous flow in interstate commerce, they are not subject to FERC regulation under the Interstate Commerce Act. However, the design, construction, operation, and maintenance of the Company's NGL and natural gas pipeline facilities are subject to the safety regulations established by the Secretary of the Department of Transportation pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended ("1968 Act"), or by state agency regulations which meet or exceed the requirements of the 1968 Act. The Company's natural gas exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, meeting bonding requirements in order to drill or operate wells and regulating the location of wells, the methods of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with such operations. Production operations are also subject to various conservation laws and regulations. These typically include the regulation of the size of drilling and spacing or proration units and the density of wells which may be drilled therein and the unitization or pooling of oil and gas properties. Whether the state has forced pooling, or integration of smaller tracts to form a tract large enough to conduct drilling operations, or relies only on voluntary pooling can affect the ease with which a property can be developed. State conservation laws also typically establish maximum rates of production of natural gas, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production and the handling of nonhydrocarbon gases, such as carbon dioxide and hydrogen sulfide. The effect of these regulations may limit the amount of oil and gas available to the Company or which the Company can produce from its wells. They also substantially affect the cost and profitability of conducting natural gas exploration and production activities. Inasmuch as such laws and regulations are frequently expanded, amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with these production-related regulations. Commencing in April 1992, the FERC issued a series of orders, generally referred to collectively as Order No. 636, which, among other things, require interstate pipelines such as Columbia Gas to "restructure" to provide transportation services separate or "unbundled" from the interstate pipelines sales of gas. Order No. 636 also requires interstate pipelines to provide open-access transportation on a basis that is equal for all shippers and all supplies of natural gas. This order was implemented through pipeline-by-pipeline restructuring proceedings. In many instances, the result has been to substantially reduce or bring to an end interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. On July 16, 1996, the United States Court of Appeals for the District of Columbia Circuit upheld the validity of most of the provisions and features of Order No. 636. However, in many instances, appeals remain outstanding in the individual pipeline restructuring proceedings, so the Company cannot predict the final outcome of these proceedings. Order No. 636 is intended to foster increased competition within all phases of the natural gas industry. It remains unclear what impact, if any, increased competition within the natural gas industry under Order No. 636 will have on the Company or its various lines of business. Additionally, the FERC has issued a number of other orders which are intended to supplement various facets of its open access program, all of which will continue to affect how and by whom natural gas production and associated NGLs will be transported and sold in the marketplace. In its current form, FERC's open access initiatives could provide the Company with additional access to gas supplies and markets and could assist the Company and its customers by mandating more fairly applied service rates, terms and conditions. On the other hand, it could also subject the Company and entities with 12 which it does business to more restrictive pipeline imbalance tolerances, more complex operations and greater monetary penalties for violation of the pipelines tolerances and other tariff provisions. The Company does not believe, however, that it will be affected by any action taken with respect to Order No. 636 materially differently than any other producers, gatherers, processors or marketers with which it competes. ENVIRONMENTAL MATTERS The Company is subject to environmental risks normally incident to the operation and construction of gathering lines, pipelines, plants and other facilities for gathering, processing, treatment, storing and transporting natural gas and other products including, but not limited to, uncontrollable flows of natural gas, fluids and other substances into the environment, explosions, fires, pollution, and other environmental and safety risks. The following is a discussion of certain environmental and safety concerns related to the Company. It is not intended to constitute a complete discussion of the various federal, state and local statutes, rules, regulations, or orders to which the Company's operations may be subject. For example, the Company, without regard to fault, could incur liability under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (also known as the "Superfund" law), or state counterparts, in connection with the disposal or other releases of hazardous substances, including sour gas, and for natural resource damages. Further, the recent trend in environmental legislation and regulations is toward stricter standards, and this will likely continue in the future. The Company's activities in connection with the operation and construction of gathering lines, pipelines, plants, injection wells, storage caverns, and other facilities for gathering, processing, treatment, storing, and transporting natural gas and other products are subject to environmental and safety regulation by federal and state authorities, including, without limitation, the state environmental agencies and the federal Environmental Protection Agency ("EPA"), which can increase the costs of designing, installing and operating such facilities. In most instances, the regulatory requirements relate to the discharge of substances into the environment and include measures to control water and air pollution. Environmental laws and regulations may require the acquisition of a permit or other authorization before certain activities may be conducted by the Company. These laws also include fines and penalties for non-compliance. Further, these laws and regulations may limit or prohibit activities on certain lands lying within wilderness areas, wetlands, areas providing habitat for certain species or other protected areas. The Company is also subject to other federal, state, and local laws covering the handling, storage or discharge of materials used by the Company, or otherwise relating to protection of the environment, safety and health. The Company believes that it is in material compliance with all applicable environmental laws and regulations. EMPLOYEES As of December 31, 1996, the Company had 84 employees. Eighteen 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 recently negotiated a new collective bargaining agreement with this Union that is effective May 1, 1996, and expires on April 30, 2000. The agreement covers only hourly, nonsupervisory employees. The Company considers labor relations to be satisfactory at this time. 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 and Exchange Act of 1933 and Section 21E of the Securities and Exchange Act of 1934. All forward 13 looking statements involve risks and uncertainties. The forward looking statements in this document are intended to be subject to the safe harbor protection provided by Sections 27A and 21E. Factors that most typically impact the Company's operating results and financial condition include (i) changes in general economic conditions in regions in which the Company's products are located, (ii) the availability and prices of NGLs and competing commodities, (iii) the availability of raw natural gas supply, (iv) the ability of the Company to negotiate favorable marketing agreements, (v) the risks that natural gas exploration and production activities will not be successful, (vi) the Company's dependence on certain significant customers, (vii) competition from other NGL processors, including major oil and gas companies, and (viii) the Company's ability to identify and consummate acquisitions complementary to its business. For discussions identifying other important factors that could cause actual results to differ materially from those anticipated in the forward looking statements, see the Company's Securities and Exchange Commission filings; and "Management's Discussion and Analysis of Financial Conditions and Results of Operations" of this Form 10-K. ITEM 3. LEGAL PROCEEDINGS The Company is not currently a party to any legal proceedings, and is not aware of any threatened litigation, the adverse outcome of which, individually or in the aggregate, would have a material adverse effect on the Company's financial condition 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, 1996. 14 PART II ITEM 5. MARKET FOR THE REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER MATTERS As of January 29, 1997, there were 8,485,000 shares of Common Stock outstanding held by 410 holders of record. The Common Stock is traded on the Nasdaq Exchange under the symbol "MWHX". The following table sets forth quarterly high and low closing sales prices as reported by the Nasdaq National Market for the periods indicated. HIGH LOW ------- ------- 1996 Fourth Quarter................... 15 1/2 10 1/4 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, any contractual restrictions, restrictions imposed by law and other factors deemed relevant by the Company's Board of Directors. 15 ITEM 6. SELECTED FINANCIAL DATA The selected consolidated statement of operations and balance sheet data for the years ended December 31, 1996, 1995 and 1994 and as of December 31, 1996 and 1995 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 for below for the years ended December 31, 1993 and 1992 and as of December 31, 1993 and 1992 have been derived from audited financial statements not included in this Form 10-K. The selected consolidated financial information set forth below should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Company's Consolidated Financial Statements and related notes thereto included elsewhere in this Form 10-K. Year Ended December 31, 1996 1995 1994 1993 1992 ---- ---- ---- ---- ---- (in thousands, except per share and operating data) STATEMENT OF OPERATIONS: Revenues................................ $ 71,952 $ 48,226 $ 52,963 $ 55,871 $ 82,977 Income (loss) before taxes, extraordinary item and cumulative effect of change in accounting......... 14,760 7,824 5,120 540 5,449 Income tax provision Arising from reorganization............ 3,745 -- -- -- -- Subsequent to reorganization........... 3,246 -- -- -- -- Income before extraordinary item and cumulative effect of change in accounting............................. 7,769 7,824 5,120 540 5,449 Extraordinary loss...................... -- (1,750) - -- -- Cumulative effect of change in accounting............................. -- -- -- -- 877 Net income.............................. 7,769 6,074 5,120 540 6,326 Pro forma information (1): Historical income before extraordinary item................................... 14,760 7,824 5,120 540 5,449 Pro forma provision for income taxes.... 5,609 2,937 1,424 228 2,060 Pro forma net income.................... 9,151 4,887 3,696 312 3,389 Pro forma earnings per share of common.. stock (2).............................. 1.16 .85 Pro forma weighted average shares outstanding(2)......................... 7,908 5,725 BALANCE SHEET DATA: Total assets............................ $ 78,254 $ 46,896 $ 35,913 $ 40,668 $ 41,092 Long-term debt.......................... 11,257 17,500 9,887 16,486 11,750 Partners' capital....................... -- 25,161 22,183 17,350 19,614 Stockholders' equity.................... 43,664 -- -- -- -- OPERATING DATA: Fee gas processed (mbtu)................ 33,899,744 -- -- -- -- NGL production (gallons)................ 94,908,534 92,239,000 99,735,000 93,355,000 88,616,000 Terminal throughput (gallons)........... 37,851,450 31,206,000 32,664,000 30,116,000 26,273,000 Michigan pipeline throughput (mcf)...... 1,161,182 -- -- -- -- - ---------------------------------------- (1) Prior to October 7, 1996, the Company was organized as a partnership, MarkWest Hydrocarbon Partners, Ltd. ("MarkWest Partnership") and consequently, was not subject to income tax. Effective October 7, 1996 the Company reorganized (the "Reorganization") and the existing general and limited partners exchanged 100% of their interests in MarkWest Partnership for 5,725,000 common shares of the Company. A pro forma provision for income taxes has been presented for purposes of comparability as if the Company had been a taxable entity for all periods presented. 16 (2) Pro forma weighted average shares outstanding at December 31, 1996 represents the weighted average of the period prior to 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 at December 31, 1995 represents the weighted average number of common shares issued in the Reorganization. ITEM 7. MANAGEMENT'S DISCUSSIONS AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion is intended to provide an analysis of the Company's financial condition and results of operations for the three years ended December 31, 1996, and should be read in conjunction with the selected financial data and the Company's Consolidated Financial Statements and related Notes thereto included elsewhere in this Form 10-K. RESULTS OF OPERATIONS Year ended December 31, 1996 Compared to Year Ended December 31, 1995 Revenues. Plant revenue increased to $45.9 million from $33.8 million for the year ended December 31, 1996 as compared to the year ended December 31, 1995, an increase of $12.1 million or 36%. This increase is primarily a result of price-related increases of all NGLs of $9.9 million, partially offset by a volume-related decrease of $1.1 million. The volume decrease at the fractionation plant at Siloam, which receives approximately 70% of its raw NGL mix from the Kenova plant, was due principally to normal start-up delays in the transition from an older processing facility at Kenova to the Company's new plant in the first quarter of 1996. In addition, the new Kenova processing plant, which was placed into service in January 1996, generated an additional $3.5 million of fee revenue during 1996. Terminal and marketing revenue increased to $22.9 million from $13.2 million for the year ended December 31, 1996 as compared to the year ended December 31, 1995, an increase of $9.7 million, or 74%. This increase of $9.7 million was due to a $5.4 million volume-related increase and a $4.3 million price-related increase. Revenue from the West Memphis terminal accounted for $7.9 million of the increase and the new terminal in Church Hill, Tennessee, which became operational in the fall of 1995, accounted for $1.8 million of the increase. The increase in revenues from the West Memphis terminal was due principally to colder temperatures during the first and fourth quarters of 1996. Oil and gas and other revenue increased to $3.0 million from $1.1 million for the year ended December 31, 1996 as compared to the year ended December 31, 1995, an increase of $1.9 million, or 173%. This increase is principally due to the consolidation of MarkWest Michigan revenue of $1.7 million, offset by a decrease in miscellaneous revenue of approximately $100,000. Costs and expenses. Plant feedstock purchases increased to $22.2 million from $17.3 million for the year ended December 31, 1996 as compared to the year ended December 31, 1995, an increase of $4.9 million or 28%. This increase is principally due to price-related increases in raw materials. Terminal and marketing purchases increased to $18.7 million from $11.9 million for the year ended December 31, 1996 as compared to the year ended December 31, 1995, an increase of $6.8 million, or 57%. Increased propane prices resulted in a $2.5 million increase, in addition to volume increases at West Memphis and Churchill which resulted in increases of $2.9 million and $1.4 million, respectively. Operating expenses increased to $7.0 million from $4.7 million for the year ended December 31, 1996 as compared to the year ended December 31, 1995, an increase of $2.3 million, or 49%. This increase is partially due to new operations at both the Kenova and Church Hill facilities which commenced operations 17 in January 1996 and October 1995, respectively. Additional operating expenses resulted from the consolidation of MarkWest Michigan operations, which began in May 1996. Depreciation and amortization increased to $2.9 million from $1.8 for the year ended December 31, 1996 as compared to the year ended December 31, 1995, an increase of $1.1 million or 61%. This increase is due principally to depreciation attributable to the Company's new Kenova plant and MarkWest Michigan's pipeline and facilities. Net interest expense. Net interest expense increased to $900,000 from $400,000 for the year ended December 31, 1996 as compared to the year ended December 31, 1995, an increase of $500,000 or 125%. This increase resulted principally from an increase in average outstanding long-term debt of $12 million for 1996 compared to $8.1 million for 1995. Additionally, $301,000 of interest was capitalized in conjunction with capital projects in 1995, compared to only $27,000 of interest capitalized for 1996 projects. Income tax expense. Income tax expense increased $7 million for the year ended December 31, 1996, as compared to the year ended December 31, 1995, which had $0 income tax expense. As a partnership, MarkWest Hydrocarbon Partners, Ltd. (the Company's predecessor) was not subject to federal and state income tax, and its income was taxed directly to its respective partners. MarkWest Hydrocarbon, Inc. is a taxable entity and therefore, recorded income tax expense in 1996. Year Ended December 31, 1995 Compared to Year Ended December 31, 1994 Revenues. Plant revenue increased to $33.8 million from $33.1 million for the year ended December 31, 1995 as compared to the year ended December 31, 1994, an increase of $767,000, or 2%. This increase resulted principally from a $2.0 million increase due to an increase in average NGL sales prices, offset by a $1.2 million decrease due to reduced volumes sold. Terminal and marketing revenue decreased to $13.2 million from $13.7 million for the year ended December 31, 1995 as compared to the year ended December 31, 1994, a decrease of $494,000 or 4%. This decrease principally resulted from the expiration of the remaining third-party brokerage sales in 1994, including a net volume-related decrease of $3.1 million offset by a net price-related increase of $2.6 million. Oil and gas and other revenue decreased to $1.1 million from $1.8 million for the year ended December 31, 1995 as compared to the year ended December 31, 1994, a decrease of $755,000 or 41%. The decrease resulted principally from the Company's sale in 1994 of substantially all of its San Juan Basin coalbed methane properties and associated gathering systems. The Company sold its San Juan Basin coalbed methane properties and associated gathering systems in 1994 because it had the opportunity to do so at a substantial profit, and, at that time, such properties did not provide natural gas dedicated to the Company's processing operations. Gain on sale of oil and gas properties of $4.3 million in 1994 was due to the sale of a majority of the Company's oil and gas producing assets for approximately $10.1 million. Costs and expenses. Plant feedstock purchases decreased to $17.3 million from $21.6 million for the year ended December 31, 1995 as compared to the year ended December 31, 1994, a decrease of $4.3 million or 20%. This decrease resulted from the acquisition of feedstock quantities during off-peak periods, when prices typically are lower, rather than at spot prices during peak season. Terminal and marketing purchases increased to $11.9 million from $11.5 million for the year ended December 31, 1995 as compared to the year ended December 31, 1994, an increase of $440,000 or 4%. This increase was due principally to an increase in the average price per gallon of propane. 18 Operating expenses increased to $4.7 million from $4.4 million for the year ended December 31, 1995 as compared to the year ended December 31, 1994, an increase of $313,000 or 7%. The increase was attributable to the construction and start up of the Kenova gas processing facility. General and administrative expenses increased to $4.2 million from $3.7 million for the year ended December 31, 1995 as compared to the year ended December 31, 1994, an increase of $535,000 or 15%. The increase was attributable to administrative support activities related to the Michigan Project and the new Kenova and Church Hill facilities. Depreciation and amortization decreased to $1.8 million from $1.9 million for the year ended December 31, 1995 as compared to the year ended December 31, 1994, a decrease of $188,000 or 10%. This decrease resulted principally from lower plant carrying values due to reductions made in 1994. Reduction in carrying value of assets of $3.0 million in 1994 was due to a one- time charge reflecting the shutdown of the isomerization unit at the Siloam plant and a charge for the write-down of other non-productive equipment. Net interest expense. Net interest expense decreased to $400,000 from $1.7 million for the year ended December 31, 1995 as compared to the year ended December 31, 1994, a decrease of $1.3 million or 79%. The decrease resulted principally from lower average borrowing levels of approximately $16.0 million in 1994 to $8.1 million in 1995, a decrease in interest rates, the capitalization of approximately $301,000 of interest in connection with the construction of the Kenova gas processing plant, and the early extinguishment of a note that required the Company to pay additional interest averaging $400,000 per year based on the throughput of the Company's Siloam facility. LIQUIDITY AND CAPITAL RESOURCES The Company's sources of liquidity and capital resources historically have been net cash provided by operating activities; proceeds from issuance of long-term debt; in 1994, the proceeds from the sale of certain oil and gas properties; and in 1996, an initial public offering of equity. The Company's principal uses of cash have been to fund operations and acquisitions. The following summary table reflects comparative cash flows for the Company for the years ended December 31, 1996, 1995 and 1994: Year Ended December 31, --------------------------------- 1996 1995 1994 ---- ---- ---- Net cash provided by operating activities............................. $ 16,815 $ 5,436 $ 994 Net cash provided by (used in) investing activities................... $(17,516) $(12,610) $ 9,068 Net cash provided by (used in) financing activities................... $ 4,341 $ 2,467 $(5,886) For the year ended December 31, 1996, net cash provided by operating activities increased by $11.4 million over the year ended December 31, 1995. This increase resulted primarily from an increase in revenue of $23.7 million, which was offset by a $15.1 million increase in feedstock purchases, terminal and marketing purchases, operating expenses and general and administrative expenses. Cash used in investing activities increased $4.9 million for the year ended December 31, 1996, as compared to the year ended December 31, 1995, primarily due to capital expenditures incurred during 1996 related to the Michigan project. 19 Cash provided by financing activities increased $1.9 million for the year ended December 31, 1996, as compared to the year ended December 31, 1995. This increase resulted primarily from the initial public offering in October, which was partially offset by payments made on long-term debt. Financing Facilities Revolver Loan. The Company currently has a financing agreement with Norwest Bank Denver, N.A., as agent, First American National Bank of Nashville, Tennessee, First Chicago NBD and N M Rothschild and Sons Limited. The agreement is structured as a revolving facility, with a maximum borrowing base of $40.0 million as of December 31, 1996. Interest rates are based on either the agent bank's prime rate plus 1/4 % or the London Interbank Offered Rate (LIBOR) plus 2%. The repayment period begins on September 30, 1998, continuing for 16 equal quarterly installments until June 30, 2002. Outstanding borrowings at December 31, 1996 were $4.2 million. This facility is secured by substantially all of the Company's assets. Working Capital Loan. The Company has a working capital line of credit with a maximum borrowing base of $7.5 million as of December 31, 1996. Interest rates are based on prime plus 1/4 %, with maturity on June 30, 1998. Outstanding borrowings at December 31, 1996 were $5.7 million. The working capital loan is secured by the Company's inventories, receivables and cash. All amounts outstanding under this facility were repaid effective February 19, 1997. Resources Revolver Loan. The Company's Resources subsidiary has a revolving facility with Colorado National Bank ("CNB") with a maximum borrowing base of $5.8 million as of December 31, 1996. Interest is based on CNB's bank rate plus 1/2 %. The facility has a maturity date of April 2003. This facility is restricted for the exploration and development of oil and gas properties and as of December 31, 1996, $1.2 million was outstanding. This facility is secured by substantially all of MarkWest Resources' assets. The Company has guaranteed $1.0 million of this facility. All amounts outstanding under this facility were repaid effective February 19, 1997. The loan agreements contain affirmative and negative covenants customary in commercial lending transactions, including restrictions on the incurrence of additional debt, restrictions on the payment of dividends that would cause the Company to violate the financial covenants contained in the loan agreements, maintenance of a specified tangible net worth, current ratio, ratio of funded debt to total capitalization and fixed charge coverage ratio. Capital Investment Program The Company expects to invest approximately $20.0 for activities in the Michigan Core Area during 1997. The Company also expects to invest approximately $3.6 million in Resources in 1997. For the year ended December 31, 1996, the Company made capital expenditures totaling $9.8 million. During 1996 and 1995, the Company expended $12.2 million in connection with the construction of the Kenova plant. During 1995, the Company expended $213,000 for the construction and related costs for development of the Church Hill terminal and storage facility, respectively. During 1994, the Company expended $1.4 million for the expansion and upgrade of existing facilities. RISK MANAGEMENT ACTIVITIES The Company's policy is to utilize risk management tools primarily to reduce commodity price risk for its natural gas shrink replacement purchases. This effectively allows the Company to fix a portion of its margin because gains or losses in the physical market are offset by corresponding losses or gains in the financial instruments market. The Company's hedging activities generally fall into three categories--contracting for future purchases of natural gas at a predetermined BTU differential based upon a basket of 20 Gulf Coast NGL prices, the fixing of margins between propane sales prices and natural gas reimbursement costs by purchasing natural gas contracts and simultaneously selling propane contracts (or a substitute for propane such as crude oil) of approximately the same BTU value, and the purchase of propane futures contracts to hedge future sales of propane at the Company's terminals or gas plants. The Company maintains a three-person committee that oversees all hedging activity of the Company. This committee reports monthly to management regarding recommended hedging transactions and positions. Gains and losses related to qualifying hedges, as defined by Statement of Financial Accounting Standards, ("SFAS") No. 80, "Accounting for Futures Contracts", of firm commitments or anticipated transactions are recognized in plant revenue and feedstock purchases upon execution of the hedged physical transaction. As of December 31, 1996, 1995 and 1994, the Company did not hold any material notional quantities of natural gas, NGL, or crude oil futures, swaps or options. For the year ended December 31, 1996, the Company recognized a $1.1 million loss in operating income on the settlement of propane and natural gas futures. 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 and Exchange Act of 1933 and Section 21E of the Securities and Exchange Act of 1934. All forward looking statements involve risks and uncertainties. The forward looking statements in this document are intended to be subject to the safe harbor protection provided by Sections 27A and 21E. Factors that most typically impact the Company's operating results and financial condition include (i) changes in general economic conditions in regions in which the Company's products are located, (ii) the availability and prices of NGLs and competing commodities, (iii) the availability of raw natural gas supply, (iv) the ability of the Company to negotiate favorable marketing agreements, (v) the risks that natural gas exploration and production activities will not be successful, (vi) the Company's dependence on certain significant customers, (vii) competition from other NGL processors, including major oil and gas companies, and (viii) the Company's ability to identify and consummate acquisitions complementary to its business. For discussions identifying other important factors that could cause actual results to differ materially from those anticipated in the forward looking statements, see the Company's Securities and Exchange Commission filings; and "Management's Discussion and Analysis of Financial Conditions and Results of Operations" of this Form 10-K. 21 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Page ---- Report of Independent Accountants......................................... 23 Consolidated Balance Sheet at December 31, 1996 and 1995.................. 24 Consolidated Statement of Operations for each of the three years ended December 31, 1996........................................................ 25 Consolidated Statement of Cash Flows for each of the three years ended December 31, 1996........................................................ 26 Consolidated Statement of Changes in Stockholders' Equity/ Partners' Capital for each of the three years ended December 31, 1996.............. 27 Notes to Consolidated Financial Statements................................ 28 22 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of MarkWest Hydrocarbon, Inc. In our opinion, the accompanying consolidated balance sheet and related consolidated statements of operations, of cash flows and of changes in stockholders' equity/ partners' capital present fairly, in all material respects, the financial position of MarkWest Hydrocarbon, Inc., a Delaware corporation (formerly MarkWest Hydrocarbon Partners, Ltd., a Colorado limited partnership), and its subsidiaries at December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. PRICE WATERHOUSE LLP Denver, Colorado March 5, 1997 23 MARKWEST HYDROCARBON, INC. (SUCCESSOR TO MARKWEST HYDROCARBON PARTNERS, LTD.) CONSOLIDATED BALANCE SHEET ($000S, EXCEPT SHARE DATA) December 31, ASSETS 1996 1995 -------- -------- Current assets: Cash and cash equivalents............... $ 4,401 $ 761 Receivables............................. 9,755 8,909 Inventories............................. 5,632 2,830 Prepaid expenses and other assets....... 2,289 2,104 -------- ------- Total current assets.................. 22,077 14,604 -------- ------- Property and equipment: Gas processing, gathering, storage and marketing.............................. 45,247 23,134 Oil and gas properties and equipment.... 3,731 1,883 Construction in progress................ 5,831 10,282 Land, buildings and other equipment..... 5,647 6,216 -------- ------- 60,456 41,515 Less: accumulated depreciation, depletion and amortization............. (12,316) (9,568) -------- ------- Total property and equipment, net..... 48,140 31,947 -------- ------- Intangible assets, net of accumulated amortization of $315 and $152 respectively.................... 380 320 Note receivable and other assets......... 7,657 25 -------- ------- Total assets.......................... $ 78,254 $46,896 ======== ======= LIABILITIES AND STOCKHOLDERS' EQUITY/PARTNERS' CAPITAL Current liabilities: Trade accounts payable.................. $ 5,382 $ 3,283 Accrued liabilities..................... 1,629 952 Income taxes payable.................... 3,014 -- Current portion of long-term debt....... 156 -- -------- ------- Total current liabilities............. 10,181 4,235 Deferred income taxes.................... 3,977 -- Long-term debt........................... 11,257 17,500 -------- ------- Total liabilities..................... 25,415 21,735 Minority interest........................ 9,175 -- -------- ------- Commitments and contingencies............ -- -- -------- ------- Stockholders' equity/ partners' capital: Common stock, par value $.01; 8,485,000 shares authorized, issued and outstanding........................ 85 -- Additional paid-in capital.............. 42,237 -- Partners' capital....................... -- 25,161 Retained earnings....................... 1,342 -- -------- ------- Total stockholders' equity/ partners' capital............................... 43,664 25,161 -------- ------- Total liabilities and stockholders' equity/partners' capital................ $ 78,254 $46,896 ======== ======= The accompanying notes are an integral part of these financial statements. 24 MARKWEST HYDROCARBON, INC. (SUCCESSOR TO MARKWEST HYDROCARBON PARTNERS, LTD.) CONSOLIDATED STATEMENT OF OPERATIONS ($000S, EXCEPT PER SHARE DATA) For the Year Ended December 31, 1996 1995 1994 ------- ------- ------- Revenues: Plant revenue................................................... $45,880 $33,823 $33,056 Terminal and marketing revenue.................................. 22,858 13,172 13,666 Oil and gas and other revenue................................... 3,022 1,075 1,830 Interest income................................................. 192 156 136 Gain on sales of oil and gas properties......................... -- -- 4,275 ------- ------- ------- Total revenues................................................ 71,952 48,226 52,963 ------- ------- ------- Costs and expenses: Plant feedstock purchases....................................... 22,231 17,308 21,582 Terminal and marketing purchases................................ 18,676 11,937 11,497 Operating expenses.............................................. 7,048 4,706 4,393 General and administrative expenses............................. 5,302 4,189 3,654 Depreciation, depletion and amortization................................................... 2,910 1,754 1,942 Interest expense................................................ 1,090 508 1,825 Reduction in carrying value of assets........................... -- -- 2,950 ------- ------- ------- Total costs and expenses...................................... 57,257 40,402 47,843 ------- ------- ------- Income before minority interest, income taxes and extraordinary item.................................... 14,695 7,824 5,120 Minority interest in net loss of subsidiary...................................................... 65 -- -- ------- ------- ------- Income before income taxes and extraordinary item.............................................. 14,760 7,824 5,120 Income tax provision: Arising from reorganization..................................... 3,745 -- -- Subsequent to reorganization.................................... 3,246 -- -- ------- ------- ------- Income before extraordinary item................................. 7,769 7,824 5,120 Extraordinary loss on extinguishment of debt............................................................ -- (1,750) -- ------- ------- ------- Net income....................................................... $ 7,769 $ 6,074 $ 5,120 ======= ======= ======= Pro forma information (Note 2): Historical income before extraordinary item............................................ $14,760 $ 7,824 $ 5,120 Pro forma provision for income taxes........................... 5,609 2,937 1,424 ------- ------- ------- Pro forma net income........................................... $ 9,151 $ 4,887 $ 3,696 ======= ======= ======= Pro forma earnings per share of common stock.................................................. $ 1.16 $ .85 ======= ======= Pro forma weighted average number of outstanding shares of common stock............................ 7,908 5,725 ======= ======= The accompanying notes are an integral part of these financial statements. 25 MARKWEST HYDROCARBON, INC. (SUCCESSOR TO MARKWEST HYDROCARBON PARTNERS, LTD.) CONSOLIDATED STATEMENT OF CASH FLOWS ($000S) For the Year Ended December 31, 1996 1995 1994 -------- -------- -------- Cash flows from operating activities: Net income............................. $ 7,769 $ 6,074 $ 5,120 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and 2,910 1,754 1,942 amortization..................... Deferred income taxes............. 3,977 -- -- Option granted in conjunction with extinguishment of debt..... -- 1,050 -- Loss (gain) on sale of assets..... 46 -- (4,275) Reduction in carrying value of assets........................... -- -- 2,950 (Increase) in receivables......... (846) (4,729) (977) (Increase) decrease in inventories (2,802) (19) 1,348 (Increase) decrease in prepaid expenses and other assets........ (185) (86) (1,125) Increase (decrease) in accounts payable and accrued liabilities.. 5,946 1,392 (3,989) -------- -------- -------- Net cash flow provided by operating activities.... 16,815 5,436 994 Cash flows from investing activities: Capital expenditures.............. (9,824) (12,426) (1,442) Proceeds from sale of assets...... -- -- 10,166 Increase in long-term notes receivable....................... (7,657) -- -- Decrease (increase) in intangible and other assets................. (35) (184) 344 -------- -------- -------- Net cash provided by (used in) investing activities.............. (17,516) (12,610) 9,068 Cash flows from financing activities: Proceeds from issuance of long-term debt.................. 1,174 -- -- Repayments of long-term debt...... (84) (500) -- Borrowings under revolving credit facility......................... 45,950 26,050 7,201 Payments on revolving credit facility........................ (53,548) (18,937) (12,800) Partners' distributions........... (14,150) (4,150) (320) Payments on partner notes......... 320 -- -- Payments on options............... 71 4 33 Proceeds from issuance of common stock.................... 24,608 -- -- -------- -------- -------- Net cash provided by (used in) financing activities.............. 4,341 2,467 (5,886) Net increase (decrease) in cash and cash equivalents............. 3,640 (4,707) 4,176 Cash and cash equivalents at beginning of year.............................. 761 5,468 1,292 -------- -------- -------- Cash and cash equivalents at end of year................................. $ 4,401 $ 761 $ 5,468 ======== ======== ======== The accompanying notes are an integral part of these financial statements. 26 MARKWEST HYDROCARBON, INC. (SUCCESSOR TO MARKWEST HYDROCARBON PARTNERS, LTD.) CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY/ PARTNERS' CAPITAL ($000S) TOTAL PARTNERS' COMMON ADDITIONAL PAID-IN RETAINED STOCKHOLDERS' CAPITAL STOCK CAPITAL EARNINGS EQUITY ---------- ------ ------------------ --------- -------------- Balance, December 31, 1993 $ 17,350 $ $ -- $ $ 17,350 Net income 5,120 -- -- -- 5,120 Distributions, net of contributions (287) -- -- -- (287) -------- ------ ------------------ -------- -------- Balance, December 31, 1994 22,183 -- -- -- 22,183 Net income 6,074 -- -- -- 6,074 Distributions, net of contributions (4,146) -- -- -- (4,146) Option granted in conjunction with extinguishment of debt 1,050 -- -- -- 1,050 -------- ------ ------------------ -------- -------- Balance, December 31, 1995 25,161 -- -- -- 25,161 Net income prior to reorganization 6,427 -- -- -- 6,427 Notes receivable from partners, net, 205 -- -- -- 205 prior to reorganization Distributions prior to reorganization (14,150) -- -- -- (14,150) Exercise of options, prior to 71 -- -- -- 71 reorganization Reorganization from a limited partnership to a corporation (17,714) 57 17,657 -- -- Deferred taxes relating to the reorganization -- -- -- (3,745) (3,745) Common stock issued -- 28 24,580 -- 24,608 Net income after reorganization -- -- -- 5,087 5,087 -------- ------ ------------------ -------- -------- Balance, December 31, 1996 $ -- $85 $42,237 $ 1,342 $ 43,664 ======== ====== ================== ======== ======== The accompanying notes are an integral part of these financial statements. 27 MARKWEST HYDROCARBON, INC. (SUCCESSOR TO MARKWEST HYDROCARBON PARTNERS, LTD.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. NATURE OF OPERATIONS AND SIGNIFICANT BUSINESS ACQUISITIONS NATURE OF OPERATIONS AND RECENT REORGANIZATION MarkWest Hydrocarbon, Inc. (the "Company") provides compression, gathering, treatment, processing and natural gas liquids extraction services to natural gas producers and pipeline companies and fractionates natural gas liquids into marketable products for sale to third parties. The Company also purchases, stores and markets natural gas and natural gas liquids and has begun to conduct strategic exploration for new natural gas resources for its processing and fractionation activities. The Company was incorporated in June 1996 to act as the successor to MarkWest Hydrocarbon Partners, Ltd. (the "Partnership"). Effective October 7, 1996, the Partnership reorganized (the "Reorganization") and the existing general and limited partners exchanged 100% of their interests in the Partnership for 5,725,000 common shares of the Company. An additional 2,400,000 shares of common stock were offered for public sale, totaling 8,125,000 shares outstanding as of October 15, 1996. The over-allotment of 360,000 shares was also exercised during October, resulting in a total of 8,485,000 shares outstanding at October 31, 1996. This transaction was a reorganization of entities under common control, and accordingly, it was accounted for at historical cost. SIGNIFICANT BUSINESS ACQUISITIONS Prior to July 1, 1996, the Partnership owned 49% of MarkWest Coalseam Development Company LLC (formerly MarkWest Coalseam Joint Venture) ("Coalseam"), a natural gas development venture, and MW Gathering LLC ("Gathering"), a natural gas gathering venture. Effective July 1, 1996, Gathering was merged into Coalseam. Simultaneously, the Partnership formed MarkWest Resources Inc. ("Resources"), and Coalseam distributed 49% of its assets to Resources and 51% to MAK-J Energy Partners, Ltd. (formerly MarkWest Energy Partners, Ltd.) ("Energy"), a partnership whose general partner is a corporation owned and controlled by the President of the Company. The consolidated financial statements reflect Resources' 49% proportionate share of the underlying oil and gas assets, liabilities, revenues and expenses. Effective May 6, 1996, the Partnership acquired the right to earn up to a 60% interest for $16.8 million in a newly formed venture, West Shore Processing, LLC ("West Shore"). The most significant asset of West Shore is Basin Pipeline, LLC, which was contributed by the Partnership's venture partner, Michigan Energy Company, LLC. The West Shore agreement is structured so that the Company's ownership interest increases as capital expenditures for the benefit of West Shore are made by the Company. As of December 31, 1996, the Company has recorded a net investment in West Shore of $10.4 million, representing a 47% ownership interest. The Company is committed to make capital expenditures of approximately $21.0 million through 1997 in conjunction with the first two phases of the agreement. Phase I of the project will be completed in early 1997. Phase II, scheduled for completion in late 1997, is underway. 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, Resources and MarkWest Michigan, Inc. All significant intercompany accounts and transactions have been eliminated in consolidation. 28 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 term/revolver loan facility. Accordingly, investments are limited to overnight investments of end-of-day cash balances. RECEIVABLES Receivables comprise the following (in $000s): At December 31, 1996 1995 ------- ------ Trade and other receivables... $9,755 $5,735 Short-term advances........... -- 3,174 ------ ------ $9,755 $8,909 ====== ====== No allowance for doubtful accounts is considered necessary based on favorable historical experience. During the fourth quarter of 1995, the Partnership made several short-term advances totaling $3,174,000 as part of an agreement with a partner to develop a joint project. In accordance with the terms of the agreement, the Partnership was reimbursed for the full amount of the advances at the closing date of May 6, 1996. INVENTORIES Inventories comprise the following (in $000s): At December 31, 1996 1995 ------- ------ Product inventory.................. $5,292 $2,718 Materials and supplies inventory... 340 112 ------ ------ $5,632 $2,830 ====== ====== Product inventory consists primarily of finished goods (propane, butane, isobutane and natural gasoline) and is valued at the lower of cost, using the first-in, first-out method, or market. Market value of the Company's product inventory was $7.6 million and $3.8 million at December 31, 1996 and 1995, respectively. Capitalized overhead costs of $232,000 and $219,000 were included in product inventory at December 31, 1996, and 1995, respectively. Materials and supplies are valued at the lower of average cost or estimated net realizable value. PREPAID EXPENSES AND OTHER ASSETS Prepaid expenses and other assets comprise the following (in $000s): At December 31, 1996 1995 ------ ------- Prepaid feedstock............ $1,831 $1,729 Prepaid expenses............. 458 375 ------ ------ 29 $2,289 $2,104 ====== ====== Prepaid feedstock consists of natural gas purchased in advance of its actual use. It is valued on a first-in, first-out method. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is recorded at cost. Expenditures which extend the useful lives of assets are capitalized. Repairs, maintenance and renewals which 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, 20 years; buildings, 40 years; furniture, leasehold improvements and other, 3-10 years. Depreciation for oil and gas properties is provided for using the units-of-production method. Oil and gas properties consist of leasehold costs, producing and non-producing gas wells and equipment, and pipelines. The Company uses the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves are capitalized to the full cost pool. These capitalized costs, including estimated future costs to develop the reserves and estimated abandonment costs, net of salvage value, are amortized on a units-of-production basis using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment of such properties indicate that the properties are impaired, the amount of impairment is added to the capitalized cost base to be amortized. As of December 31, 1996 and 1995, approximately $649,000 and $862,000 of investments in unproved properties were excluded from amortization. The capitalized costs included in the full cost pool are subject to a "ceiling test," which limits such costs to the aggregate of the estimated present value, using a 10 percent discount rate, of the future net revenues from proved reserves, based on current economics and operating conditions. Impairment under the ceiling test of $116,000 was recognized in 1994 and is included in depreciation, depletion and amortization in the accompanying consolidated statement of operations. No impairment existed as of December 31, 1996 and 1995. Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in the consolidated statement of operations. IMPAIRMENT OF LONG-LIVED ASSETS During 1996, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, which requires that an impairment loss be recognized when the carrying amount of an asset exceeds the expected future undiscounted net cash flows. There was no effect on the Company's financial statements as a result of adopting SFAS No. 121. INTANGIBLE ASSETS 30 Deferred financing costs and a non-compete agreement with a former officer and director are included in intangible assets. Both are amortized using the straight-line method over the terms of the associated agreements. NOTE RECEIVABLE Note receivable at December 31, 1996 consists of a note receivable (the "Note") from Michigan Production Company, LLC ("MPC"). The Note is for all sums necessary for the construction of the 31 mile extension to the Basin pipeline. The Note bears an interest rate of 5.98% and is payable to the Company on the earlier of two dates which are contingent upon certain events as defined in the 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 SFAS No. 80, Accounting for Futures Contracts. Gains and losses on such hedge contracts are deferred and included as a component of propane revenues and feedstock purchases 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, 1996 and 1995, 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 delivered 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 which potentially subject the Company to concentrations of credit risk consist principally of trade accounts receivable. The 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, 1996, 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. The Company has complied with the pro forma disclosure requirements of SFAS No. 123 as required under the pronouncement. 31 SUPPLEMENTAL CASH FLOW INFORMATION Interest of $1,012,000, $792,000 and $1,805,000 was paid for years ended December 31, 1996, 1995 and 1994, respectively. Interest paid in 1996 is net of $27,000 capitalized in relation to various construction projects. There were no income taxes paid during the three years ended December 31, 1996. The Consolidated Statement of Cash Flows for the year ended December 31, 1996 excludes non-cash activities related to the contribution of Basin Pipeline, LLC by Michigan Energy, LLC ("MEC") to West Shore. MEC's contribution was valued at approximately $9.2 million. In 1996, the Company financed the purchase of certain assets from the Dow Chemical Company ("Dow") with a note valued at approximately $421,000. As of December 31, 1996, $337,000 was outstanding under this note. PRO FORMA INFORMATION Pro forma provision for income taxes and pro forma net income. Prior to the Reorganization, MarkWest was organized as a partnership and, consequently, was not subject to income tax. A pro forma provision for income taxes for the years ended December 31, 1996, 1995 and 1994 has been presented for purposes of comparability as if MarkWest had been a taxable entity for all periods presented. Pro forma weighted average shares outstanding at December 31, 1996 and December 31, 1995. Pro forma weighted average shares outstanding at December 31, 1996 represents the weighted average of, for the period prior to 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 at December 31, 1995 represents the number of common shares issued in the Reorganization. RECLASSIFICATIONS Certain prior year amounts have been reclassified to conform to the 1996 presentation. 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. NOTE 3. DEBT REVOLVER/TERM LOAN On November 20, 1992, the Partnership entered into a financing agreement with Norwest Bank Denver, N.A. ("Norwest") and First American National Bank ("FANB") of Nashville, Tennessee. The facility is structured as a revolver and had an initial maximum borrowing base of $20 million. The borrowing base on the facility is redetermined semi-annually. On September 8, 1995, the agreement was amended to add N M Rothschild and Sons Limited ("Rothschild") as a lender, revise the interest rate for base rate loans and institute the option of LIBOR (London Interbank Offered Rate) interest. On May 31, 1996, the facility was further amended to increase the maximum borrowing base to $40 million and extend the repayment period 32 to June 30, 2002, with 16 equal quarterly installments commencing September 30, 1998. As of December 31, 1996 and 1995, outstanding borrowings were $4.2 million and $15 million, respectively. The remaining borrowing base of $35.8 million and $10 million was unutilized at December 31, 1996 and 1995, respectively. Interest on a base rate loan is now calculated at prime plus 1/4 % if the Company's total debt is less than or equal to 40% of total capitalization. If debt exceeds 40% of capitalization, the rate increases to prime plus 1/2 %. At December 31, 1996 and 1995, $0 million and $3 million were outstanding under a base rate loan bearing interest at 8 1/2 % and 9 %, respectively. The LIBOR option allows the Company to lock in a portion of the revolver balance for a period of one, two, three or six months. Interest on a LIBOR loan is calculated at LIBOR plus 2% if the Company's total debt is less than or equal to 40% of total capitalization. If debt exceeds 40% of capitalization, the rate increases to LIBOR plus 2 1/4 %. At December 31, 1996 and 1995, $0 and $12 million were outstanding under the LIBOR commitment, respectively. This debt is secured by a first mortgage on the Company's property, plant, equipment and contracts, excluding railcars and truck trailers. The loan agreement restricts certain activities and requires the maintenance of certain financial ratios and other conditions. WORKING CAPITAL LINE OF CREDIT On November 20, 1992, the Partnership entered into a working capital line of credit agreement with Norwest and FANB in the amount of $5 million. The borrowing base, as defined in the credit agreement, is redetermined monthly. On September 8, 1995, the agreement was amended to add Rothschild as a lender, revise the interest rate, increase the maximum borrowing base to $7.5 million, and extend the working capital commitment period and maturity date. The extended due date on the working capital note is June 30, 1998. The interest rate change is the same as discussed above for the revolver/term loan. No LIBOR option is available for the working capital line. At December 31, 1996 and 1995, $5.7 million and $2.5 million were outstanding bearing interest at 8 1/2 % and 9 %, respectively. All amounts outstanding under this facility were paid off effective February 6, 1997. MARKWEST RESOURCES REVOLVER LOAN The Company's MarkWest Resources subsidiary has a revolving facility with Colorado National Bank ("CNB") with a maximum borrowing base of $5.8 million as of December 31, 1996. Interest is based on CNB's bank rate plus 1/2 %. The facility has a maturity date of April 2003. This facility is restricted for the exploration and development of oil and gas properties and as of December 31, 1996 and December 31, 1995, $1.2 million and $0 were outstanding, respectively. This facility is secured by substantially all of MarkWest Resources' assets. The Company has guaranteed $1 million of this facility. All amounts outstanding under this facility were repaid effective February 19, 1997. Scheduled debt maturities under the terms of the facilities are as follows (in $000s): At December 31, 1996 At December 31, 1995 Revolver Line of Subsidiary Revolver Line of loan credit Debt loan credit -------- ------- ---------- ---------- -------- 1997 $ - $ - $ 156 $ 1,875 $2,500 1998 525 5,700 156 3,750 - 1999 1,050 - 25 3,750 - 2000 1,050 - - 3,750 - 2001 and thereafter 1,575 - 1,176 1,875 - ------ ------- ------ ------- -------- 33 Total $4,200 $5,700 $1,513 $15,000 $2,500 ====== ======= ====== ======= ======== SOUTH SHORE NOTE The note agreement for the purchase of the South Shore plant and the isomerization expansion allowed for the prepayment of principal to no less than $500,000. In November 1992, the Partnership exercised its prepayment rights relative to this agreement by paying $9.2 million of the then-outstanding balance. The remaining $500,000 principal balance accrued interest at 12%. Under the terms of the note, additional interest was payable annually based on certain operating results of the fractionation plant and proceeds from asset dispositions. Such additional interest expense was $422,000 for 1994. During 1995, the Partnership reached an agreement with the noteholder to fully retire the note. Accordingly, the Partnership paid the remaining balance of $500,000 as well as $700,000 of additional interest. In addition, the Partnership granted to the noteholder an option to acquire 3.5% of the Partnership. Based on management's best estimate of the fair value of the Partnership, the option was valued at $1,050,000 which, together with the $700,000 of additional interest, is reflected in the Consolidated Statement of Operations as an extraordinary loss due to the early extinguishment of debt. NOTE 4. RELATED PARTY AND CAPITAL TRANSACTIONS The Company made contributions of $299,000, $211,000, $213,000 to a profit- sharing plan for the years ended December 31, 1996, 1995 and 1994, respectively. The plan is discretionary, with annual contributions determined by the Company's Board of Directors. The Partnership periodically extended offers to employees to purchase interests in the Partnership. The partners and/or employees provided the Partnership with promissory notes as part of the exercise price. According to the terms of the notes, interest accrues at 7% and payments are required for the greater of accrued interest or excess distributions. Notes in the amounts of $376,000 and $512,000 have been recorded as a reduction of additional paid-in capital at December 31, 1996 and 1995, respectively. The Company has receivables from employees and officers of $23,000 and $74,000 at December 31, 1996 and 1995, respectively. The Company's employees perform certain administrative functions on behalf of its subsidiaries. At December 31, 1996 and 1995, no material amounts were due to or from the subsidiaries for miscellaneous administrative expenses. NOTE 5. SPECIAL ITEMS In 1994, the Partnership shut down the South Shore plant's isomerization unit when it was unable to find satisfactory markets for its isobutane. Accordingly, the Partnership recorded a $2,242,000 charge to write down the unit to its estimated realizable value. In addition, a catalyst used in the isomerization process was sold, resulting in a $347,000 loss. The Partnership also recorded a charge of $361,000 in 1994 for the write-down of non-productive equipment related to various business development projects. NOTE 6. COMMITMENTS AND CONTINGENCIES The Company is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities (net of insurance) that may result from these claims will not, individually or in the aggregate, have a material adverse effect on the Company's financial position or results of operations. NOTE 7. SIGNIFICANT CUSTOMERS 34 For the year ended December 31, 1995, sales to one customer accounted for approximately 18% of total revenues. During 1996 and 1994, no sales to any one customer accounted for more than 10% of total revenue. Management believes the loss of these customers would not adversely impact operations, as alternative markets are available. NOTE 8. HEDGING ACTIVITIES MarkWest's primary hedging objectives are to meet or exceed budgeted gross margins by locking in budgeted or above-budgeted prices in the financial derivatives markets and to protect margins from precipitous declines. Under internal guidelines, speculative positions are prohibited. The Company's hedging activities generally fall into three categories - 1) contracting for future purchases of natural gas at a predetermined BTU differential based upon a basket of Gulf Coast NGL prices (or a substitute for propane such as crude oil), 2) the fixing of margins between propane sales prices and natural gas reimbursement costs by purchasing natural gas contracts and simultaneously selling propane contracts of approximately the same BTU value, and 3) the purchase of propane futures contracts to hedge future sales of propane at the Company's terminals or gas plants. The Company enters into futures transactions on the New York Mercantile Exchange ("NYMEX"). Future gas purchases are based on predetermined BTU differentials are negotiated with natural gas suppliers and structured to provide similar risk protections as NYMEX futures. At December 31, 1996, the Company had a total of 295 short and 135 long open propane futures contracts representing a notional quantity amounting to 160,000 barrels of production. Late in 1996, the Company entered into agreements with certain natural gas suppliers for gas purchases (25,000 mmbtus a day) for the summer of 1997 at differentials to crude oil futures and NGL baskets at December 31, 1996. There were no material notional quantities of natural gas or crude oil futures or options at December 31, 1996, and no material notional quantities of natural gas, NGL, or crude oil futures, swaps or options at December 31, 1995. During the years ended December 31, 1996 and 1995, a $1.1 million loss and $300,000 gain, respectively, were recognized in operating income on the settlement of propane and natural gas futures. Financial instrument gains and losses on hedging activities were generally offset by amounts realized from the sale of the underlying products in the physical market. NOTE 9. INCOME TAXES In connection with the reorganization from a partnership to a corporation, the Company recorded deferred income taxes as of October 7, 1996 and a one-time charge to earnings of $3.7 million. The total income tax provision for the year ended December 31, 1996 has been allocated as follows (in $000s): Arising from reorganization $3,745 Subsequent to reorganization 3,246 ------ $6,991 ====== 35 The components of the income tax provision subsequent to reorganization consisted of the following (in $000s): Year ended December 31, 1996 ------------ Current federal $2,616 Current state 398 ------ Total current..................... 3,014 ------ Deferred federal.............................. 212 Deferred state 20 ------ Total deferred.................... 232 ------ Total income tax provision subsequent......... $3,246 to reorganization............................ ====== The deferred tax liability is comprised of the following (in $000s): December 31, 1996 ------------ Property and equipment........................ $3,667 Intangible assets............................. (6) Other assets.................................. 316 ------ Net deferred tax liability.................... $3,977 ====== Income taxes subsequent to reorganization as reflected in the Consolidated Statement of Operations differ from the amounts computed by applying the statutory federal corporate tax rate to income as follows (in $000s): Year ended December 31, 1996 ------------ Income taxes subsequent to 2,916 reorganization at statutory rate............. State income taxes, net of federal 140 benefit...................................... Tax credits................................... (35) Other......................................... 225 ------ Income taxes subsequent to reorganization............................... $3,246 ====== NOTE 10. STOCK COMPENSATION PLANS At December 31, 1996, 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 (1996 and 1995 grants only) under those plans consistent with the method prescribed by SFAS No. 123, Accounting for Stock-Based Compensation, the 36 Company's pro forma net income and earnings per share would have been reduced to the pro forma amounts listed below (in $000s): 1996 1995 ------- ------- Pro forma net income As reported $9,151 $4,887 Pro forma 9,127 4,887 Pro forma earnings per share As reported $ 1.16 $ 0.85 Pro forma 1.15 0.85 The Company historically granted employees the right to purchase partnership interests in the Partnership. As part of the Reorganization, such employee options to purchase partnership interests were replaced by options to purchase shares pursuant to the Company's 1996 Stock Incentive Plan. Under the 1996 Stock Incentive Plan, the Company may grant options to its employees for up to 600,000 shares of common stock in the aggregate. 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 both plans, 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 10 years. Options are granted periodically throughout the year and vest at the rate of 20% on the first anniversary of the option grant date, and at the rate of 20% on each subsequent anniversary thereof until fully vested. 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 used for grants in 1996 and 1995, respectively: dividend yield of $0/share for all years; expected volatility of 33% for 1996 option grants and 34% for 1995 plan options; risk-free interest rate of 6.55% for 1996 option grants and 6.22% for 1995 option grants; and expected lives of 6 years for 1996 and 1995 option grants. A summary of the status of the Company's two fixed stock option plans as of December 31, 1996 and 1995 and changes during the years ended on those dates is presented below: 1996 1995 ----------------------- ------------------ Weighted- Weighted- Average Average Exercise Exercise Shares Price Shares Price FIXED OPTIONS ------- ----------- ------ --------- Outstanding at beginning of year 64,004 $6.99 -- -- Granted 138,032 9.65 64,004 $6.99 Exercised -- -- -- -- Forfeited (1,146) -- -- -- ------- ----- ------ ----- Outstanding at end of year 200,890 $8.86 64,004 $6.99 ======= ===== ====== ===== Options exercisable at 12/31/96 12,800 12,800 Weighted-average fair value of options granted during the year $ 4.37 $ 3.16 37 The following table summarizes information about fixed stock options outstanding at December 31, 1996: Options Outstanding Options Exercisable --------------------------------------- ---------------------- Weighted- Average Weighted- Weighted- Number Remaining Average Number Average Outstanding Contractual Exercise Exercisable Exercise Range of Exercise Prices at 12/31/96 Life Price at 12/31/96 Price - ------------------------- ----------- ----------- --------- ----------- --------- $6.99 64,004 8.6 years $6.99 12,800 $6.99 $7.00 to $10.00 136,886 9.7 years $9.65 -- ---------- ------ 200,890 12,800 ========== ====== NOTE 11. STOCK ACTIVITY Activity in the Company's common stock for each of the three years ended December 31, 1996 is summarized below (in 000s of shares): # of shares ----------- Balance at December 31, 1993 -- Balance at December 31, 1994 -- Balance at December 31, 1995 -- Shares issued in exchange for partnership interests 5,725 Shares issued in initial public offering 2,400 Shares issued in over-allotment 360 ----- Balance at December 31, 1996 8,485 ===== 38 NOTE 12. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) The following summarizes certain quarterly results of operations ($000s): First Second Third Fourth -------- ------- --------- -------- 1996 - -------------------------------------- Revenue(1) $19,832 $8,760 $14,935 $28,233 Gross profit (2) 5,514 1,580 3,533 10,268 Pro forma net income (3) 2,588 195 1,205 5,163 Per common share data: Pro forma net income $ .33 $ .03 $ .15 $ .65 1995 - -------------------------------------- Revenue (1) $15,566 $7,360 $ 8,665 $16,479 Gross profit (2) 4,770 1,860 1,564 4,171 Pro forma income before extraordinary loss (3) 2,261 421 352 1,853 Extraordinary loss on extinguishment of debt -- -- (1,750) -- Pro forma net income(3) 2,261 421 (1,398) 1,853 Per common share data: Pro forma income before extraordinary loss $ .40 $ .07 $ .06 $ .32 Extraordinary loss -- -- (.30) -- Pro forma net income (loss) .40 .07 (.24) .32 (1) Excludes interest income. (2) Excludes general and administrative expenses and interest expense. (3) During 1996, the Company reorganized and became a taxable entity. Pro forma net income reflects the results of the Company had it been a taxable entity for all periods presented. 39 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 AND 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 (the "Proxy Statement") pursuant to Regulation 14A under the Securities 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 June 6, 1997 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 listing on page 22 for a list of all financial statements filed as a part of this report. (2) Financial Statement Schedules: None required. (3) Exhibits 3.1 Certificate of Incorporation of MarkWest Hydrocarbon, Inc. (Filed as exhibit 3.1 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 3.2 Bylaws of MarkWest Hydrocarbon, Inc. (Filed as exhibit 3.2 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 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. (Filed as exhibit 10.1 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 40 10.2 Loan Agreement dated November 20, 1992, among MarkWest Hydrocarbon Partners, Ltd., Norwest Bank Denver, National Association, individually and as Agent, and First American National Bank (Filed as exhibit 10.21 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.3 Modification Agreement, dated July 31, 1996, among MarkWest Hydrocarbon Partners, Ltd., MarkWest Hydrocarbon, Inc., Norwest Bank Colorado, N.A., First American National Bank N M Rothschild and Sons Limited and Norwest (Filed as exhibit 10.2 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.4 Amended and Restated Mortgage, Assignment, Security Agreement and Financing Statement, dated May 2, 1996, between West Shore Processing Company, L.L.C. and Bank of America Illinois (Filed as exhibit 10.3 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.5 Secured Guaranty, dated May 2, 1996, between West Shore Processing Company LLC and Bank of America Illinois (Filed as exhibit 10.4 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.6 Security Agreement, dated May 2, 1996, between West Shore Processing Company L.L.C. and Bank of America Illinois (Filed as exhibit 10.5 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.7 Pledge Agreement, dated May 2, 1996, between West Shore Processing Company, L.L.C. and Bank of America Illinois (Filed as exhibit 10.6 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.8 Participation, Ownership and Operating Agreement for West Shore Processing Company, L.L.C. dated May 2, 1996 (Filed as exhibit 10.7 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.9 Second Amended and Restated Operating Agreement for Basin Pipeline L.L.C., dated May 2, 1996 (Filed as exhibit 10.8 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.10 Subordination Agreement, dated May 2, 1996, among MarkWest Michigan LLC, Bank of America Illinois, West Shore Processing Company, L.L.C., Basin Pipeline L.L.C., Michigan Energy Company, L.L.C. (Filed as exhibit 10.9 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.11 Gas Treating and Processing Agreement, dated May 1, 1996, between West Shore Processing Company, LLC and Shell Offshore, Inc. (Filed as exhibit 10.10 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.12 Gas Gathering, Treating and Processing Agreement, dated May 2, 1996, between Oceana Acquisition Company and West Shore Processing Company, LLC (Filed as exhibit 10.11 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.13 Gas Gathering, Treating and Processing Agreement, dated May 2, 1996, between Michigan Production Company, L.L.C. and West Shore Processing Company, LLC(Filed as exhibit 10.12 to 41 MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.14 Products Exchange Agreements, dated May 1, 1996, with Ferrellgas, L.P. (Filed as exhibit 10.13 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.15 Gas Processing and Treating Agreement, dated March 29, 1996, between Manistee Gas Limited Liability Company and Michigan Production Company, L.L.C. (Filed as exhibit 10.14 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.16 Processing Agreement (Kenova Processing Plant), dated March 15, 1995, between Columbia Gas Transmission Corporation and MarkWest Hydrocarbon Partners, Ltd. (Filed as exhibit 10.15 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.17 Natural Gas Liquids Purchase Agreement (Cobb Plant), between Columbia Gas Transmission Corporation and MarkWest Hydrocarbon Partners, Ltd. (Filed as exhibit 10.16to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.18 Purchase and Demolition Agreement Construction Premises, dated March 15, 1995, between Columbia Gas Transmission Corporation and MarkWest Hydrocarbon Partners, Ltd. (Filed as exhibit 10.17 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.19 Purchase and Demolition Agreement Remaining Premises, dated March 15, 1995, between Columbia Gas Transmission Corporation and MarkWest Hydrocarbon Partners, Ltd. (Filed as exhibit 10.18 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.20 Agreement to Design and Construct New Facilities, dated March 165, 1995, between Columbia Gas Transmission Corporation and MarkWest Hydrocarbon Partners, Ltd. (Filed as exhibit 10.19 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.21 Sales Acknowledgment, dated August 8, 1994, NO. 12577, confirming sale to Ashland Petroleum Company (Filed as exhibit 10.20 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.22 Contract for Construction and Lease of Boldman Plant, dated December 24, 1990, between Columbia Gas Transmission Corporation and MarkWest Hydrocarbon partners, Ltd. (Filed as exhibit 10.22 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.23 Natural Gas Liquids Purchase Agreement (Boldman Plant), dated December 24, 1990, between Columbia Gas Transmission Corporation and MarkWest Hydrocarbon Partners, Ltd. (Filed as exhibit 10.23 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.24 Natural Gas Liquids Purchase Agreement, dated April 26, 1988, between Columbia Gas Transmission Corporation and MarkWest Hydrocarbon Partners, Ltd. (Filed as exhibit 10.24 to 42 MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.25 1996 Incentive Compensation Plan (Filed as exhibit 10.25 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.26 1996 Stock Incentive Plan (Filed as exhibit 10.26 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.27 1996 Nonemployee Director Stock Option Plan (Filed as exhibit 10.27 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.28 Form of Non-Compete Agreement between John M. Fox and MarkWest Hydrocarbon, Inc. (Filed as exhibit 10.28 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No. 333-09513 and incorporated herein by reference). 10.29 Sales Acknowledgment by Ashland Petroleum, 54 million gallons of Normal Butane, dated September 9, 1996. 10.30 Sales Acknowledgment by Ashland Petroleum, 19.5 million gallons of Isobutane, dated September 9, 1996. 10.31 Pipeline Construction and Operating Agreement between Michigan Production Company, L.L.C. and West Shore Processing Company, L.L.C., dated October 1, 1996. 10.32 Non-Recourse Loan Agreement between Michigan Production Company, L.L.C. and West Shore Processing Company, L.L.C., dated October 1, 1996. 10.33 First Amendment to Participation, Ownership and Operating Agreement for West Shore Processing Company, L.L. C., dated October 1, 1996. 10.34 Option and Agreement to Purchase and Sell Pipeline, dated October 1, 1996. 10.35 Mortgage, Assignment, Security Agreement and Financing Statement from Michigan Production Company, L.L.C. to West Shore Processing Company, L.L.C., dated October 22, 1996. 10.36 Amendment to Participation, Ownership and Operating Agreement for West Shore Processing Company, L.L.C., dated December 12, 1996. 10.37 Assignment and Bill of Sale by and between Enron Gas Processing Company and West Shore Processing Company, L.L.C., dated January 13, 1997. 11. Statement regarding computation of per share 21. List of Subsidiaries of MarkWest Hydrocarbon, Inc. 23. Consent of Price Waterhouse LLP, independent accountants 43 SIGNATURES Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Englewood, State of Colorado on March 24, 1997. MarkWest Hydrocarbon, Inc. (Registrant) BY: /s/ John M. Fox ------------------------- John M. Fox President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. /s/ John M. Fox March 24, 1997 --------------------------------- John M. Fox President, Chief Executive Officer and Director /s/ Brian T. O'Neill March 24, 1997 --------------------------------- Brian T. O'Neill Senior Vice President, Chief Operating Officer and Director /s/ Rita E. Harvey March 24, 1997 --------------------------------- Rita E. Harvey Director of Finance and Treasurer (Principal Financial and Accounting Officer) /s/ Arthur J. Denney March 24, 1997 --------------------------------- Arthur J. Denney Director /s/ Norman H. Foster March 24, 1997 --------------------------------- Norman H. Foster Director /s/ Barry W. Spector March 24, 1997 --------------------------------- Barry W. Spector Director /s/ David R. Whitney March 24, 1997 --------------------------------- David R. Whitney Director 44