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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 [ Fee Required ] for the fiscal year ended December 31, 1997.
[_] Transition report pursuant to section 13 or 15(d) of the Securities
Exchange Act of 1934 [No Fee Required] for the transition period from
__________ to ____________.
COMMISSION FILE NUMBER 1-11566
MARKWEST HYDROCARBON, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 84-1352233
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
155 INVERNESS DRIVE WEST, SUITE 200, ENGLEWOOD, CO 80112-5004
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 303-290-8700
Securities registered pursuant to Section 12(b) of the Act: NONE
Securities registered pursuant to Section 12(g) of the Act: COMMON STOCK, $0.01
PAR VALUE
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No ___
---
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. ___
The aggregate market value of voting common stock held by non-affiliates of the
registrant on March 13, 1998 was $78,796,221.
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 21, 1998.
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MARKWEST HYDROCARBON, INC.
FORM 10-K
TABLE OF CONTENTS
Page
----
PART I
Items 1. and 2. Business and Properties
General............................................................ 3
Appalachian Core Area.............................................. 3
Michigan Core Area................................................. 5
Sales and Marketing................................................ 6
Competition........................................................ 6
Exploration and Production......................................... 7
Operational Risks and Insurance.................................... 7
Governmental Regulation............................................ 8
Environmental Matters.............................................. 9
Employees.......................................................... 9
Risk Factors....................................................... 9
Item 3. Legal Proceedings.............................................. 10
Item 4. Submission of Matters to a Vote of Security Holders............ 10
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters.................................................. 10
Item 6. Selected Financial Data........................................ 10
Item 7. Management's Discussions and Analysis of Financial Condition
and Results of Operation............................................. 12
Item 8. Financial Statements and Supplementary Data.................... 18
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.................................. 32
PART III
Item 10. Directors and Executive Officers of the Registrant............ 32
Item 11. Executive Compensation........................................ 32
Item 12. Security Ownership of Certain Beneficial Owners and
Management........................................................... 33
Item 13. Certain Relationships and Related Transactions................ 33
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K............................................................. 33
<PAGE>
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
GENERAL
MarkWest Hydrocarbon, Inc. (the "Company" or "MarkWest") is engaged in natural
gas processing and related services. The Company, which has grown substantially
since its founding in 1988, is the largest processor of natural gas in
Appalachia, and in 1996, established a venture to provide natural gas
transportation and processing services in western Michigan. The independent gas
processing industry has expanded rapidly in the last 10 years, and the Company
believes there will be significant opportunities to grow its gas processing
operations within these existing core regions and in new markets. The Company
provides compression, gathering, treatment and natural gas liquids ("NGL")
extraction services to natural gas producers and pipeline companies and
fractionates NGLs into marketable products for sale to third parties. The
Company also purchases, stores and markets natural gas and NGLs and conducts
strategic exploration for new natural gas sources for its processing and
fractionation activities.
The Company's processing and marketing operations 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") and the developing basin in western Michigan (the "Michigan Core
Area"). At the Company's processing plants, natural gas is treated to remove
contaminants and NGLs are extracted and fractionated into propane, normal
butane, isobutane and natural gasoline. The Company then markets the
fractionated NGLs to refiners, petrochemical companies, gasoline blenders,
multistate and independent propane dealers and propane resellers. In addition to
processing and NGL marketing, the Company engages in terminalling and storage of
NGLs in a number of NGL storage complexes in the central and eastern United
States and operates propane terminals in Arkansas and Tennessee.
1997 was a year of expansion and growth for MarkWest. In Michigan, the Company
completed an extension to its pipeline, constructed an NGL plant, and in
November, increased its interest in the Michigan project from 60 percent to 100
percent. In connection with the Company's expanded infrastructure in Michigan,
drilling activity in the area continues to increase. Volumes through the
Company's gas pipeline and plant in Michigan increased to between thirteen and
fourteen million cubic feet per day ("mmcf/d") in the second half of 1997, and
are expected to continue to increase with new discoveries. A pipeline extension
and plant expansion are planned for 1998 to accommodate further increases in
volumes.
The Company's principal offices are located at 155 Inverness Drive West, Suite
200, Englewood, Colorado, 80112-5004, and its telephone number is (303) 290-
8700. The Company was incorporated in Delaware in 1996. As used herein, the
Company refers to MarkWest Hydrocarbon, Inc. and its fully consolidated
subsidiaries.
APPALACHIAN CORE AREA
<TABLE>
<CAPTION>
YEAR
ACQUIRED GAS NGL PRODUCTION
OR PLACED THROUGHOUT THROUGHPUT THROUGHPUT
INTO SERVICE CAPACITY (MCF/D)/A,B/ (GAL/YEAR)/B/
-------------------------------------------------------------
<S> <C> <C> <C> <C>
Processing Plants
Kenova Extraction Plant,
Wayne County, WV 1996 120,000 mcf/d 120,000 68,551,000
Boldman Extraction Plant,
Pike County, KY 1991 70,000 mcf/d 50,000 9,068,000
Siloam Fractionation Plant,
South Shore, KY 1988 360,000 Gal/d N/A 102,453,000
PIPELINE
38.5 mile NGL pipeline Wayne
County, WV to South Shore, KY 1988 350,000 Gal/d N/A 68,551,000
</TABLE>
<TABLE>
<CAPTION>
YEAR ACQUIRED STORAGE
OR PLACED CAPACITY ANNUAL SALES
INTO SERVICE (GAL) (GAL/YEAR)B
------------------------------------------
<S> <C> <C> <C>
TERMINAL AND STORAGE
Siloam Fractionation Storage, South Shore, KY 1988 14,000,000 103,424,000
Terminal and Storage, West Memphis, AR 1992 2,500,000 26,049,000
Terminal and Storage, Church Hill, TN 1995 240,000 4,283,000
</TABLE>
____________
/a/ mcf/d = thousand cubic feet per day
/b/ For the year ended December 31, 1997.
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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 situated
between the TET pipeline to the north and the Dixie pipeline to the south. The
demand for NGL products in Appalachia exceeds local production and the capacity
of these two lines during peak winter periods. This factor enables NGL
suppliers in Appalachia (principally MarkWest, Ashland Oil Company and CNG
Transmission Corporation) to price their products (particularly propane) at a
premium to Gulf Coast spot prices during times of supply shortages from other
sources, especially during winter high demand periods.
Plants. The Kenova natural gas liquids extraction plant, which is situated on a
main transmission line of Columbia Gas Transmission Corporation ("Columbia"),
replaced a 1958 extraction facility owned and operated by Columbia. The new
facility generates fee revenue related to the processing operations, generates
greater NGL recovery from natural gas, and has reduced downtime for maintenance
and significantly reduced fuel costs compared to the replaced facility. 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 which 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 over 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 British thermal units ("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 the exclusive right to process hydrocarbon-
rich gas delivered into Columbia's transmission pipelines through 2010.
Existing NGL purchase agreements with Columbia for Boldman and Cobb have a term
into 2003.
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.
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MICHIGAN CORE AREA
<TABLE>
<CAPTION>
YEAR ACQUIRED GAS NGL PRODUCTION
OR PLACED THROUGHOUT THROUGHPUT THROUGHPUT
INTO SERVICE CAPACITY (MCF/D)/A,B/ (GAL/YEAR)/B/
---------------------------------------------------------
<S> <C> <C> <C> <C>
Pipeline
63 mile sour gas gathering pipeline,
Manistee, Mason and Oceana Counties, MI 1996 35,000 mcf/d 8,900 N/A
PROCESSING PLANT
Fisk Gas Plant, Manistee County, MI 1998 50,000 mcf/d -- --
</TABLE>
____________
/a/ mcf/d = thousand cubic feet per day
/b/ For the year ended December 31, 1997.
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
project provides natural gas gathering, treatment, processing and NGL marketing
in Manistee, Mason and Oceana Counties in Michigan. The Company began to earn
an interest in the project by funding various capital programs, principally a
pipeline extension. 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 its
western Michigan project 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
Phase I of the Michigan project, which included the construction of a 32 mile
extension to the previously existing 31 mile pipeline. This extension, which
provides an outlet for sour gas production from previously shut-in wells, as
well as for gas from new wells to be drilled, was built and is currently being
operated by the Company on behalf of a producer, Michigan Production Company,
L.L.C. ("MPC"). In March 1998, the Company received approval from the Michigan
Public Service Commission to convert the pipeline from a producer pipeline to a
common carrier pipeline, and plans to acquire the pipeline from MPC in exchange
for the forgiveness of a note owed to the Company by MPC. The Company will
operate the pipeline to gather gas from additional wells in Mason and Oceana
counties.
Drilling activities are increasing considerably along the route of the MarkWest
pipeline because of recent discoveries and the pending approval of further
pipeline extensions. MarkWest is participating in exploration activities in the
region, holding a 17.5 percent working interest in a recently completed seismic
program, with drilling of the first of four wells expected to start in the
second quarter of 1998. A second group of companies started drilling in the
first quarter of 1998 following their 3-D seismic program which covered 50
square miles. No results have been reported to date. A third producer is
planning a four well program for 1998 following its two recent successful wells,
which have a combined deliverability of 16 mmcf/d, adding to the region's shut-
in gas wells capability of 7 mmcf/d. Drilling success in these three programs
would add significantly to the Company's pipeline and NGL throughput.
By mid-1998, MarkWest plans to extend the pipeline to connect to the new and
existing shut-in wells, which will add 23 mmcf/d in the second half of 1998.
Permitting activities for this extension are nearly complete, with approval
received in the first quarter of 1998 for the first part of the extension, and
approval of the remaining segment expected in the second quarter of 1998.
Natural Gas Liquids Plant. In December 1997, the Company began final testing
and partial operations at the Fisk Gas Plant, a 50 mmcf/d liquids extraction and
fractionation facility. 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. Engineering and procurement efforts have commenced to expand pipeline
and treating capacity to 50 mmcf/d from 35 mmcf/d, when volumes require. The
plant also conditions residue gas such that it can be sold directly into the
Michigan Consolidated Gas Company dry distribution system serving western
Michigan.
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
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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 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 and natural gas sold.
The Company has exclusive gathering, treatment and processing agreements with
four companies: MPC, Dominion Midwest Energy, Inc. ("Dominion"), Oceana
Exploration and Production Company, LC ("Oceana") and Longwood Exploration
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 will be processed at the Company's Fisk Gas Plant.
The terms of these agreements with each company are as follows: MPC, through
2016; Dominion, for 25 years from the date of initial delivery, which is
anticipated in 1998, depending on exploration success; Longwood, 25 years from
the date of initial delivery, which is anticipated in 1998, depending on
exploration success. Oceana has committed to drill four 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.
Shell Treatment and Processing Agreement. To provide sulfur treatment for
natural gas dedicated to the project, 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. In December 1997, the Company exercised its option
to request that Shell expand the Shell treating plant to handle 55 mmcf/d.
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 truck and tank car fleet, as well as its
own terminals and storage facilities, to enhance supply reliability to its
customers. All of these efforts have allowed the Company to maintain premium
pricing of its NGL products compared to Gulf Coast spot prices.
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. In 1998 and beyond, an increasing portion of the Company's revenues is
expected to be derived from transportation and treating revenues from the
Company's Michigan operations, as production volumes and throughput in Michigan
are expected to grow significantly, beginning in the second half of 1998.
Revenues from the sale of NGLs represented 83%, 91% and 98% of total revenues in
1997, 1996 and 1995, respectively. The Company markets and sells NGLs to
numerous customers, including refiners, petrochemical companies, gasoline
blenders, multistate and independent propane distributors and propane resellers.
The majority of the Company's sales of NGLs are based on spot prices at the time
the NGLs are sold. Spot market prices are based upon prices and volumes
negotiated for short terms, typically 30 days.
COMPETITION
The Company faces intense competition in obtaining natural gas supplies for its
gathering and processing operations, in obtaining processed NGLs for
fractionation and in marketing its products and services. The Company's
principal competitors include major integrated oil and gas companies, major
interstate pipeline companies, NGL processing companies and national and local
gas gatherers, brokers, marketers and distributors of varying sizes, financial
resources and experience. Many of the Company's competitors, such as major oil
and gas and pipeline companies, have capital resources and control supplies of
natural gas substantially greater than those of the Company. Smaller local
distributors may enjoy a marketing advantage in their immediate service areas.
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The Company competes against other companies in its gas processing business both
for supplies of natural gas and for customers to which it sells its products.
Competition for natural gas supplies is based primarily on location of gas
gathering facilities and gas processing plants, operating efficiency and
reliability, and ability to obtain a satisfactory price for products recovered.
Competition for customers is based primarily on price, delivery capabilities,
and maintenance of quality customer relationships.
The Company's fractionation business competes against other fractionation
facilities that serve local markets. Competitive factors affecting the Company's
fractionation business include proximity to industry marketing centers and
efficiency and reliability of service.
In marketing its products and services, the Company has numerous competitors,
including interstate pipelines and their marketing affiliates, major producers,
and local and national gatherers, brokers, and marketers of widely varying
sizes, financial resources and experience. Marketing competition is primarily
based upon reliability, transportation, flexibility and price.
EXPLORATION AND PRODUCTION
The Company maintains a strategic gas exploration effort intended to permit the
Company to gain a foothold position in production areas that have strong
potential to create demand for its processing services. The Company currently
owns interests in several exploration and production assets. Such assets include
the following:
. A 49% undivided interest in two separate exploration and production projects
in La Plata County, Colorado, producing from the Fruitland Formation coal
seam. Current projects contain fourteen coal seam wells that produce
approximately 1,300 mcf/d of natural gas. To date, all development has
occurred on a 320 acre spacing. Due to recent Colorado Oil & Gas Conservation
Commission (the "Commission") rulings, the right to infil each drill block is
now available to MarkWest, subject to certain approval by the Commission and
the Ute Indian Tribe. Upon receiving such approval, MarkWest has the right to
drill up to four additional wells in its Alamo project and up to fourteen
additional wells in its Tiffany project. Thus, additional developments are
expected to occur in 1998 and 1999 through the infilling of operated
drillblocks.
. A 5.4% working interest in a 66 well drilling program operated by Conley
Smith, Denver, Colorado. Well sites are in Oklahoma, Kansas, Nevada, Texas
and Wyoming. MarkWest believes it may have a future opportunity to provide
its processing expertise to Conley Smith in the areas with successful
drilling sites. There can be no assurance, however, that Conley Smith will
use the Company's processing services.
. A 25% working interest in a 31,000 acre project to be developed in the
Piceance Basin of Colorado. The project includes both the exploration for
conventional natural gas and the development of the Cameo Coal Formation
utilizing existing well bores. While there can be no assurance that these
projects will generate substantial natural gas volumes, MarkWest believes
that this area could generate increased demand for processing services.
. A 17.5% working interest in the drilling program of the Niagaran Reef Trend
in the Michigan Core Area. As a non-operator, MarkWest participated in a 28
square mile three-dimensional seismic survey in an Area of Mutual Interest.
Seismic processing and interpretation directed a focused acreage acquisition
program over specific targeted Reef mounds through 1997. Drilling activities
are planned in 1998.
OPERATIONAL RISKS AND INSURANCE
The Company's operations are subject to the usual hazards incident to the
exploration for and production, transmission, processing and storage of natural
gas and NGLs, such as explosions, product spills, leaks, 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
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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 (the "Decontrol Act"). Thus, all sales by the
Company of natural gas currently can be made at uncontrolled market prices.
There can be no assurance, however, that Congress will not reenact price
controls in the future which could apply to, or substantially affect, these
sales activities.
The processing of natural gas for the removal of liquids by non-pipeline
companies currently is not 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.
As part of the Michigan Project, the Company owns and operates pipeline
gathering facilities in conjunction with its processing plant. Under the NGA,
facilities which 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. The pipeline affiliate is presently seeking regulatory
approval from the MPSC in connection with a proposed extension to the existing
pipeline system in Michigan. The proceeding is in its initial stages and a
schedule for further proceedings has been established. The requested approval
is not opposed by any party to the proceeding
The design, construction, operation, and maintenance of the Company's NGL and
natural gas pipeline facilities are subject to the safety regulations
established by the Secretary of the Department of Transportation pursuant to the
Natural Gas Pipeline Safety Act of 1968, as amended ("1968 Act"), or by state
agency regulations which meet or exceed the requirements of the 1968 Act.
The Company's natural gas exploration and production operations are subject to
various types of regulation at the federal, state and local levels. Such
regulation includes requiring permits for the drilling of wells, meeting bonding
requirements in order to drill or operate wells and regulating the location of
wells, the methods of drilling and casing wells, the surface use and restoration
of properties upon which wells are drilled, the plugging and abandoning of wells
and the disposal of fluids used in connection with such operations. Production
operations are also subject to various conservation laws and regulations. These
typically include the regulation of the size of drilling and spacing or
proration units and the density of wells which may be drilled therein and the
unitization or pooling of oil and gas properties. Whether the state has forced
pooling, or integration of smaller tracts to form a tract large enough to
conduct drilling operations, or relies only on voluntary pooling can affect the
ease with which a property can be developed. State conservation laws also
typically establish maximum rates of production of natural gas, generally
prohibit the venting or flaring of gas and impose certain requirements regarding
the ratability of production and the handling of nonhydrocarbon gases, such as
carbon dioxide and hydrogen sulfide. The effect of these regulations may limit
the amount of oil and gas available to the Company or which the Company can
produce from its wells. They also substantially affect the cost and
profitability of conducting natural gas exploration and production activities.
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
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the natural gas industry. It remains unclear what impact, if any, increased
competition within the natural gas industry under Order No. 636 will have on the
Company or its various lines of business. Additionally, the FERC has issued a
number of other orders which are intended to supplement various facets of its
open access program, all of which will continue to affect how and by whom
natural gas production and associated NGLs will be transported and sold in the
marketplace. In its current form, FERC's open access initiatives could provide
the Company with additional access to gas supplies and markets and could assist
the Company and its customers by mandating more fairly applied service rates,
terms and conditions. On the other hand, it could also subject the Company and
entities with 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 the acquisition of a permit or
other authorization before certain activities may be conducted by the Company.
These laws also include fines and penalties for non-compliance. Further, these
laws and regulations may limit or prohibit activities on certain lands lying
within wilderness areas, wetlands, areas providing habitat for certain species
or other protected areas. The Company is also subject to other federal, state,
and local laws covering the handling, storage or discharge of materials used by
the Company, or otherwise relating to protection of the environment, safety and
health. The Company believes that it is in material compliance with all
applicable environmental laws and regulations.
EMPLOYEES
As of December 31, 1997, the Company had 96 employees.
Twelve employees at the Company's Siloam fractionation facility in South Shore,
Kentucky, are represented by the Oil, Chemical and Atomic Workers International
Union, Local 3-372 (Siloam Sub-Local). The Company's collective bargaining
agreement with this Union expires on April 30, 2000. The agreement covers only
hourly, nonsupervisory employees. The Company considers labor relations to be
satisfactory at this time.
RISK FACTORS
This Annual Report on Form 10-K contains statements which, to the extent that
they are not recitations of historical fact, constitute "forward-looking
statements" within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities and Exchange Act of 1934. All forward-looking
statements involve risks and uncertainties. The forward-looking statements in
this document are intended to be subject to the safe harbor protection provided
by Sections 27A and 21E. Factors that most typically impact the Company's
operating results and financial condition include (i) changes in general
economic conditions in regions in which the Company's products are located, (ii)
the availability and prices of NGLs and competing commodities, (iii) the
availability of raw natural gas supply, (iv) the ability of the Company to
negotiate favorable marketing agreements, (v) the risks that natural gas
exploration and production activities will not be successful, (vi) the Company's
dependence on certain significant customers, (vii) competition from other NGL
processors, including major oil and gas companies, and (viii) the Company's
ability to identify and consummate acquisitions complementary to its
9
<PAGE>
business. For discussions identifying other important factors that could cause
actual results to differ materially from those anticipated in the forward-
looking statements, see the Company's Securities and Exchange Commission
filings; and "Management's Discussion and Analysis of Financial Condition and
Results of Operations" of this Form 10-K.
ITEM 3. LEGAL PROCEEDINGS
In February 1998, MarkWest filed arbitration proceedings to resolve issues with
Columbia regarding three natural gas processing plants in Appalachia. In this
arbitration, MarkWest requests a declaration of rights and status to clarify
agreements between the companies.
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.
MarkWest's intention in taking over operations at these plants is to assist
Columbia in their rate settlement and to possibly increase its liquids
processing business on Columbia's transmission system. The initial economic
effect in taking over operations is neutral. Columbia and MarkWest continue to
have several ongoing contracts, the most important of which extends through the
year 2010. Although the outcome of arbitration or the length of the process
cannot be predicted, the Company anticipates that the arbitration will have a
minimal effect on MarkWest in the interim.
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, 1997.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
As of March 13, 1998, there were 8,498,613 shares of common stock outstanding
held by 555 holders of record. The common stock is traded on The Nasdaq Stock
Market under the symbol "MWHX". The following table sets forth quarterly high
and low closing sales prices as reported by the Nasdaq National Market for the
periods indicated.
HIGH LOW
------ -------
1997
Fourth Quarter................................ 23 1/2 19 1/2
Third Quarter................................. 23 1/2 14 3/4
Second Quarter................................ 15 1/4 12
First Quarter................................. 16 1/8 14 1/16
1996
Fourth Quarter (1)............................ 15 1/2 10 1/4
(1) The Company's initial public offering was completed on October 9, 1996.
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, 1997, 1996 and 1995 and as of December 31, 1997 and
1996 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, 1994 and 1993 and as of December 31, 1995,
1994 and 1993 have been derived from audited financial statements not included
in this Form 10-K. The selected consolidated financial information set forth
below should be read in conjunction with "Management's Discussion and Analysis
of Financial Condition and Results of Operations" and the Company's Consolidated
Financial Statements and related notes thereto included elsewhere in this Form
10-K.
10
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31,
1997 (4) 1996 1995 1994 1993
--------- -------- --------- -------- --------
(in thousands, except per share data)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS:
Revenues....................................... $ 79,917 $71,952 $48,226 $52,963 $55,871
Income (loss) before taxes, extraordinary
item and cumulative effect of change in
accounting.................................... 12,397 14,760 7,824 5,120 540
Provision for income taxes..................... 4,550 6,991 -- -- --
Income before extraordinary loss............... 7,847 7,769 7,824 5,120 540
Extraordinary loss............................. -- -- (1,750) -- --
Net income..................................... 7,847 7,769 6,074 5,120 540
Basic earnings per share (historical 0.92 1.21 1.06 0.89 0.09
information; see note 1 for pro forma
information assuming the Company had been a
taxable entity)...............................
Earnings per share assuming dilution 0.91 1.20 1.06 0.89 0.09
(historical information; see note 1 for pro
forma information assuming the Company had
been a taxable entity)........................
Weighted average shares outstanding (2)........ 8,485 6,415 5,725 5,725 5,725
BALANCE SHEET DATA
(AS OF DECEMBER 31):
Total assets................................... $ 98,657 $78,254 $46,896 $35,913 $40,668
Long-term debt................................. 33,931 11,257 17,500 9,887 16,486
Partners' capital.............................. -- -- 25,161 22,183 17,350
Stockholders' equity........................... 51,548 43,664 -- -- --
OPERATING DATA:
Appalachia:
NGL production - Siloam (gallons)............ 102,453 94,909 92,239 99,735 93,355
NGLs marketed - Siloam (gallons)............. 103,424 94,595 95,484 97,848 92,722
Fee gas processed (mmbtu) (3)................ 57,973 33,900 -- -- --
Terminal throughput (gallons)................ 30,332 37,851 31,206 32,665 30,117
Michigan pipeline throughput (mcf)............. 3,247 1,161 -- -- --
Gas production (mcf)........................... 434 116 N/M 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 1993
------- ------ ------ ------
<S> <C> <C> <C> <C>
Historical income before income taxes $14,760 $7,824 $5,120 $ 540
Pro forma provision for income taxes 5,609 2,937 1,424 228
Pro forma net income 9,151 4,887 3,696 312
Pro forma basic earnings per share 1.16 0.85 0.65 0.05
Pro forma earnings per share assuming dilution 1.15 0.85 0.65 0.05
Pro forma weighted average shares outstanding (a) 7,908 5,725 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 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
11
<PAGE>
average shares outstanding for the years ended December 31, 1995, 1994 and
1993 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, 1994 and 1993 represent the weighted
average number of common shares issued in the Reorganization.
(3) 1997 includes fee gas processed at the Boldman and Cobb plants, effective
February 1, 1997, as well as the fee gas processed at the Kenova plant.
(4) 1997 results reflect the Company's acquisition of the remaining 40 percent
interest of the Michigan project from MEC 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.
RESULTS OF OPERATIONS
- ----------------------
Year Ended December 31, 1997 Compared to Year Ended December 31, 1996 (in
thousands of dollars)
For the year ended December 31,
1997 1996 $ Change % Change
------- ------- -------- --------
Revenue $79,917 $71,952 $ 7,965 11%
Gross profit (a) 19,397 20,895 (1,498) (7%)
Income before income taxes 12,397 14,760 (2,363) (16%)
Provision for income taxes 4,550 6,991 (2,441) (35%)
------- ------- -------- --------
Net income 7,847 7,769 78 1%
======= ======= ======== ========
Pro forma information (b):
Income before income taxes 12,397 14,760 (2,363) (16%)
Provision for income taxes 4,550 5,609 1,059 19%
------- ------- -------- --------
Net income 7,847 9,151 (1,304) (14%)
======= ======= ======== ========
(a) Excludes interest income, general and administrative expense and interest
expense.
(b) 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 industry-wide 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.
REVENUES
Gathering, processing and marketing revenue. Gathering, processing and
marketing revenue increased $7.1 million or 10% 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.
Appalachian revenue was also positively affected by a 71% increase in fee gas
processed during 1997. 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
12
<PAGE>
arrangements effective in early 1997. In addition, the Company's Siloam plant
sold a record 103 million gallons in 1997, a nine percent 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 $570,000 or 164% 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 accrues interest at a rate of 5.98%. The
note, due from MPC, is for the costs incurred by the Company for the
construction of the 30 mile extension to the gas pipeline in Michigan.
COSTS AND EXPENSES
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 $3.9 million or 55% 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 36% 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 is
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.
YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995 (IN
THOUSANDS OF DOLLARS)
For the year ended December 31,
1996 1995 $ Change % Change
-------- -------- -------- --------
Revenue $71,952 $48,226 $23,726 49%
Gross profit (a) 20,895 12,365 8,530 69%
Income before income taxes 14,760 7,824 6,936 89%
Provision for income taxes 6,991 -- 6,991 (100%)
-------- -------- -------- --------
Net income 7,769 7,824 (55) (1%)
======== ======== ======== ========
13
<PAGE>
Pro forma information (b):
Income before income taxes 14,760 7,824 6,936 89%
Provision for income taxes 5,609 2,937 (2,672) (91%)
Net income 9,151 4,887 4,264 87%
======= ======= ======== ========
(a) Excludes interest income, general and administrative expense and interest
expense.
(b) 1996 and 1995 information are 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 and 1995 have been presented for purposes of comparability as if
MarkWest had been a taxable entity.
For the year ended December 31, 1996, income before income taxes was $14.8
million, compared to income before income taxes of $7.8 million, for the year
ended December 31, 1995. The increase in income before income taxes was
primarily a result of industry-wide strong NGL prices, which were at near record
levels in the fourth quarter of 1996, combined with a 21% increase in throughput
volumes at the Company's terminals in 1996 compared to 1995.
REVENUES
Gathering, processing and marketing revenue. Gathering, processing and
marketing revenue increased $23.4 million or 50% for the year ended December
31, 1996, compared to 1995, for a variety of reasons.
The Company's Appalachia operations accounted for the majority of the increase,
primarily as a result of price-related increases for all NGLs in the fourth
quarter of 1996, when NGL prices were at near record levels. These price
increases were complemented by the addition of the new terminal in Church Hill,
Tennessee, which was operational for a full year for the first time in 1996, and
an overall 21% increase in throughput volumes at the Company's propane
terminals, principally due to higher demand as a result of colder temperatures
during the first and fourth quarters of 1996.
Offsetting these favorable price and terminal volume increases was a volume
decrease at the Company's Siloam plant. The volume decrease at Siloam, which
receives approximately 70% of its raw NGL mix from the Kenova plant, was due to
start-up delays at the Company's new Kenova processing facility during the
first quarter of 1996. The new Kenova plant, which was placed into service in
January 1996, generated additional fee revenue in 1996 compared to 1995.
The remaining increase in gathering, processing and marketing revenue can be
attributed to the Company's new operations in Michigan, which commenced in May
1996.
COSTS AND EXPENSES
Cost of sales. Cost of sales increased $11.7 million or 40% for the year ended
December 31, 1996, compared to 1995. The Company's Appalachia operations
accounted for the majority of the increase, primarily as a result of increased
natural gas and propane prices, and due to an increase in volumes sold from the
Company's terminals.
Operating expenses. Operating expenses increased $2.3 million or 50% for the
year ended December 31, 1996, compared to 1995. This increase was partially due
to new operations at both the Kenova and Church Hill facilities, which commenced
operations in January 1996 and October 1995, respectively. The remaining
increase resulted from the Company's Michigan operations, which commenced in May
1996.
Depreciation, depletion and amortization expense. Depreciation, depletion and
amortization expense increased $1.2 million or 66% for the year ended December
31, 1996, compared to 1995, primarily as a result attributable to the Company's
new Kenova plant and Michigan operations.
Interest expense. Interest expense increased $582,000 for the year ended
December 31, 1996, compared to 1995. This increase resulted principally from
an increase in average outstanding long-term debt of $12.0 million for 1996
compared to $8.1 million for 1995.
Provision for income taxes. Provision for income taxes increased $7.0 million
for the year ended December 31, 1996, compared to 1995, as a result of the
Company's Reorganization from a partnership in October of 1996.
14
<PAGE>
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, 1997, 1996 and 1995:
For the year ended December 31,
1997 1996 1995
-------- -------- --------
Net cash provided by operating activities $ 4,885 $ 16,815 $ 5,436
Net cash used in investing activities (30,329) (17,516) (12,610)
Net cash provided by financing activities 22,536 4,341 2,467
For the year ended December 31, 1997, net cash provided by operating activities
before adjustments for working capital decreased $2.1 million from the prior
year, primarily as a result of a decrease in gross profit since 1996. The
Company's working capital accounts, excluding cash, increased $7.8 million in
the year ended December 31, 1997, in contrast to the decrease in working capital
accounts, excluding cash, of $2.1 million which occurred in the year ended
December 31, 1996. The change in working capital was driven by increases in
accounts receivable, prepaid feedstock and other current assets and decreases in
accounts payable and accrued liabilities, primarily related to tax payments made
in 1997, both of which were offset by a decrease in inventory levels in 1997.
Cash used in investing activities increased $12.8 million for the year ended
December 31, 1997 compared to 1996, primarily related to higher capital
expenditures made in 1997 (see further discussion under "Capital Investment
Program").
For the year ended December 31, 1997, cash provided by financing activities
increased $18.2 million compared to 1996. This increase was caused by
borrowings in 1997 to fund increased capital expenditures and working capital
requirements. Cash provided by financing activities increased $1.9 million for
the year ended December 31, 1996, as compared to the year ended December 31,
1995. This increase resulted primarily from the initial public offering in
October 1996, which was partially offset by payments made on long-term debt.
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 complete its current
capital expenditure program. 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, if required, no assurance can be given that it will be able to do so.
In November 1997, the Company acquired the remaining 40% interest in the
Michigan project from its partner for a purchase price of $8.5 million plus up
to $13.5 million in contingent payments. The future contingent payments consist
of nine payments ranging from $1.0 million to $2.7 million. The Company
believes that, if required to make any or all of the payments, cash flow
provided by operating activities, together with amounts available to be borrowed
under its financing facilities, will provide sufficient funds to cover the
contingent payments.
FINANCING FACILITIES
Effective June 20, 1997, the Company replaced its existing financing agreement
with a new credit facility (the "credit facility") with the Bank of Montreal, as
agent, NationsBank and Colorado National Bank. The credit facility, as amended
in December 1997, allows the Company to borrow up to $60.0 million, pursuant to
a revolving loan commitment. The revolving loan commitment converts to a
reducing loan commitment on May 31, 1999. The reducing loan commitment reduces
ratably on a quarterly basis to zero by June 20, 2003.
Interest rates are based on either the agent bank's prime rate plus 1% or the
London Interbank Offered Rate (LIBOR), plus an applicable margin of between 50
and 150 basis points, based on the Company's debt to capitalization ratio. At
December 31, 1997, approximately $33.9 million was outstanding. Of the total
outstanding, $31.9 million bears interest at 6.5% and $2.0 million bears
interest at 8.5%.
Effective January 14, 1998, the Company's wholly owned subsidiary, 155
Inverness, Inc., obtained a promissory note in the amount of $3.7 million with
Allianz Life Insurance Company, to finance the purchase of the Company's office
building, which was acquired on July 1, 1997.
15
<PAGE>
CAPITAL INVESTMENT PROGRAM
During 1997, the Company invested $19.3 million in capital expenditures,
including $9.1 million in Michigan. In addition, the Company spent $8.5 million
in Michigan to buy out its previous partner, and an additional $1.9 million for
the construction of the 30 mile gas pipeline extension in Michigan built on
behalf of MPC. During the year ended December 31, 1996, the Company invested
$9.8 million in capital expenditures, primarily in connection with the start up
of its Michigan operations, and an additional $7.7 million for the construction
of the gas pipeline extension in Michigan built on behalf of MPC . During 1995,
the Company expended $12.4 million in capital programs, $12.2 million of which
were incurred in connection with the construction of the Kenova plant.
The Company's capital investment program for 1998 is estimated at $24 million,
including $18 million in Michigan to fund a further extension of the pipeline
and expansion of the current system capacity. The remaining capital programs
for 1998 include $3 million for various projects in Appalachia, including a new
compressor at the Company's Kenova facility, and $3 million in exploration and
production activities.
1998 OUTLOOK
- ------------
Price levels in the fourth quarter of 1997 were fairly consistent with
historical, normal levels, as opposed to the near record high price levels
experienced in the fourth quarter of 1996. Propane prices rose dramatically in
the fourth quarter of 1996 due to an early cold start to the winter and a
Mexican plant explosion, which had a detrimental impact on imported propane
volumes into the United States. The Company was able to extend the benefit from
these high price levels by entering into various hedge contracts which
positively affected the Company's results in the first quarter of 1997. It is
expected that the results from the first quarter of 1998 will reflect price
levels below historical levels, and the outlook for the balance of the year
cannot be predicted. The sales price of natural gas liquids is correlated with
the price of crude oil, and crude oil prices have fallen significantly beginning
in the fourth quarter of 1997.
A significant portion of the Company's revenues, and as a result, its gross
margins, remain dependent upon the sales price of propane, which fluctuates with
the winter weather conditions and other supply and demand determinants.
Currently, MarkWest has an annual sensitivity to NGL prices equal to $1 million
in pretax income for every $0.01/gallon change in NGL prices and an annual
sensitivity to natural gas prices equal to $1 million in pretax income for every
$0.10/mmbtu change in natural gas prices.
The Company's future results are expected to be positively affected by volumes
through its sour gas pipeline and plant in Western Michigan, which more than
tripled to 13.2 mmcf/d in the fourth quarter of 1997 from 4.2 mmcf/d in the
fourth quarter of 1996. Drilling activities in the area are increasing
considerably because of recent discoveries and the pending approval of further
pipeline extensions. By mid-1998, MarkWest plans to extend the pipeline to
connect to new and existing shut-in wells, which will add 23 mmcf/d in the
second half of 1998. These increased volumes, along with the new NGL extraction
plant, which began operations in December 1997, are expected to add substantial
production volumes and related revenues to the Company's operations in the
second half of 1998 and beyond. The Company expects greater volumes to have a
substantial and positive impact on earnings and cash flow in 1998.
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 three-person committee of senior management
that oversees all hedging activity. Under internal guidelines, speculative
transactions are prohibited.
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 also 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.
16
<PAGE>
The Company had no material notional quantities of natural gas, NGL, or crude
oil futures, swaps or options at December 31, 1997. At December 31, 1996, the
Company had a total of 295 short and 135 long open propane futures contracts
representing a notional quantity amounting to 160,000 barrels of production.
Late in 1996, the Company entered into agreements with certain natural gas
suppliers for gas purchases (25,000 mmbtus a day) for the summer of 1997 at
differentials to crude oil futures and NGL baskets at December 31, 1996. There
were no material notional quantities of natural gas or crude oil futures or
options at December 31, 1996.
During the years ended December 31, 1997 and 1996, a $989,000 gain and a $1.1
million loss, 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. 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.
In the first quarter of 1998, the Company began its preliminary assessment of
the Year 2000 Issue. Many of the Company's computer systems are purchased from
third party vendors who have represented to the Company that they are Year 2000
compliant. 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, is expected to be completed by
the fourth quarter of 1998. The outcome of this analysis will be a formal Year
2000 plan and remediation, if any, is expected to be completed in 1999. 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 there
should be little impact to the Company's computer systems.
17
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Report of Independent Accountants..................................................... 18
Consolidated Balance Sheet at December 31, 1997 and 1996.............................. 19
Consolidated Statement of Operations for each of the three years ended
December 31, 1997........................................................... 20
Consolidated Statement of Cash Flows for each of the three years ended
December 31, 1997........................................................... 21
Consolidated Statement of Changes in Stockholders' Equity/ Partners'
Capital for each of the three years ended December 31, 1997................ 22
Notes to Consolidated Financial Statements............................................ 23
</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, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, 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.
PRICE WATERHOUSE LLP
Denver, Colorado
February 10, 1998
18
<PAGE>
MARKWEST HYDROCARBON, INC.
CONSOLIDATED BALANCE SHEET
(000S, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
December 31,
ASSETS 1997 1996
---------- ----------
<S> <C> <C>
Current assets:
Cash and cash equivalents.............................................................. $ 1,493 $ 4,401
Receivables, net of allowance for doubtful accounts of $120 and $0,
respectively......................................................................... 10,150 9,755
Inventories............................................................................ 5,141 5,632
Prepaid feedstock...................................................................... 2,690 1,831
Other assets........................................................................... 2,698 458
---------- ----------
Total current assets..................................................... 22,172 22,077
Property and equipment:
Gas processing, gathering, storage and marketing equipment............................ 58,794 46,416
Oil and gas properties and equipment................................................... 7,854 3,731
Land, buildings and other equipment.................................................... 9,363 4,478
Construction in progress............................................................... 5,258 5,831
---------- ----------
81,269 60,456
Less: accumulated depreciation, depletion and amortization............................ (15,439) (12,316)
---------- ----------
Total property and equipment, net........................................ 65,830 48,140
Intangible assets, net of accumulated amortization of $287 and $315,
respectively............................................................................ 555 380
Note receivable and other assets......................................................... 10,100 7,657
---------- ----------
Total assets............................................................................. $ 98,657 $ 78,254
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Trade accounts payable................................................................. $ 3,074 $ 5,382
Accrued liabilities.................................................................... 4,339 4,643
Current portion of long-term debt...................................................... 156 156
---------- ----------
Total current liabilities................................................ 7,569 10,181
Deferred income taxes.................................................................... 5,609 3,977
Long-term debt........................................................................... 33,931 11,257
Minority interest........................................................................ -- 9,175
Commitments and contingencies (Note 5)................................................... -- --
Stockholders' equity:
Preferred stock, par value $0.01; 5,000,000 shares authorized, 0 shares
issued and outstanding............................................................... -- --
Common stock, par value $0.01; 20,000,000 shares authorized, 8,523,285
and 8,485,000 shares issued, respectively............................................ 85 85
Additional paid-in capital............................................................. 42,729 42,237
Retained earnings...................................................................... 9,189 1,342
Treasury stock; 31,072 and 0 shares, respectively...................................... (455) --
---------- ----------
Total stockholders' equity............................................... 51,548 43,664
---------- ----------
Total liabilities and stockholders' equity............................................... $ 98,657 $ 78,254
========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
19
<PAGE>
MARKWEST HYDROCARBON, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(000S, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
For the Year Ended December 31,
1997 1996 1995
------- ------- -------
<S> <C> <C> <C>
Revenue:
Gathering, processing and marketing revenue......... $77,498 $70,405 $46,995
Oil and gas revenue................................. 917 347 1,075
Interest income..................................... 661 192 156
Other income........................................ 841 1,008 --
------- ------- -------
Total revenue..................................... 79,917 71,952 48,226
------- ------- -------
Costs and expenses:
Costs of sales...................................... 45,657 40,907 29,245
Operating expenses.................................. 10,956 7,048 4,706
General and administrative expenses................. 7,215 5,302 4,189
Depreciation, depletion and amortization............ 3,246 2,910 1,754
Interest expense.................................... 826 1,090 508
------- ------- -------
Total costs and expenses.......................... 67,900 57,257 40,402
------- ------- -------
Income before minority interest, income taxes and
extraordinary item.................................. 12,017 14,695 7,824
Minority interest in net loss of subsidiary........... 380 65 --
------- ------- -------
Income before income taxes and extraordinary item..... 12,397 14,760 7,824
Provision for income taxes:
Current............................................. 2,918 3,014 --
Deferred............................................ 1,632 232 --
Arising from reorganization......................... -- 3,745 --
------- ------- -------
Income before extraordinary item...................... 7,847 7,769 7,824
Extraordinary loss on extinguishment of debt.......... -- -- (1,750)
------- ------- -------
Net income........................................... $ 7,847 $ 7,769 $ 6,074
======= ======= =======
Basic earnings per share.............................. $ 0.92 $ 1.21 $ 1.06
======= ======= =======
Earnings per share assuming dilution.................. $ 0.91 $ 1.20 $ 1.06
======= ======= =======
Weighted average number of outstanding shares of
common stock....................................... 8,485 6,415 5,725
======= ======= =======
</TABLE>
The accompanying notes are an integral part of these financial statements.
20
<PAGE>
MARKWEST HYDROCARBON, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(000S)
<TABLE>
<CAPTION>
For the Year Ended December 31,
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income.................................................... $ 7,847 $ 7,769 $ 6,074
Add income items that do not affect working capital:
Depreciation, depletion and amortization.................. 3,246 2,910 1,754
Deferred income taxes..................................... 1,632 3,977 --
Option granted in conjunction with extinguishment of debt -- -- 1,050
(Gain) loss on disposition of assets...................... (75) 46 --
-------- -------- --------
12,650 14,702 8,878
Adjustments to working capital:
Increase in receivables................................... (1,485) (846) (4,729)
(Increase) decrease in inventories........................ 491 (2,802) (19)
Increase in prepaid expenses and other assets............. (3,099) (185) (86)
Increase (decrease) in accounts payable and accrued
liabilities........................................... (3,672) 5,946 1,392
-------- -------- --------
(7,765) 2,113 (3,442)
Net cash flow provided by operating activities......... 4,885 16,815 5,436
Cash flows from investing activities:
Capital expenditures...................................... (19,323) (9,824) (12,426)
Acquisition of interest in Michigan project............... (8,563) -- --
Increase in notes receivable and other assets............. (2,443) (7,692) (184)
-------- -------- --------
Net cash used in investing activities.................. (30,329) (17,516) (12,610)
Cash flows from financing activities:
Proceeds from issuance of long-term debt.................. 39,920 47,124 26,050
Repayments of long-term debt.............................. (17,246) (53,632) (19,437)
Debt issuance costs....................................... (175) -- --
Partners' distributions................................... -- (14,150) (4,150)
Payments on employee/partner notes........................ 192 320 --
Payments on options....................................... -- 71 4
Purchase of treasury stock................................ (455) -- --
Proceeds from issuance of common stock.................... 300 24,608 --
-------- -------- --------
Net cash provided by financing activities.............. 22,536 4,341 2,467
Net increase (decrease) in cash and cash equivalents... (2,908) 3,640 (4,707)
Cash and cash equivalents at beginning of year.................... 4,401 761 5,468
-------- -------- --------
Cash and cash equivalents at end of year.......................... $ 1,493 $ 4,401 $ 761
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
21
<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, 1994................ $ 22,183 -- -- $ -- $ -- $ -- $ -- $ 22,183
Net income........................ 6,074 -- -- -- -- -- -- 6,074
Distributions, net of
contributions.................... (4,146) -- -- -- -- -- -- (4,146)
Option granted in
conjunction with
extinguishment of
debt............................. 1,050 -- -- -- -- -- -- 1,050
--------- --------- -------- ------ ---------- -------- -------- -----------
Balance,
December 31, 1995................ 25,161 -- -- -- -- -- -- 25,161
Net income prior to
reorganization................... 6,427 -- -- -- -- -- -- 6,427
Notes receivable from
partners, net, 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............... 38 -- -- 300 -- -- 300
Acquisition of treasury
stock............................ -- (31) -- -- -- (455) (455)
--------- -------- ------ ---------- -------- -------- -----------
Balance,
December 31, 1997................ 8,523 (31) $ 85 $ 42,729 $ 9,189 $ (455) $ 51,548
========= ======== ====== ========== ======== ======== ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
22
<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 compression,
gathering, treatment, processing and natural gas liquids ("NGLs") extraction
services to natural gas producers and fractionates NGLs into marketable
products for sale to third parties. The Company also purchases, stores and
markets natural gas and NGLs and conducts strategic exploration for new natural
gas resources for its processing and fractionation activities. The Company's
processing and marketing operations are concentrated in two core areas: the
southern Appalachian region of eastern Kentucky, southern West Virginia and
southern Ohio; and western Michigan.
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 (the "Reorganization") and the existing general and
limited partners exchanged 100% of their interests in the Partnership for
5,725,000 common shares of the Company. An additional 2,760,000 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 Michigan Project
The Michigan project 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 project by funding various
capital programs, principally a 26 mile pipeline extension. 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 in the Michigan project from its partner, Michigan Energy
Company, L.L.C. ("MEC") 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,
1997 1996
-------- --------
Product inventory....................... $4,728 $5,292
Materials and supplies inventory........ 413 340
-------- --------
$5,141 $5,632
======== ========
23
<PAGE>
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Product inventory consists primarily of finished goods (propane, butane,
isobutane, natural gasoline and 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, 1997 and 1996 were $585,000 and $0, respectively. In addition, the
Company recorded a write-down of $251,000 related to firm commitments held at
December 31, 1997 for the purchase of natural gas inventory. Capitalized
overhead costs of $166,000 and $232,000 were included in product inventory at
December 31, 1997, and 1996, 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 at the lower of cost, using the first-in, first-out method,
or market. Prepaid feedstock write-downs at December 31, 1997 and 1996 were
$160,000 and $0, respectively.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is recorded at cost. Expenditures which extend
the useful lives of assets are capitalized. Repairs, maintenance and renewals
which do not extend the useful lives of the assets are expensed as incurred.
Interest costs for the construction or development of significant long-term
assets are capitalized and amortized over the related asset's estimated useful
life.
Depreciation is provided principally on the straight-line method over the
following estimated useful lives: plant facilities and pipelines, 20 years;
buildings, 40 years; furniture, leasehold improvements and other, 3-10 years.
Depreciation for oil and gas properties is provided for using the units-of-
production method.
Oil and gas properties consist of leasehold costs, producing and non-producing
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, 1997 and 1996,
approximately $967,000 and $649,000 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, 1997.
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 in 1997 or 1996 as a result of adopting SFAS No. 121.
INTANGIBLE ASSETS
Intangible assets consist of deferred financing costs which are amortized using
the straight-line method over the term of the associated agreement.
24
<PAGE>
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE RECEIVABLE
Note receivable at December 31, 1997 and 1996 consists of a note receivable (the
"Note") from Michigan Production Company, LLC ("MPC"). The Note is for the
costs incurred by the Company for the construction of the 31 mile extension to
the Basin pipeline. The Note bears an interest rate of 5.98% and is payable to
the Company on the earlier of two dates which are contingent upon certain events
as defined in the governing agreement.
HEDGING ACTIVITIES
The Company limits its exposure to natural gas and propane price fluctuations
related to future purchases and production with futures contracts. These
contracts are accounted for as hedges in accordance with the provisions of SFAS
No. 80, Accounting for Futures Contracts. Gains and losses on such hedge
contracts are deferred and included as a component of 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, 1997 and
1996, based on rates available for similar types of debt, the fair value of
long-term debt was not materially different from its carrying amount.
REVENUE RECOGNITION
Revenue for sales or services is recognized at the time the product is shipped
or at the time the service is performed.
INCOME TAXES
Deferred income taxes reflect the impact of "temporary differences" between
amounts of assets and liabilities for financial reporting purposes and such
amounts as measured by tax laws. These temporary differences are determined in
accordance with the liability method of accounting for income taxes as
prescribed by SFAS No. 109, Accounting for Income Taxes.
CONCENTRATION OF CREDIT RISK
Financial instruments which potentially subject the Company to concentrations of
credit risk consist principally of trade accounts receivable and note
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. The note receivable risk is limited
due to the fact that the note is secured by the pipeline extension. At December
31, 1997 and 1996, the Company had no significant concentrations of credit risk.
STOCK COMPENSATION
As permitted under SFAS No. 123, Accounting for Stock-Based Compensation, the
Company has elected to continue to measure compensation costs for stock-based
employee compensation plans as prescribed by Accounting Principles Board Opinion
No. 25, Accounting for Stock Issued to Employees. See Note 9 for the applicable
disclosures required by SFAS No. 123.
EARNINGS PER SHARE (EPS)
For the year ended December 31, 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 common share are determined by
dividing net income by the weighted-average number of common shares outstanding
during the year. Diluted earnings per common share are determined by dividing
net income by the weighted-average number of common shares and common stock
equivalents outstanding.
SUPPLEMENTAL CASH FLOW INFORMATION
Interest of $1.0 million, $1.0 million and $792,000 was paid during the years
ended December 31, 1997, 1996 and 1995, respectively. Interest paid in 1997 is
net of $557,000 capitalized in relation to various construction projects.
25
<PAGE>
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Income taxes of $7.0 million were paid during the year ended December 31, 1997.
There were no income taxes paid during the two years ended December 31, 1996
because of the Company's partnership status.
In 1996, non-cash investing activities included the contribution of Basin
Pipeline, LLC by Michigan Energy, LLC ("MEC") to the Company. MEC's
contribution was valued at approximately $9.2 million.
In 1996, non-cash financing activities included the purchase of certain assets
from the Dow Chemical Company ("Dow") by the assumption of a note valued at
approximately $421,000. As of December 31, 1997 and 1996, $187,000 and
$337,000, respectively, was outstanding under this note.
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 1997
presentation.
NOTE 3. DEBT
New Credit Facility. Effective June 20, 1997, the Company replaced its existing
financing agreements with a new credit facility (the "credit facility") with the
Bank of Montreal, as agent, NationsBank and Colorado National Bank. The credit
facility initially allowed the Company to borrow up to $55 million pursuant to a
revolving loan commitment. Effective December 24, 1997, the credit facility was
amended to increase the borrowing capacity to $60 million. The revolving loan
commitment converts to a reducing loan commitment on June 20, 1999. The
reducing loan commitment reduces ratably on a quarterly basis to zero by June
20, 2003.
The credit facility permits the Company to borrow money using either a base rate
loan or a London Interbank Offered Rate ("LIBOR") loan option. The base rate
loan accrues interest based on the agent bank's prime rate plus 1%. At December
31, 1997, approximately $2.0 million was outstanding under the base rate loan
option bearing interest at 8.5%. Alternatively, LIBOR loans accrue interest
based on the LIBOR, plus an applicable margin of between 50 and 150 basis
points, based upon the Company's debt to capitalization ratio. At December 31,
1997, approximately $31.9 million was outstanding under the LIBOR option bearing
interest at 6.5%.
The Company pays a commitment fee at the rate of 0.2% of 1% per annum on the
average daily unused commitment. 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 a new credit facility, the Company wrote off previously deferred financing
costs associated with the 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. ("155 Inverness"), obtained
separate financing for the purchase of an office building, which was acquired on
July 1, 1997. 155 Inverness entered into a promissory note (the "note") with
Allianz Life Insurance Company. The note is in the amount of $3.7 million and
it matures on February 10, 2003. Interest accrues on the note at the rate of
7.25%. The note is secured by the property's deed of trust and by a ten year
master lease with the Company.
Previous Loan Agreements. Prior to the establishment of the aforementioned
credit facility, the Company had two financing agreements with four financial
institutions. The first financing agreement was structured as a revolver loan
(the "revolver") and had a maximum borrowing base of $40 million. Terms of the
revolver dictated that the loan must be repaid by June 30, 2002, via 16 equal
quarterly installments commencing September 30, 1998. The second financing
arrangement was a working capital line of credit (the "line of credit") with a
maximum borrowing base of $7.5 million and a maturity date of June 30, 1998.
26
<PAGE>
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The revolver allowed the Company to borrow money using either a base rate or a
LIBOR loan option. Interest on the base rate loan was calculated based on the
prime rate and the Company's debt to capitalization ratio. At December 31,
1996, $4.2 million was outstanding under a base rate loan bearing interest at
8.5%. The LIBOR option allowed the Company to lock in a portion of the revolver
balance for a period of one, two, three or six months. Interest on the LIBOR
option was calculated based on the LIBOR and the Company's debt to
capitalization ratio. At December 31, 1996, $0 was outstanding under the LIBOR
commitment. Interest on the line of credit was calculated based on the prime
rate and the Company's debt to capitalization ratio. At December 31, 1996, $5.7
million was outstanding under the line of credit bearing interest at 8.5%.
The revolver was secured by a first mortgage on the Company's major assets. The
revolver restricted certain activities and required the maintenance of certain
financial ratios and other conditions. The Revolver/Term Loan was paid off in
full and canceled by the Company effective June 20, 1997. All amounts
outstanding under the line of credit were paid off on February 6, 1997. The
line of credit was also canceled by the Company effective June 20, 1997.
Resources' Revolver Loan. Resources, the Company's wholly-owned subsidiary, had
a revolving credit agreement with Colorado National Bank. As of December 31,
1996, $1.2 million was outstanding. The agreement was terminated by Resources
effective April 25, 1997.
Scheduled debt maturities under the terms of the facilities are as follows (in
000s):
At December 31, 1997
------------------------------------
Credit facility Subsidiary debt
--------------- ---------------
1998....................... $ - $156
1999....................... 6,357 31
2000....................... 8,476 -
2001....................... 8,476 -
2002 and thereafter........ 10,591 -
--------------- ---------------
Total...................... $33,900 $187
=============== ===============
NOTE 4. RELATED PARTY TRANSACTIONS
The Company, through its wholly-owned subsidiary, Resources, holds a varied
undivided interest in several exploration and production assets owned jointly
with MAK-J Energy, which owns a 51% undivided interest in such properties. The
general partner of MAK-J Energy 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
Energy. 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, 1997 and 1996, the Company has receivables due from MAK-J Energy for
approximately $790,000 and $0, and payables to MAK-J Energy for approximately
$202,000 and $62,000, respectively.
The Company made contributions of $271,000, $299,000 and $211,000 to a profit-
sharing plan for the years ended December 31, 1997, 1996 and 1995, 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 provide 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 for the greater of
accrued interest or excess distributions and are payable in full on October 8,
1999. Notes in the amounts of $167,000 and $376,000 have been recorded as a
reduction of additional paid-in capital at December 31, 1997 and 1996,
respectively. Purchase of Company stock with financing provided by the Company
was discontinued concurrent with the Company's public offering in October 1996.
27
<PAGE>
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5. COMMITMENTS AND CONTINGENCIES
In connection with the Company's acquisition of the remaining 40 percent
interest in its western Michigan project from its partner, MEC (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, and are contingent upon several factors,
including substantial sustained increases in system throughput volumes, ranging
from 45 million cubic feet per day ("mmcfd") to 75 mmcfd, 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, 1997, 1996 and 1995, sales to one customer
accounted for approximately 19%, 16% and 18% of total revenues. Management
believes the loss of this customer would not adversely impact operations, as
alternative markets are available.
NOTE 7. FINANCIAL DERIVATIVES
The Company uses futures contracts and fixed/floating price swaps to hedge its
commodity price risk. Gains and losses experienced on hedging transactions are
offset by the related gains or losses on the sale of the commodity. Under
internal guidelines, speculative positions are prohibited.
Futures. The Company enters into futures transactions on the New York
Mercantile Exchange ("NYMEX") and is subject to margin requirement deposits.
MarkWest protects margins by purchasing natural gas futures while simultaneously
selling propane futures of approximately the same British Thermal Unit ("BTU")
value. The Company also manages its commodity price risk on terminal propane
purchases and sales by purchasing and selling, respectively, propane futures
contracts. The Company had no material notional quantities of natural gas, NGL,
or crude oil futures, swaps or options at December 31, 1997. At December 31,
1996, the Company had a total of 295 short and 135 long open propane futures
contracts representing a notional quantity amounting to 160,000 barrels. Late
in 1996, the Company entered into agreements with certain natural gas suppliers
for gas purchases (25,000 mmbtus a day) for the summer of 1997 at differentials
to crude oil futures and NGL baskets at December 31, 1996. There were no
material notional quantities of natural gas or crude oil futures or options at
December 31, 1996.
During the years ended December 31, 1997 and 1996, a $989,000 gain and a $1.1
million loss, 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.
Swaps. The Company's wholly owned subsidiary, MarkWest Resources, Inc., 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, 1997,
Resources had three open swap agreements in place covering certain monthly
production through 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. No provision was recorded in 1995 as the
entity was a partnership.
The total income tax provision has been allocated as follows (in 000s):
Year ended December 31,
1997 1996
------ ------
Arising from Reorganization............. $ -- $3,745
Subsequent to Reorganization............ 4,550 3,246
------ ------
$4,550 $6,991
====== ======
28
<PAGE>
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The provision for income taxes subsequent to reorganization is comprised of
(000s):
<TABLE>
<CAPTION>
October 7
Year Ended through
December 31, 1997 December 31, 1996
----------------- -----------------
<S> <C> <C>
Current:
Federal........................................... $ 2,510 $ 2,616
State............................................. 408 398
----------------- -----------------
Total current..................................... 2,918 3,014
----------------- -----------------
Deferred:
Federal........................................... 1,419 212
State............................................. 213 20
----------------- -----------------
Total deferred.................................... 1,632 232
----------------- -----------------
Total tax provision............................... $ 4,550 $ 3,246
================= =================
<CAPTION>
The deferred tax liabilities (assets) are comprised of the tax effect of the
following:
1997 1996
----------------- -----------------
<S> <C> <C>
Property and equipment................................. $ 5,301 $ 3,667
Other assets........................................... 314 316
Total deferred income tax liabilities............. 5,615 3,983
----------------- -----------------
Intangible assets...................................... (6) (6)
Total deferred income tax assets.................. (6) (6)
----------------- -----------------
Net deferred tax liability........................ $ 5,609 $ 3,977
================= =================
</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, 1997 and
1996 are summarized as follows (in 000s):
<TABLE>
<CAPTION>
1997 % 1996 %
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Income tax at statutory rate................... $ 4,339 35.0% $ 2,916 35.0%
State income taxes, net of federal
benefit..................................... 403 3.3% 140 1.7%
Tax credits.................................... (204) (1.6%) (35) (0.4%)
Other.......................................... 12 0.1% 225 2.7%
---------- ---------- ---------- ----------
Total..................................... $ 4,550 36.8% $ 3,246 39.0%
========== ========== ========== ==========
</TABLE>
29
<PAGE>
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 9. STOCK COMPENSATION PLANS
At December 31, 1997, 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):
1997 1996 1995
------ ------ ------
Net income As reported...... $7,847 $7,769 $6,074
Pro forma........ 7,732 7,714 6,062
Basic earnings per share As reported...... $ 0.92 $ 1.21 $ 1.06
Pro forma........ 0.91 1.20 1.06
Earnings per share assuming As reported...... $ 0.91 $ 1.20 $ 1.06
dilution Pro forma........ 0.89 1.19 1.06
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 10 years.
Options are granted periodically throughout the year and vest at the rate of 20%
on the first anniversary of the option grant date and at the rate of 20% on each
subsequent anniversary thereof until fully vested.
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 3 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.
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 1997, 1996 and 1995; expected
volatility of 30% for 1997 option grants, 33% for 1996 option grants and 34%
for 1995 option grants; risk-free interest rate of 5.83% for 1997 option grants,
6.55% for 1996 option grants and 6.22% for 1995 option grants; expected lives of
6 years for 1997, 1996 and 1995 option grants.
30
<PAGE>
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A summary of the status of the Company's two fixed stock option plans as of
December 31, 1997, 1996 and 1995 and changes during the years ended on those
dates is presented below:
<TABLE>
<CAPTION>
1997 1996 1995
-------------------------- -------------------------- -------------------------
Weighted-Average Weighted-Average Weighted-Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
------- ---------------- ------- ---------------- ------ ----------------
<S> <C> <C> <C> <C> <C> <C>
FIXED OPTIONS
Outstanding at beginning of
year.......................... 276,749 $ 8.30 140,863 $ 7.01 76,859 $ 6.99
Granted........................ 159,374 18.21 137,032 9.62 64,004 7.04
Exercised...................... (34,724) 7.24 -- -- -- --
Forfeited...................... (17,909) 8.55 (1,146) -- -- --
------- ---------------- ------- --------------- ------- --------------
Outstanding at end of year..... 383,490 $ 12.50 276,749 $ 8.30 140,863 $ 7.01
======= ================ ======= =============== ======= ==============
Options exercisable at
December 31, 1997,
1996 and 1995,
respectively................ 88,926 63,069 33,393
Weighted-average fair value of
options granted during the
year.......................... $ 7.52 $ 4.27 $ 3.11
</TABLE>
The following table summarizes information about fixed stock options outstanding
at December 31, 1997:
<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 12/31/97 Life Price at 12/31/97 Price
- ------------------------ ----------- ----------- --------- ----------- ---------
<S> <C> <C> <C> <C> <C>
$6.99........................ 90,509 3.99 years $ 6.99 58,275 $ 6.99
$7.14 to $10.00.............. 133,607 6.51 years $ 9.43 30,651 $ 9.21
$13.50 to $17.50............. 35,000 7.22 years $ 14.53 -- --
$19.25....................... 124,374 9.95 years $ 19.25 -- --
----------- ------
383,490 88,926
=========== ======
</TABLE>
31
<PAGE>
NOTE 10. EARNINGS PER SHARE
During 1997, the Company adopted Financial Accounting Standards ("SFAS")
Statement No. 128, Earnings per Share. This statement requires that all
periods presented be retroactively restated in accordance with SFAS No. 128.
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
three years ending December 31, 1997 (in 000s, except per share data):
<TABLE>
<CAPTION>
For the Year Ended December 31,
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
Net income............................................ $ 7,847 $ 7,769 $ 6,074
============ ============ ============
Weighted average number of outstanding
shares of common stock used in
earnings per share............................. 8,485 6,415 5,725
Effect of dilutive securities:
Stock options.................................. 129 66 --
------------ ------------ ------------
Weighted average number of outstanding
shares of common stock used in
earnings per share, assuming dilution......... 8,614 6,481 5,725
============ ============ ============
</TABLE>
NOTE 11. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The following summarizes certain quarterly results of operations (000s):
<TABLE>
<CAPTION>
First Second Third Fourth
-------- -------- -------- --------
1997
- ---------------------------------------------------
<S> <C> <C> <C> <C>
Revenue (1)........................................ $ 28,614 $ 11,772 $ 14,948 $ 23,922
Gross profit (2)................................... 8,672 2,316 3,181 5,228
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
1996
- ---------------------------------------------------
Revenue (1)........................................ $ 19,832 $ 8,760 $ 14,935 $ 28,233
Gross profit (2)................................... 5,514 1,580 3,533 10,268
Net income......................................... 4,174 314 1,943 1,338
Basic earnings per share (3)....................... $ 0.73 $ 0.05 $ 0.34 $ 0.16
Earnings per share assuming dilution (3)........... $ 0.73 $ 0.05 $ 0.34 $ 0.16
</TABLE>
(1) Excludes interest income.
(2) Excludes general and administrative expenses and interest expense.
(3) Weighted average shares outstanding for each quarter in 1996 represents the
weighted average of, for each quarter prior to the Company's initial public
offering, the number of shares issued in the Reorganization and, for the
quarter subsequent to the Offering, the total number of common shares
outstanding.
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
32
<PAGE>
ITEM 12. SECURITY OWNERSHIP AND CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12 and 13 are omitted
because the Company will file a definitive proxy statement (the "Proxy
Statement") pursuant to Regulation 14A under the 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 21, 1998 and is
hereby incorporated by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
(1) Financial Statements:
Reference is made to the listing on page 18 for a list of all
financial statements filed as a part of this report.
(2) Financial Statement Schedules:
None required.
(3) Exhibits
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 to MarkWest Hydrocarbon, Inc.'s Registration Statement on
Form S-1, Registration No. 333-09513 and incorporated herein by
reference).
3.2 Bylaws of MarkWest Hydrocarbon, Inc. (Filed as exhibit 3.2 to MarkWest
Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No.
333-09513 and incorporated herein by reference).
10.1 Amended and Restated Reorganization Agreement made as of August 1, 1996,
by and among MarkWest Hydrocarbon, Inc., MarkWest Hydrocarbon Partners,
Ltd., MWHC Holding, Inc. RIMCO Associates, Inc. and each of the limited
partners of MarkWest Hydrocarbon Partners, Ltd. (Filed as exhibit 10.1
to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1,
Registration No. 333-09513 and incorporated herein by reference).
10.2 Participation, Ownership and Operating Agreement for West Shore
Processing Company, L.L.C. dated May 2, 1996 (Filed as exhibit 10.7 to
MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1,
Registration No. 333-09513 and incorporated herein by reference).
10.3 Second Amended and Restated Operating Agreement for Basin Pipeline
L.L.C., dated May 2, 1996 (Filed as exhibit 10.8 to MarkWest
Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No.
333-09513 and incorporated herein by reference).
10.4 Gas Treating and Processing Agreement, dated May 1, 1996, between West
Shore Processing Company, LLC and Shell Offshore, Inc. (Filed as exhibit
10.10 to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-
1, Registration No. 333-09513 and incorporated herein by reference).
10.5 Gas Processing and Treating Agreement, dated March 29, 1996, between
Manistee Gas Limited Liability Company and Michigan Production Company,
L.L.C. (Filed as exhibit 10.14 to MarkWest Hydrocarbon, Inc.'s
Registration Statement on Form S-1, Registration No. 333-09513 and
incorporated herein by reference).
10.6 Processing Agreement (Kenova Processing Plant), dated March 15, 1995,
between Columbia Gas Transmission Corporation and MarkWest Hydrocarbon
Partners, Ltd. (Filed as exhibit 10.15 to MarkWest Hydrocarbon, Inc.'s
Registration Statement on Form S-1, Registration No. 333-09513 and
incorporated herein by reference).
33
<PAGE>
10.7 Natural Gas Liquids Purchase Agreement (Cobb Plant), between Columbia
Gas Transmission Corporation and MarkWest Hydrocarbon Partners, Ltd.
(Filed as exhibit 10.16 to MarkWest Hydrocarbon, Inc.'s Registration
Statement on Form S-1, Registration No. 333-09513 and incorporated
herein by reference).
10.8 Purchase and Demolition Agreement Construction Premises, dated March 15,
1995, between Columbia Gas Transmission Corporation and MarkWest
Hydrocarbon Partners, Ltd. (Filed as exhibit 10.17 to MarkWest
Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No.
333-09513 and incorporated herein by reference).
10.9 Purchase and Demolition Agreement Remaining Premises, dated March 15,
1995, between Columbia Gas Transmission Corporation and MarkWest
Hydrocarbon Partners, Ltd. (Filed as exhibit 10.18 to MarkWest
Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No.
333-09513 and incorporated herein by reference).
10.10 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 to MarkWest Hydrocarbon, Inc.'s
Registration Statement on Form S-1, Registration No. 333-09513 and
incorporated herein by reference).
10.11 Contract for Construction and Lease of Boldman Plant, dated December 24,
1990, between Columbia Gas Transmission Corporation and MarkWest
Hydrocarbon Partners, Ltd. (Filed as exhibit 10.22 to MarkWest
Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No.
333-09513 and incorporated herein by reference).
10.12 Natural Gas Liquids Purchase Agreement (Boldman Plant), dated December
24, 1990, between Columbia Gas Transmission Corporation and MarkWest
Hydrocarbon Partners, Ltd. (Filed as exhibit 10.23 to MarkWest
Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No.
333-09513 and incorporated herein by reference).
10.13 Natural Gas Liquids Purchase Agreement, dated April 26, 1988, between
Columbia Gas Transmission Corporation and MarkWest Hydrocarbon Partners,
Ltd. (Filed as exhibit 10.24 to MarkWest Hydrocarbon, Inc.'s
Registration Statement on Form S-1, Registration No. 333-09513 and
incorporated herein by reference).
10.14 1996 Incentive Compensation Plan (Filed as exhibit 10.25 to MarkWest
Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No.
333-09513 and incorporated herein by reference).
10.15 1996 Stock Incentive Plan (Filed as exhibit 10.26 to MarkWest
Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration No.
333-09513 and incorporated herein by reference).
10.16 1996 Non-employee Director Stock Option Plan (Filed as exhibit 10.27 to
MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1,
Registration No. 333-09513 and incorporated herein by reference).
10.17 Form of Non-Compete Agreement between John M. Fox and MarkWest
Hydrocarbon, Inc. (Filed as exhibit 10.28 to MarkWest Hydrocarbon,
Inc.'s Registration Statement on Form S-1, Registration No. 333-09513
and incorporated herein by reference).
10.18 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 to MarkWest Hydrocarbon,
Inc.'s Form 10-K for the year ended December 31, 1996 and incorporated
herein by reference).
10.19 Non-Recourse Loan Agreement between Michigan Production Company, L.L.C.
and West Shore Processing Company, L.L.C., dated October 1, 1996. (Filed
as exhibit 10.32 to MarkWest Hydrocarbon, Inc.'s Form 10-K for the year
ended December 31, 1996 and incorporated herein by reference).
10.20 First Amendment to Participation, Ownership and Operating Agreement for
West Shore Processing Company, L.L.C., dated October 1, 1996. (Filed as
exhibit 10.33 to MarkWest Hydrocarbon, Inc.'s Form 10-K for the year
ended December 31, 1996 and incorporated herein by reference).
10.21 Option and Agreement to Purchase and Sell Pipeline, dated October 1,
1996. (Filed as exhibit 10.34 to MarkWest Hydrocarbon, Inc.'s Form 10-K
for the year ended December 31, 1996 and incorporated herein by
reference).
34
<PAGE>
10.22 Mortgage, Assignment, Security Agreement and Financing Statement from
Michigan Production Company, L.L.C. to West Shore Processing Company,
L.L.C., dated October 22, 1996. (Filed as exhibit 10.35 to MarkWest
Hydrocarbon, Inc.'s Form 10-K for the year ended December 31, 1996 and
incorporated herein by reference).
10.23 Amendment to Participation, Ownership and Operating Agreement for West
Shore Processing Company, L.L.C., dated December 12, 1996. (Filed as
exhibit 10.36 to MarkWest Hydrocarbon, Inc.'s Form 10-K for the year
ended December 31, 1996 and incorporated herein by reference)
10.24 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).
10.25 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).
10.26 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.
11. Statement regarding computation of earnings per share.
21. List of Subsidiaries of MarkWest Hydrocarbon, Inc.
23. Consent of Price Waterhouse LLP, independent accountants.
27. Financial Data Schedule
(b) Reports on Form 8-K:
(i) A report on Form 8-K dated December 3, 1997 was filed during the
fourth quarter of 1997 to announce the Company's acquisition of the
remaining 40 percent interest in its western Michigan project from
its partner, Michigan Energy Company, L..L.C.
(ii) A report of Form 8-K dated February 24, 1998 was filed during the
first quarter of 1998 to announce the Company's arbitration with
Columbia Gas Transmission Corporation to resolve issues regarding
three natural gas processing plants in Appalachia.
(c) Exhibits required by Item 601 of Regulation S-K. See (a) (3) above.
35
<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 20, 1998.
MarkWest Hydrocarbon, Inc.
(Registrant)
BY: /s/ John M. Fox
------------------------------------
John M. Fox
President and Chief
Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
/s/ John M. Fox March 20, 1998
--------------------------------
John M. Fox
President, Chief Executive
Officer and Director
/s/ Brian T. O'Neill March 20, 1998
--------------------------------
Brian T. O'Neill
Senior Vice President, Chief
Operating Officer and Director
/s/ Gerald A. Tywoniuk March 20, 1998
--------------------------------
Gerald A. Tywoniuk
Chief Financial Officer and
Vice President of Finance
(Principal Financial and
Accounting Officer)
/s/ Arthur J. Denney March 20, 1998
--------------------------------
Arthur J. Denney
Director
/s/ Norman H. Foster March 20, 1998
--------------------------------
Norman H. Foster
Director
/s/ Barry W. Spector March 20, 1998
--------------------------------
Barry W. Spector
Director
/s/ David R. Whitney March 20, 1998
--------------------------------
David R. Whitney
Director
36
<PAGE>
EXHIBIT 10.26
================================================================================
FIRST AMENDMENT TO CREDIT AGREEMENT
dated as of December 24, 1997
among
MARKWEST HYDROCARBON, INC.,
as the Borrower,
and
VARIOUS COMMERCIAL LENDING INSTITUTIONS,
as the Lenders,
and
BANK OF MONTREAL,
acting through certain U.S. branches or agencies,
as the Agent for the Lenders
================================================================================
<PAGE>
FIRST AMENDMENT TO CREDIT AGREEMENT
THIS FIRST AMENDMENT TO CREDIT AGREEMENT, dated as of December 24, 1997
(the "First Amendment"), is among MARKWEST HYDROCARBON, INC., a Delaware
---------------
corporation ("Borrower"), the various commercial lending institutions as are or
--------
may become parties hereto ("Lenders"), and BANK OF MONTREAL, acting through
-------
certain U.S. branches or agencies, as Agent for the Lenders (in such capacity,
"Agent").
- ------
W I T N E S S E T H:
-------------------
1. Borrower, Lenders and Agent have heretofore entered into that certain
Credit Agreement, dated as of June 20, 1997 (the "Credit Agreement").
----------------
2. Borrower, Lenders and Agent now intend to amend the Credit Agreement as
follows:
I. AMENDMENTS TO CREDIT AGREEMENT.
------------------------------
A. Section 1.1 of the Credit Agreement is hereby amended by adding the
-----------
following definitions of "Contingent Liability", "Hedging Agreement", "Hedging
Counterparty", "Lender Hedging Agreement", "Michigan Energy Company" and "West
Shore/Basin Purchase Agreement" in appropriate alphabetical order:
"Contingent Liability" means any agreement, undertaking or arrangement
--------------------
by which any Person guarantees, endorses or otherwise becomes or is
contingently liable upon (by direct or indirect agreement, contingent or
otherwise, to provide funds for payment, to supply funds to, or otherwise
to invest in, a debtor, or otherwise to assure a creditor against loss) the
indebtedness, obligation or any other liability of any other Person (other
than by endorsements of instruments in the course of collection), or
guarantees the payment of dividends or other distributions upon the shares
of any other Person; provided, however, that notwithstanding the foregoing,
-------- -------
the definition of "Contingent Liability" shall not include any contingent
payments owing by Borrower or any or its Subsidiaries in connection with
Section 2 of the West Shore/Basin Purchase Agreement. The amount of any
Person's obligation under any Contingent Liability shall (subject to any
limitation set forth therein) be deemed to be the outstanding principal
amount (or maximum principal amount, if larger) of the debt, obligation or
other liability guaranteed thereby.
"Hedging Agreement" means any interest rate swap agreements, interest
-----------------
rate cap agreements, interest rate collar agreements, commodity price
protection agreement, and all other agreements or arrangements designed to
protect such
<PAGE>
Person against fluctuations in interest rates, or commodity prices, as any
such agreement is amendment, supplemented or otherwise modified from time
to time.
"Hedging Counterparty" means any Person which is a counterparty to a
--------------------
Hedging Agreement.
"Lender Hedging Agreement" means any Hedging Agreements entered into
------------------------
by Borrower or any of its Subsidiaries in which a Lender is the Hedging
Counterparty.
"Michigan Energy Company" means Michigan Energy Company, L.L.C., a
-----------------------
Michigan limited liability company.
"West Shore/Basin Purchase Agreement" means that certain Purchase and
-----------------------------------
Sale Agreement, dated as of November 21, 1997, between Michigan Energy
Company and MarkWest Michigan.
B. The definitions of "Access Easement", "Applicable Margin", "Hedging
Obligation", "Loan Documents", "Reducing Loan Commitment Amount", and "Revolving
Loan Commitment Amount" appearing in Section 1.1 of the Credit Agreement are
-----------
hereby amended in their entirety to the followings:
"Access Easement" means an access easement, substantially in the form
---------------
of Exhibit X hereto or in such other form acceptable to the Agent, in its
---------
sole and reasonable discretion, and executed and delivered pursuant to
Section 7.1.10,, as amended, supplemented, restated or otherwise modified
--------------
from time to time.
"Applicable Margin" means, with respect to any Loan of any type or any
-----------------
Letter of Credit, and at such time as the ratio of Total Funded Debt to
Capitalization is in one of the following ranges, the number of basis
points ("b.p.") per annum for the relevant type of Loan or Letter of Credit
---------
and the relevant range set forth below:
- --------------------------------------------------------------------------------
Range Applicable Margin
- --------------------------------------------------------------------------------
LIBOR Rate Letter of
Margin Credit
- --------------------------------------------------------------------------------
Range 1 The ratio of Total Funded Debt to 50 b.p. 50 b.p.
Capitalization is less than 25%
- --------------------------------------------------------------------------------
Range 2 The ratio of Total Funded Debt to 62.5 b.p. 62.5 b.p.
Capitalization is equal to or greater
than 25%, but less than 35%
- --------------------------------------------------------------------------------
<PAGE>
- --------------------------------------------------------------------------------
Range 3 The ratio of Total Funded Debt to 87.5 b.p. 87.5 b.p.
Capitalization is equal to or greater
than 35%, but less than 45%
- --------------------------------------------------------------------------------
Range 4 The ratio of Total Funded Debt to 150.0 b.p. 150.0 b.p.
Capitalization is equal to or greater
than 45%
================================================================================
The ratio of Total Funded Debt to Capitalization shall be determined from
the then most recent monthly, annual or quarterly financial statements
delivered by the Borrower pursuant to Section 7.1.1 and any changes in
Applicable Margin shall become effective the first day of the second month
following the applicable date of such financial statements (and not the
delivery date of such financial statements). Until financial statements
for the first quarter ending after the date hereof have been delivered, the
Applicable Margin shall be 50 b.p. In the event that the Borrower shall at
any time fail to furnish the Lenders such financial statements required to
be delivered under Section 7.1.1, the maximum Applicable Margin as set
forth above shall apply until such time as such financial statements are so
delivered. Changes in the Applicable Margin as a result of a change in the
ratio of Total Funded Debt to Capitalization will occur automatically as
aforesaid without notice.
"Hedging Obligation" means, with respect to any Person, all
------------------
liabilities of such Person under any Hedging Agreement.
"Loan Documents" means this Agreement, the Notes, each of the
--------------
Collateral Documents, each Guaranty, each Lender Hedging Agreement, and
each other agreement, document or instrument delivered by the Borrower or
any Guarantor from time to time in connection with this Agreement and the
Notes.
"Reducing Loan Commitment Amount" means, on any date, $60,000,000, as
-------------------------------
such amount may be reduced from time to time pursuant to Section 2.2.
-----------
"Revolving Loan Commitment Amount" means, on any date, $60,000,000, as
--------------------------------
such amount may be reduced from time to time pursuant to Section 2.2.
-----------
3
<PAGE>
C. Section 7.1.8 of the Credit Agreement is hereby amended by deleting the
-------------
phrase "within 120 days of the Effective Date" and inserting in lieu thereof the
phrase "prior to or on January 31, 1998".
D. Section 7.1.10 of the Credit Agreement is hereby amended in its
--------------
entirety to the following:
"SECTION 7.1.10 Access Easement. Borrower shall on or before March
---------------
1, 1998, deliver to the Agent an executed counterpart of the Access
Easement, duly executed by the parties thereto."
E. Section 7.1 of the Credit Agreement is hereby amended by inserting
-----------
after Section 7.1.12 thereof the following Section 7.1.13:
-------------- --------------
"SECTION 7.1.13 Hedging Agreements. Borrower shall, and shall cause
------------------
each of its Subsidiaries to, promptly, and in any event within 14 days
after the date of the execution of a Hedging Agreement, (i) notify the
Agent of any Hedging Agreement entered into by Borrower or any of its
Subsidiaries and (ii) provide the Agent with a copy of such Hedging
Agreement."
F. Section 7.2.2 of the Credit Agreement is hereby amended in its entirety
-------------
to the following:
"SECTION 7.2.2 Indebtedness . The Borrower will not, and will not
------------
permit any of its Subsidiaries to, create, incur, assume or suffer to exist
or otherwise become or be liable in respect of any Indebtedness, other
than, without duplication, the following: (a) Indebtedness in respect of
the Loans and other Obligations; (b) until the date of the initial
Borrowing, Indebtedness identified in Item 7.2.2(b) ("Indebtedness to be
-------------
Paid") of the Disclosure Schedule; (c) Indebtedness existing as of the
Effective Date which is identified in Item 7.2.2(c) ("Ongoing
-------------
Indebtedness") of the Disclosure Schedule; (d) Indebtedness in an aggregate
principal amount not to exceed $5,000,000 at any time outstanding which is
incurred by the Borrower or any of its Subsidiaries to finance its
acquisition of an office building at 155 Inverness, Englewood, Colorado;
(e) unsecured Indebtedness incurred in the ordinary course of business
consisting of open accounts extended by suppliers and customers on normal
trade terms in connection with purchases or sales of goods and services,
but excluding Indebtedness incurred through the borrowing of money or
Contingent Liabilities; (f) Indebtedness in respect of Capitalized Lease
Liabilities to the extent permitted by Section 7.2.7; (g) other unsecured
-------------
Indebtedness of the Borrower and its Subsidiaries in an aggregate amount
not to exceed $5,000,000, (h) Indebtedness between the Borrower and its
Subsidiaries and between the Borrower's Subsidiaries provided such
Indebtedness is
4
<PAGE>
evidenced by a promissory note; (i) Indebtedness resulting
from any Hedging Obligations; and (j) Indebtedness arising in respect of
the West Shore/Basin Purchase Agreement; provided, however, that no
-------- -------
Indebtedness otherwise permitted by clauses (d) or (g) shall be permitted
----------- ---
if, after giving effect to the incurrence thereof, any Default shall have
occurred and be continuing."
G. Article 8 of the Credit Agreement is hereby amended by inserting after
---------
Section 8.12 thereof the following Section 8.13:
- ------------ ------------
"SECTION 8.13 Default on Hedging Obligations pursuant to Lender
-------------------------------------------------
Hedging Agreements. A default shall occur in payment when due (subject to
------------------
any applicable grace period), whether due by acceleration or otherwise, of
any Hedging Obligation of the Borrower or any of its Subsidiaries arising
in connection with a Lender Hedging Agreement, or a default shall occur in
the performance or observance of any obligation or condition with respect
to such Hedging Obligation if the effect of such default is to accelerate
the maturity of any such Hedging Obligation or such default shall continue
unremedied for any applicable period of time sufficient to permit the
holder or holders of such Hedging Obligation, or any trustee or agent for
such holders, to cause such Hedging Obligation to become due and payable
prior to its expressed maturity."
H. Article 10 of the Credit Agreement is hereby amended by inserting after
----------
Section 10.16 thereof the following Section 10.17:
- ------------- -------------
"SECTION 10.17 Priority of Hedging Obligations. Borrower, Lenders and
-------------------------------
Agent hereby agree that (i) the first $10,000,000 received in satisfaction
of any Obligations arising under the Loan Documents, including, without
limitation, Obligations under this Agreement and any Lender Hedging
Agreement, shall rank pari passu in right of payment and shall be used to
---- -----
repay such Obligations on a pro rata basis, and (ii) except as otherwise
set forth in Section 10.17(i) above, all Hedging Obligations arising in
----------------
connection with any Lender Hedging Agreement are hereby expressly
subordinated in right of payment to the prior payment in full in cash of
all Obligations under the Loan Documents, other than any Lender Hedging
Agreement."
I. The Credit Agreement is hereby amended by replacing Exhibit F to the
---------
Credit Agreement with Exhibit F to this First Amendment.
---------
J. The Credit Agreement is hereby amended by inserting Exhibit Y to this
---------
First Amendment as Exhibit Y to the Credit Agreement following Exhibit X to the
--------- ---------
Credit Agreement.
5
<PAGE>
K. After giving effect to, and as of the date of, this First Amendment,
the applicable "Percentage" for (i) Bank of Montreal shall be 50%, (ii)
NationsBank of Texas, N.A. shall be 25%, and (iii) Colorado National Bank shall
be 25%.
II. EFFECTIVENESS. This First Amendment shall become effective as of the
-------------
date hereof when Agent shall have received (i) counterparts hereof duly executed
by Borrower, Required Lenders and Agent (or, in the case of any party as to
which an executed counterpart shall not have been received, telegraphic, telex,
or other written confirmation from such party of execution of a counterpart
hereof by such party), (ii) a Note date of even date herewith in the original
principal amount of $15,000,000 payable to the order of Colorado National Bank
duly executed by Borrower, and (iii) a copy of the West Shore/Basin Purchase
Agreement, duly certified as being true, correct and complete by an Authorized
Officer of Borrower.
III. REAFFIRMATION OF REPRESENTATIONS AND WARRANTIES. To induce Lenders
-----------------------------------------------
and Agent to enter into this First Amendment, Borrower hereby reaffirms, as of
the date hereof, its representations and warranties in their entirety contained
in Article VI of the Credit Agreement and in all other documents executed
----------
pursuant thereto (except to the extent such representations and warranties
relate solely to an earlier date) and additionally represents and warrants as
follows:
(i) Borrower is a corporation duly incorporated, validly existing
and in good standing under the laws of its jurisdiction of incorporation
and has all requisite authority, permits and approvals, and is in good
standing to conduct its business in each jurisdiction in which its business
is conducted.
(ii) Borrower has the corporate power and authority and legal right
to execute and deliver this First Amendment and to perform its obligations
hereunder. The execution and delivery by Borrower of this First Amendment
and the performance of its obligations hereunder have been duly authorized
by proper corporate proceedings, and this First Amendment and the Credit
Agreement, as amended hereby, constitute the legal, valid and binding
obligations of Borrower, enforceable against Borrower in accordance with
their terms, except as enforceability may be limited by bankruptcy,
insolvency or similar laws affecting the enforcement of creditors' rights
generally.
(iii) No Default or Event of Default has occurred and is continuing
as of the date hereof.
(iv) There has been no material adverse change (a) in the financial
condition, operations, assets, businesses, properties or prospects of
Borrower and its Subsidiaries from June 20, 1997, (b) affecting the rights
and remedies of Lenders under and in connection with this First Amendment
and the Credit Agreement, as amended by this
6
<PAGE>
First Amendment, or (c) in the ability of Borrower to perform its
obligations under this First Amendment or the Credit Agreement, as amended
by this First Amendment.
(v) There is no pending or, to the knowledge of Borrower, threatened
litigation, action, proceeding, or labor controversy affecting Borrower or
any of its Subsidiaries, or any of their respective properties, businesses,
assets or revenues, which may materially adversely affect the financial
condition, operations, assets, business, properties or prospects of
Borrower or any Subsidiary or which purports to affect the legality,
validity or enforceability of this Amendment, Credit Agreement, the Notes
or any other Loan Document, except as disclosed in Item 6.7 ("Litigation")
--------
of the Disclosure Schedule to the Credit Agreement and as supplemented in
the Borrower's monthly financial report delivered pursuant to Section
7.1.1(a) of the Credit Agreement.
IV. DEFINED TERMS. Except as amended hereby, terms used herein when
-------------
defined in the Credit Agreement shall have the same meanings herein unless the
context otherwise requires.
V. REAFFIRMATION OF CREDIT AGREEMENT. This First Amendment shall be
---------------------------------
deemed to be an amendment to the Credit Agreement, and the Credit Agreement, as
amended hereby, is hereby ratified, approved and confirmed in each and every
respect. All references to the Credit Agreement herein and in any other
document, instrument, agreement or writing shall hereafter be deemed to refer to
the Credit Agreement as amended hereby.
VI. GOVERNING LAW. THIS AMENDMENT, THE CREDIT AGREEMENT, THE NOTES AND
-------------
EACH OTHER LOAN DOCUMENT SHALL EACH BE DEEMED TO BE A CONTRACT MADE UNDER AND
GOVERNED BY THE INTERNAL LAWS OF THE STATE OF NEW YORK. All obligations of the
Borrower and rights of Lenders and Agent and any other holders of the Notes
expressed herein shall be in addition to and not in limitation of those provided
by applicable law.
VII. SEVERABILITY OF PROVISIONS. Any provision in this First Amendment
--------------------------
that is held to be inoperative, unenforceable, or invalid in any jurisdiction
shall, as to that jurisdiction, be inoperative, unenforceable, or invalid
without affecting the remaining provisions in that jurisdiction or the
operation, enforceability, or validity of that provision in any other
jurisdiction, and to this end the provisions of this First Amendment are
declared to be severable.
VIII. COUNTERPARTS. This First Amendment may be executed in any number of
------------
counterparts, all of which taken together shall constitute one agreement, and
any of the parties hereto may execute this First Amendment by signing any such
counterpart.
7
<PAGE>
IX. HEADINGS. Article and section headings in this First Amendment are
--------
for convenience of reference only, and shall not govern the interpretation of
any of the provisions of this First Amendment.
X. SUCCESSORS AND ASSIGNS. This First Amendment shall be binding upon and
----------------------
inure to the benefit of the parties hereto and their respective successors and
assigns.
XI. NOTICE. THIS WRITTEN FIRST AMENDMENT TOGETHER WITH THE CREDIT
------
AGREEMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE
PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR
SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES.
THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.
8
<PAGE>
IN WITNESS WHEREOF, the parties hereto have caused this First Amendment to
be executed by their respective officers thereunto duly authorized as of the day
and year first above written.
MARKWEST HYDROCARBON, INC.
By: /s/ Gerald A. Tywoniuk
---------------------------------
Name: Gerry Tywoniuk
Title: Vice President of Finance
S-1
<PAGE>
BANK OF MONTREAL, acting through its U.S.
branches and agencies, as Agent and Lender
By: /s/ Donald G. Skipper
---------------------------------------
Name: Donald G. Skipper
Title: Director
S-2
<PAGE>
NATIONSBANK OF TEXAS, N.A., as Lender
By: /s/ David S. Rubenking
----------------------------------
Name: David S. Rubenking
Title: Senior Vice President
S-3
<PAGE>
COLORADO NATIONAL BANK, as Lender
By: /s/ Monte E. Deckerd
----------------------------
Name: Monte E. Deckerd
Title: Colorado National Bank
S-4
<PAGE>
EXHIBIT F
FORM OF COMPLIANCE CERTIFICATE
------------------------------
The undersigned hereby certifies that he is the chief financial Authorized
Officer of MARKWEST HYDROCARBONS, INC., a Delaware corporation (the "Borrower"),
--------
that he has knowledge of the facts stated herein, and that as such he is
authorized to execute this certificate. With reference to the Credit Agreement,
dated as of June 20, 1997 (together with all amendments or supplements thereto
being the "Credit Agreement") among the Borrower, the Lenders which are or
----------------
become party thereto, and BANK OF MONTREAL, as Agent for the Lenders (the
"Agent"), the undersigned represents and warrants as follows (each capitalized
-----
term used herein having the same meaning given to it in the Credit Agreement
unless otherwise specified):
(a) The representations and warranties on the part of the Borrower
contained in the Credit Agreement or any other Loan Document were true and
correct when made, and are repeated at and as of the time of delivery
hereof and are true and correct at and as of the time of delivery hereof,
except to the extent such representations and warranties are expressly
limited to an earlier date.
(b) No Default or any Event of Default has occurred and is continuing.
(c) Since June 20, 1997, there has been no Material Adverse Effect
with respect to the Borrower or any of its Subsidiaries.
(d) Borrower is in compliance with Section 7.2.4 of the Credit
Agreement as of the end of the fiscal quarter ending ________________,
_______. Attached hereto are the detailed computations necessary to
determine such compliance.
(e) Borrower and its Subsidiaries (i) are in compliance with Section
7.1.6 of the Credit Agreement and (ii) have not received any claims,
complaints, notices, inquiries, or requests for information regarding
potential liability under any Environmental Law or under any common law
theories relating to operations or the condition of any facilities or
property (including underlying groundwater) owned, leased or operated by
the Borrower and its Subsidiaries.
(f) Borrower is in compliance with, and has performed any and all
obligations and actions set forth in, the terms and provisions of the
Hedging Policy.
(g) As of the date hereof, Borrower has (1) Hedging Obligations equal
to $__________________, (2) Hedging Obligations pursuant to Lender Hedging
Agreements equal to $__________________, and (3) such Hedging Obligations
arise in connection with the
Exhibit F - Page 1
<PAGE>
following Hedging Agreements: __________________________________________________
________________________________________________________________________________
________________________________________________________________________________
________________________________________________________________________________
________________________________________________________________________________
______________________________________________________.
EXECUTED AND DELIVERED this _______ day of ____________________.
By:
Name:
Title: Chief Financial Officer
Exhibit F - Page 2
<PAGE>
COMPLIANCE WITH FINANCIAL COVENANTS AS OF _____________. ($ in 000's)
================================================================================
A. TANGIBLE NET WORTH $
=========
Minimum requirement $
=========
B. TOTAL FUNDED DEBT TO CAPITALIZATION %
=========
Maximum ratio allowed 55%
=========
C. TOTAL FUNDED DEBT TO
TRAILING TWELVE MONTH EBITDA
Maximum ratio allowed 4 : 1
=========
=========
D. CURRENT RATIO
Minimum ratio allowed 1 : 1
=========
================================================================================
COMPUTATION OF FINANCIAL REQUIREMENTS AND RATIOS AS OF ______________.
================================================================================
A. TANGIBLE NET WORTH (Section 7.2.4(a)) ($ in 000's)
(i) Tangible Net Worth (as defined in Section 1.1)
(a) Consolidated net worth of the Borrower
and its Subsidiaries $
---------
(b) Less amount of any intangible assets of the Borrower
----
and its Subsidiaries $
---------
TANGIBLE NET WORTH $
===========
(ii) MINIMUM REQUIRED
(a) $38,000 $38,000
(b) Plus 50% of positive consolidated net
----
income for previous quarters
beginning January 1, 1997 $
----------
(c) Plus 50% of positive consolidated net
----
Exhibit F - Page 3
<PAGE>
income for quarter ended ______________ $_____________
(d) Plus 75% of the proceeds from the issuance
----
of any Securities (other than Securities
representing Indebtedness) for previous
quarters beginning January 1, 1997 $_____________
(e) Plus 75% of the proceeds from the issuance
----
of any Securities (other than Securities
representing Indebtedness) for quarter
ended __________________ $_____________
TANGIBLE NET WORTH REQUIREMENT $
=============
================================================================================
B.. TOTAL FUNDED DEBT TO CAPITALIZATION (Section 7.2.4(b)) ($ in 000's)
(i) TOTAL FUNDED DEBT (as defined in Section 1.1)
(a) All obligations of Borrower and its
Subsidiaries for borrowed money and
all obligations evidenced by bonds,
debentures, notes or other similar instruments $_____________
(b) Plus all obligations, contingent or otherwise,
----
relative to the face amount of all letters of
credit, whether or not drawn, and banker's
acceptances issued for the account of
Borrower and its Subsidiaries $_____________
(c) Plus all obligations of Borrower and its
----
Subsidiaries as lessee under leases which
have been or should be, in accordance
with GAAP, recorded as Capitalized
Lease Liabilities $_____________
(d) Plus all obligations of Borrower and its
----
Subsidiaries to pay the deferred purchase
price of property or services which have
been or should be in accordance with GAAP $_____________
Exhibit F - Page 4
<PAGE>
(d) Less cash on hand free and clear of all Liens $_____________
----
(d) Less Cash Equivalent Investments free
----
and clear of all Liens $_____________
TOTAL FUNDED DEBT $
=============
(ii) CAPITALIZATION (as defined in Section 1.1)
(i) Total Funded Debt of the Borrower
and its Subsidiaries on a consolidated basis
(See B(i) above) $_____________
(ii) Plus total shareholders' equity of the Borrower
----
and its Subsidiaries on a consolidated basis
determined in accordance with GAAP $_____________
[exclude mark-to-market adjustments,
including those relating to commodity hedges
required to be included in determining
shareholders' equity under GAAP] $______________$_____________
CAPITALIZATION $
==============
TOTAL FUNDED DEBT TO CAPITALIZATION ((i)/(ii)) %
==========
Maximum ratio 55 %
==========
================================================================================
C. TOTAL FUNDED DEBT TO TRAILING TWELVE MONTH EBITDA
(Section 7.2.4(c)) ($ in 000's)
(i) TOTAL FUNDED DEBT (as defined in Section 1.1)
(as calculated in B(i) above) $
=============
(ii) TRAILING TWELVE MONTH EBITDA (as defined in Section 1.1)
For the Twelve Months Ended _____________ -
Net earnings (excluding extraordinary items, gains
and losses on sales and retirement of assets, non-cash
write downs and charges resulting from accounting
Exhibit F - Page 5
<PAGE>
convention changes) before deduction for federal and
state income taxes, Interest Expense, operating lease
rentals and depreciation, depletion and amortization expense
of the Borrower and its Subsidiaries on a consolidated basis,
all determined in accordance with GAAP for the 12 months
ending on the last day of such month.
TRAILING TWELVE MONTH EBITDA $
=============
TOTAL FUNDED DEBT TO TRAILING TWELVE MONTH EBITDA((i)/(ii))
=============
Maximum ratio 4 : 1
=============
===============================================================================
D. CURRENT RATIO (Section 7.2.4(d))
(i) Consolidated current assets of the Borrower and
its Subsidiaries, as determined in accordance with GAAP
$_____________
(ii) Consolidated current liabilities of the Borrower and
its Subsidiaries, as determined in accordance with GAAP
$_____________
CURRENT RATIO ((i)/(ii))
=============
Minimum ratio 1 : 1
=============
Exhibit F - Page 6
<PAGE>
EXHIBIT Y
HEDGING POLICY
--------------
[to be attached]
Exhibit Y - Page 1
<PAGE>
EXHIBIT 11
MARKWEST HYDROCARBON, INC.
COMPUTATION OF EARNINGS PER COMMON SHARE
(000s, except per share data)
For the year ended
December 31, 1997
------------------
Net income 7,847
Weighted average number of outstanding
shares of common stock 8,485
Basic earnings per share $ 0.92
==================
Net income 7,847
Weighted average number of outstanding
shares of common stock 8,485
Dilutive stock options 129
------------------
8,614
Earnings per share assuming dilution $ 0.91
==================
<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, 1998 appearing on page 18 of
this Form 10-K.
PRICE WATERHOUSE LLP
Denver, Colorado
March 25, 1998
<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 1997 FORM 10-K AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 1,493
<SECURITIES> 0
<RECEIVABLES> 10,270
<ALLOWANCES> 120
<INVENTORY> 5,141
<CURRENT-ASSETS> 22,172
<PP&E> 81,269
<DEPRECIATION> (15,439)
<TOTAL-ASSETS> 98,657
<CURRENT-LIABILITIES> 7,569
<BONDS> 34,087
0
0
<COMMON> 85
<OTHER-SE> 51,463
<TOTAL-LIABILITY-AND-EQUITY> 98,657
<SALES> 78,415
<TOTAL-REVENUES> 79,917
<CGS> 45,657
<TOTAL-COSTS> 45,657
<OTHER-EXPENSES> 22,243
<LOSS-PROVISION> 120
<INTEREST-EXPENSE> 826
<INCOME-PRETAX> 12,397
<INCOME-TAX> 4,550
<INCOME-CONTINUING> 7,847
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 7,847
<EPS-PRIMARY> 0.92
<EPS-DILUTED> 0.91
</TABLE>
