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