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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, 1996
[ ] Transition report pursuant to section 13 or 15(d) of the Securities
Exchange Act of 1934 [No Fee Required] for the transition period from
__________ to ____________
COMMISSION FILE NUMBER 1-11566
MARKWEST HYDROCARBON, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 84-1352233
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
5613 DTC PARKWAY, SUITE 400, ENGLEWOOD, COLORADO 80111
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 303-290-8700
Securities registered pursuant to Section 12(b) of the Act:
TITLE OF EACH CLASS NAME OF EXCHANGE ON WHICH REGISTERED
------------------- ------------------------------------
Common Stock, $.01 par value Nasdaq National Market
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
--- ---
The aggregate market value of voting common stock held by non-affiliates of the
registrant on March 17, 1997 was $48,695,252.
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Report (Items 10, 11, 12 and 13) is
incorporated by reference from the registrant's proxy statement to be filed
pursuant to Regulation 14A with respect to the annual meeting of stockholders
scheduled to be held on June 6, 1997.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. [X]
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MARKWEST HYDROCARBON, INC.
FORM 10-K
TABLE OF CONTENTS
Page
----
PART I
Items 1. and 2. Business and Properties........................... 3
Item 3. Legal Proceedings......................................... 14
Item 4. Submission of Matters to a Vote of Security Holders....... 14
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters............................................ 15
Item 6. Selected Financial Data................................... 16
Item 7. Management's Discussions and Analysis of Financial
Condition and Results of Operation............................. 17
Item 8. Financial Statements and Supplementary Data............... 22
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure............................ 40
PART III
Item 10. Directors and Executive Officers of the Registrant....... 40
Item 11. Executive Compensation................................... 40
Item 12. Security Ownership of Certain Beneficial Owners and
Management..................................................... 40
Item 13. Certain Relationships and Related Transactions........... 40
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K....................................................... 40
2
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
GENERAL
.
MarkWest Hydrocarbon, Inc. (the "Company" or "MarkWest") is engaged in natural
gas processing and related services. The Company, which has grown substantially
since its founding in 1988, is the largest processor of natural gas in
Appalachia, and recently established a venture to provide natural gas processing
services in western Michigan. The independent gas processing industry has grown
rapidly in the last 10 years, and the Company believes there will be substantial
opportunities to grow its gas processing operations within these existing core
regions and in new markets. The Company provides compression, gathering,
treatment, and natural gas liquids (NGL) extraction services to natural gas
producers and pipeline companies and fractionates NGLs into marketable products
for sale to third parties. The Company also purchases, stores and markets
natural gas and NGLs and has begun to conduct strategic exploration for new
natural gas sources for its processing activities. For the year ended December
31, 1996, MarkWest produced approximately 95 million gallons of NGLs and
marketed approximately 137 million gallons of NGLs.
The Company's processing and marketing operations are concentrated in two core
areas that are significant gas-producing basins: the southern Appalachian region
of eastern Kentucky, southern West Virginia, and southern Ohio (the "Appalachian
Core Area"), and western Michigan (the "Michigan Core Area"). At the Company's
processing plants, natural gas is treated to remove contaminants, and NGLs are
extracted and fractionated into propane, normal butane, isobutane and natural
gasoline. The Company then markets the fractionated NGLs to refiners,
petrochemical companies, gasoline blenders, multistate and independent propane
dealers, and propane resellers. In addition to processing and NGL marketing, the
Company engages in terminalling and storage of NGLs in a number of NGL storage
complexes in the central and eastern United States and operates propane
terminals in Arkansas and Tennessee.
During 1996, the Company took several key steps to expand its operations. In
January 1996, the Company commissioned a new natural gas liquids extraction
plant in Wayne County, West Virginia. In May 1996, the Company established West
Shore Processing Company, LLC ("West Shore"), a venture in western Michigan,
which the Company will develop as the Michigan Core Area. The Company has
identified opportunities, and has entered into agreements, to expand its gas
gathering operations and to commence gas processing operations in the Michigan
Core Area in the near future. See "Natural Gas Processing and Related Services."
The Company's principal offices are located at 5613 DTC Parkway, Suite 400,
Englewood, Colorado 80111, and its telephone number is (303) 290-8700. The
Company was incorporated in Delaware in 1996.
NATURAL GAS PROCESSING AND RELATED SERVICES
The Company's processing operations are located in its Appalachian Core Area
consisting of eastern Kentucky, southern West Virginia, and southern Ohio, and
its Michigan Core Area consisting of the area of western Michigan north of Grand
Rapids and south of Traverse City. The Company's operations in Appalachia date
from the Company's founding in 1988. At present, the Company is the largest
processor of natural gas in Appalachia based on the volume of natural gas
processed at its owned facilities, including those it leases to third parties.
The Company began development of the Michigan Core Area in June 1996.
3
APPALACHIAN CORE AREA
The Company's operations in Appalachia consist of two extraction facilities, a
fractionation plant, an NGL pipeline, rail terminals and related processing
assets. Since 1988, the volume of natural gas processed by the Company in the
Appalachian Core Area has grown to approximately 170 MMcf/D, and the Company's
NGL production has grown to approximately 275 MGal/D.
The Company believes that this region has favorable supply and demand
characteristics. The Appalachian Core Area is geographically situated between
the TET pipeline to the north and the Dixie pipeline to the south. In addition
to Appalachia, the TET pipeline serves the upper midwestern and eastern United
States, and the Dixie pipeline serves the southeast. Because the areas directly
served by these two pipelines are experiencing significant population growth,
the demand for NGL products exceeds the capacity of these two lines. The demand
for propane from the TET and Dixie pipelines is such that the pipelines allocate
supply to purchasers during peak wintertime periods, thereby limiting the
available supply to Appalachia. There are few sources of propane to the
Appalachian Core Area other than the Company's facilities, the TET and Dixie
pipelines, and propane shipped by rail cars from other producing areas. In
addition, the Appalachian mountain range limits access to the Dixie pipeline by
distributors in the Appalachian Core Area. These factors enable producers in
Appalachia (principally MarkWest, Ashland Oil Company and CNG Transmission
Corporation) to price their products (particularly propane) at a premium to Gulf
Coast spot prices during times of supply shortages from other sources,
especially during winter high demand periods. The underground storage caverns at
the Company's Siloam location allow the Company to defer sales of NGLs to the
winter months when peak demand periods often lead to higher product prices and
provide local consumers with needed wintertime supplies. The Company also
believes that there are significant growth opportunities in this region both
from the improvement of gas processing efficiencies for existing gas production
in the area and the Company's capacity to process natural gas streams from areas
that are not currently processed.
NGL Extraction. The Company currently owns two NGL extraction plants in
Appalachia, one which it operates and one which it leases to Columbia Gas
Transmission Company ("Columbia Gas"). Extraction plants remove NGLs, as well as
water vapor, solids and other contaminants, such as hydrogen sulfide or carbon
dioxide, contained in the natural gas stream. The Company provides NGL
extraction services under a fee-based arrangement.
Kenova Plant. The Company began construction of its Kenova natural gas liquids
extraction plant, located in Wayne County, West Virginia, in 1995. The Kenova
plant was commissioned in January 1996 and replaced a 1958 extraction facility
owned and operated by Columbia Gas. Because the Company owns and operates this
new facility, which is situated on a main gathering line of Columbia Gas, the
Company will generate fee revenues related to the processing operations. In
addition, the Company believes that this new facility will generate greater NGL
recovery from natural gas, reduce downtime for maintenance, and significantly
reduce fuel costs compared to the replaced facility. Construction and related
costs for development of the Kenova plant were approximately $12.2 million. To
date, substantially all of Kenova's processing throughput has been obtained from
Columbia Gas. Substantially all of the Kenova plant's extracted NGLs are
transported via the Company's 38.5 mile high pressure pipeline to its Siloam
fractionation facility located in South Shore, Kentucky, for separation into
marketable NGL products.
Boldman Plant. The Company constructed the Boldman natural gas liquids
extraction plant, located in Pike County, Kentucky, in 1991. Construction and
related costs for development of the Boldman plant were approximately $4.0
million. The Boldman plant is currently leased to, and operated by, Columbia
Gas. Under such lease, the Company receives a monthly rental fee ranging from
$40,000 to $47,000. Columbia Gas also has an option to purchase the Boldman
plant at set prices during the term and upon expiration of the lease. Columbia
Gas has dedicated all NGLs recovered at the Boldman plant to the Company's
Siloam facility for fractionation under a contract which runs through December
31, 2003. This production is transported via tanker trucks from the Boldman
plant to the Siloam plant for processing.
4
NGL Pipeline. The Company owns a 38.5 mile, high pressure steel pipeline that
connects its Kenova processing plant to the Company's Siloam fractionation
facility. The pipeline currently delivers approximately 70 million gallons per
year to the Siloam facility from the Kenova processing plant. Because this
pipeline was originally designed to handle a high pressure ethane-rich stream,
it has the capacity to handle almost twice as much product if it becomes
available.
Fractionation. The Company's fractionation services in the Appalachian Core
Area are performed at its Siloam fractionation plant located in South Shore,
Kentucky. At this facility, extracted NGLs are subjected to various processes
that cause the natural gas to separate, or fractionate, into separate NGL
products, including propane, isobutane, normal butane and natural gasoline. The
Siloam facility is one of only two fractionation plants in the Appalachian Core
Area producing over 6,500 barrels, or 275,000 gallons, per day of NGLs.
Substantially all of the Company's fractionation services in its Appalachian
Core Area are provided under keep-whole contracts with Columbia Gas.
The Company acquired the Siloam plant in April 1988 from Columbia Gas for $3.5
million. During 1989, the Company began an approximately $11.0 million expansion
program at the Siloam plant. The expansion program, among other enhancements,
included the construction of additional storage facilities, improvements to
existing electrical and control systems and the addition of loading facilities.
The expansion was fully operational in early 1991.
Approximately 77% of the fractionation throughput at the Siloam plant comes from
the production of the Company's Kenova and Boldman plants. The Company also
makes purchases of NGLs from third-party processors and of additional production
from Columbia Gas. The Company's most significant purchase contract for NGLs is
with Columbia Gas. In addition to the approximately 9.0 MMGal per year of
Columbia Gas NGL production from the Boldman plant, Columbia Gas dedicates
approximately 17.0 MMGal per year from its Cobb, West Virginia extraction plant.
Pursuant to the Columbia Gas purchase agreements, the Company is committed to
purchase substantially all of the NGLs produced at Columbia Gas' own processing
plants, as well as those produced by the Company for Columbia Gas. Under these
contracts, the Company is required to compensate Columbia Gas for the BTU energy
equivalent of NGLs and fuel removed from the natural gas as a result of
processing. In 1996, the Company's cost for purchases under these contracts was
$23 million, and such purchases represented 95% of all NGLs fractionated by the
Company.
MICHIGAN CORE AREA
The Company was attracted to the Michigan Core Area because of the potential for
providing gathering and processing services in the area. Substantially all of
the natural gas in the Michigan Core Area is sour and, therefore, has limited
outlets for processing. West Shore was formed in May 1996 and is governed by an
operating agreement between MarkWest Michigan, Inc. and Michigan Energy Company
("MEC"). West Shore is a venture dedicated to natural gas gathering, treatment,
processing and NGL marketing in Manistee, Mason and Oceana Counties in Michigan.
As a result of availability of large shut-in sour gas wells and the expected
increase in drilling by producers who previously had no outlet for sour gas
production in the area, the Company entered into several related agreements in
May 1996 providing for the development of gathering, treatment and processing
facilities in western Michigan. Through West Shore, the Company expects to be
able to gather and process this sour gas.
The most significant assets of West Shore currently include the Basin Pipeline,
a 31-mile sour gas pipeline which is situated in Manistee and Mason Counties,
rights to obtain a sour gas treatment plant located in Manistee County,
Michigan, and various agreements that dedicate natural gas production to West
Shore for processing. Until completion of the second phase of the Michigan
Project, West Shore's revenues will be derived from fees generated by gathering
of natural gas on the Basin Pipeline and by treatment of sour gas. Following
completion of the second phase, revenues will be derived from fees generated by
gathering, treatment and extraction and fractionation of NGLs.
5
The Michigan Project is completing its first phase of development, which
includes construction of a two-mile pipeline from one of West Shore's main
gathering locations to a treatment plant owned and operated by Shell Offshore,
Inc. ("Shell") in Manistee County. The purpose of this pipeline is to deliver
sour gas to Shell for treatment. The first phase also includes the construction
of a 30-mile pipeline that will connect the Slocum natural gas well owned by MPC
in Oceana County to the Basin Pipeline. Initially West Shore will operate this
pipeline for Michigan Production Company, L.L.C. ("MPC") as an individual well
pipeline. Following approval from the Michigan Public Service Commission, Basin
will acquire the pipeline from MPC and will operate it to gather gas from
additional wells in Mason and Oceana counties. The Slocum well has estimated
reserves of approximately 13 Bcf, and estimated initial well deliverabilities of
approximately 8 MMcf/D. The first phase of the Michigan Project will cost
approximately $11 million.
The second phase of the Michigan Project includes construction of a two-mile
residue return line from the Shell treatment plant to the natural gas
transmission line of Michigan Consolidated Gas Company ("MichCon") and
construction of approximately 18 miles of pipeline to connect natural gas wells
in southern Oceana County, including the Claybanks wells owned by MPC, with
estimated reserves of approximately 7.5 Bcf and estimated initial well
deliverabilities of approximately 8 MMcf/D, to the Basin Pipeline. The second
phase will also include the construction of an NGL extraction and fractionation
facility at the site of the Shell treatment plant. The facility will be owned by
West Shore and operated by Shell. The Company currently expects that the second
phase of the Michigan Project will be completed by the end of the fourth quarter
of 1997. The second phase of the Michigan Project is expected to cost
approximately $9 million.
When the first two phases of the Michigan Project are complete, the Company will
own a 60% interest in West Shore. As of December 31, 1996, the Company had made
contributions of approximately $10.4 million and owns a 47% interest.
Upon completion of the first two phases of development, West Shore's treating
and processing operations are expected to have 30 MMcf/D of capacity and
approximately 25 MMcf/D of dedicated production from currently drilled and
proven wells. With a current pipeline capacity of 35 MMcf/D and deliverabilities
of individual wells commonly exceeding 5 MMcf/D, the Company expects that demand
at West Shore could exceed capacity. As a result, the Company is already
planning to expand West Shore to increase capacity in the second phase of the
Michigan Project. There can be no assurance, however, that demand for West
Shore's services will reach the levels anticipated by the Company.
Availability of Natural Gas Supply. West Shore has exclusive gathering,
treatment and processing agreements with Michigan Production Company ("MPC")
covering the natural gas production from all wells and leases presently owned by
MPC within Manistee, Mason and Oceana Counties, Michigan. In addition, West
Shore has a gathering, treating and processing agreement with Oceana Acquisition
Company ("Oceana") covering the production from the initial phase of Oceana's
drilling program in Oceana County, Michigan. West Shore also is negotiating an
agreement with Longwood Exploration Company ("Longwood") that may result in the
dedication of its natural gas production to the pipeline, treatment and
processing facilities of West Shore.
The Company believes that the expansion of the Basin Pipeline southward will
provide an outlet for sour gas production in the area and may stimulate new
drilling activity in the area. Both MPC and Longwood are considering initiating
drilling programs in the area, to begin by early 1997. Production from the MPC
program has been dedicated to the Basin Pipeline, and West Shore is negotiating
with Longwood for dedication of its production to the Basin Pipeline. MarkWest
Resources, Inc. ("Resources"), a wholly owned subsidiary of the Company, has
agreed to purchase a 17.5% working interest in the Longwood drilling program.
MarkWest also has had discussions with other exploration companies that are
evaluating possible exploration and production activities in the corridor to be
serviced by the expanded Basin Pipeline. MarkWest currently is evaluating
various drilling programs and expects to participate actively in drilling wells
in the area.
6
The natural gas streams to be dedicated to West Shore under these agreements
will primarily be produced from an extension of the Northern Niagaran Reef trend
in western Michigan. To date, over 2.5 trillion cubic feet equivalent of natural
gas has been produced from the Northern Niagaran Reef trend. Substantially all
of the natural gas produced from the western region of this trend, however, is
sour. While several successful large wells were developed in the region, the
natural gas producers lacked adequate gathering and treatment facilities for
sour gas, and development of the trend stopped in northern Manistee County. With
the sour gas pipeline, treatment and processing facilities and capacity to be
provided by West Shore, the Company believes there could be increased
development in the region. In addition, the Company believes that improvements
in seismic technology may increase exploration and production efforts, as well
as drilling success rates.
Shell Treatment and Processing Agreement. In addition to the establishment of
West Shore, the Michigan Project includes a number of related agreements. To
provide treatment for natural gas dedicated to West Shore, West Shore has
entered into a gas treatment and processing agreement with Shell. Currently, the
agreement provides West Shore with 30 MMcf/D of gas treatment capacity at
Shell's facility in Manistee County, Michigan. The agreement also permits West
Shore to cause the expansion of Shell's treatment facilities. In addition, the
agreement grants West Shore the right to construct and install an NGL processing
plant at the site of Shell's treatment plant. Following completion of the new
processing plant, Shell will act as contract operator for West Shore.
GAS PROCESSING CONTRACTS AND NATURAL GAS SUPPLY
The Company historically has processed natural gas under two types of
arrangements: keep-whole and fee-based processing. While the Company has been
heavily dependent upon keep-whole contracts in the past, it intends to pursue
fee-based processing contracts in the future to reduce the fluctuations in
margins inherent in processing natural gas under keep-whole arrangements.
Keep-Whole Contracts. Under keep-whole contracts, the principal cost is the
reimbursement to the natural gas producers for the BTUs extracted from the gas
stream in the form of liquids or consumed as fuel during processing. In such
cases, the Company creates operating margins by maximizing the value of the NGLs
extracted from the natural gas stream and minimizing the cost of replacement of
BTUs. While the Company maintains programs to minimize the cost to deliver the
replacement of fuel and shrinkage to the natural gas supplier, the Company's
margins under keep-whole contracts can be negatively affected by either
decreases in NGL prices or increases in prices of replacement natural gas.
Approximately 59% of the Company's total revenue during 1996 resulted from keep-
whole contracts.
Fee Contracts. The Company has entered into a fee-based contract with Columbia
Gas, which expires December 31, 2010, pursuant to which Columbia Gas has agreed
to use its best efforts to deliver a minimum of 115 MMcf/D of natural gas to the
Company's Kenova processing plant, and the Company has agreed to process all
natural gas made available by Columbia Gas to the Company at the Kenova plant.
In 1996, deliveries by Columbia Gas to the Kenova plant under this contract
represented approximately 95% of all throughput processed by the Company. Under
the agreement, Columbia Gas pays the Company a fee per MMbtu of processed
natural gas. The terms of the contract provide for automatic two-year extensions
after 2010, unless either party gives notice to terminate the contract at least
one year in advance of an expiration date. In its Michigan Core Area, West Shore
has entered into a fee-based contract with MPC, which expires December 2016,
pursuant to which MPC has agreed to use its best efforts to deliver all of its
natural gas to West Shore's pipeline and treating facilities. Under the
agreement, MPC pays West Shore a fee per MMbtu of transported and treated
natural gas. Approximately 5% of the Company's total revenues during 1996
resulted from fee-based contracts.
Percent-of-Proceeds Contracts. Under percent-of-proceeds contracts, the Company
retains a portion of NGLs and/or natural gas as compensation for the processing
services provided. Operating revenues earned by the Company under percent-of-
proceeds contracts increase proportionately with the price of NGLs and natural
gas sold. While historically the Company has not entered into percent-of-
proceeds contracts,
7
recently the Company offered to process natural gas for certain suppliers in the
Appalachian Core Area under percent-of-proceeds arrangements.
The Company and Columbia Gas are in the process of negotiating fee and/or
percent-of-proceeds arrangements whereby the Company will process natural gas
directly for third-party shippers who utilize Columbia Gas's pipeline and
distribution system. In addition, part of the fee structure for transporting and
treating natural gas in the Michigan Core Area includes retaining a portion of
extracted NGLs.
SALES AND MARKETING
The Company attempts to maximize the value of its NGL output by marketing to
distributors, resellers, blenders, refiners and petrochemical companies. The
Company minimizes the use of third-party brokers and instead supports a direct
marketing staff focused on multistate and independent dealers. Additionally, the
Company uses its own truck and tank car fleet, as well as its own terminals and
storage facilities, to enhance supply reliability to its customers. All of these
efforts have allowed the Company to maintain premium pricing of its NGL products
compared to Gulf Coast spot prices.
Substantially all of the Company's revenue is derived from sales of NGLs,
particularly propane. Revenues from NGLs represented 91%, 98% and 88% of total
revenues, excluding gains on sale of property, in each of 1996, 1995 and 1994,
respectively. The Company markets and sells NGLs to numerous customers,
including refiners, petrochemical companies, gasoline blenders, multistate and
independent propane distributors and propane resellers. The majority of the
Company's sales of NGLs are based on spot prices at the time the NGLs are sold.
Spot market prices are based upon prices and volumes negotiated for short terms,
typically 30 days.
EXPLORATION AND PRODUCTION
The Company maintains a strategic gas exploration effort intended to permit the
Company to gain a foothold position in production areas that have strong
potential to create demand for its processing services. The Company, through
Resources, currently owns interests in several exploration and production
assets. Such assets include the following:
. A 49% undivided interest in two separate exploration and production projects
in La Plata County, Colorado, situated on the Fruitland Formation coal seam.
One project currently contains nine coal seam wells that produce approximately
2,300 Mcf/D of natural gas. It is estimated that full development of these two
projects will cost the Company approximately $3.2 million through the end of
1997.
. A 5.4% working interest in a 66-well drilling program operated by Conley
Smith, Denver, Colorado. The majority of these well sites are in Oklahoma,
Kansas, Nevada and Texas. MarkWest believes it may have a future opportunity
to provide its processing expertise to Conley Smith in the areas with
successful drilling sites. There can be no assurance, however, that Conley
Smith will use the Company's processing services.
. A 25% working interest in a 31,000-acre project to be developed in the
Piceance Basin of Colorado. The project includes both the exploration for
conventional natural gas and the development of the Cameo Coal Formation
utilizing tax credit qualified existing well bores. While there can be no
assurance that these projects will generate substantial natural gas volumes,
MarkWest believes that this area could generate increased demand for
processing services.
. A 17.5% working interest in the drilling program of the Niagran Reef Trend in
the Michigan Core Area. Longwood intends to conduct a 25-square-mile three-
dimensional seismic survey in the prospective area and thereafter acquire
acreage and conduct drilling activities.
8
PROPERTIES
The following table provides information concerning the Company's principal gas
processing plants and gathering facilities.
YEAR ACQUIRED GAS NGL PRODUCTION
OR PLACED THROUGHPOUT THROUGHPUT THROUGHPUT
INTO SERVICE CAPACITY (Mcf/D)/a, b/ (Gal/YEAR)/b/
---------------------------------------------------------------------
PROCESSING PLANTS
Siloam Fractionation Plant,
South Shore, KY (1)..................... 1988 360,000 Gal/D NA 94,909,000
Boldman Extraction Plant,
Pike County, KY (2)..................... 1991 70,000 Mcf/D 55,000 8,461,000
Kenova Extraction Plant,
Wayne County, WV (3).................... 1996 120,000 Mcf/D 115,000 65,443,000
PIPELINES
38.5-mile Kenova--Siloam NGL pipeline
Wayne County, WV to
South Shore, KY (4)..................... 1988 350,000 Gal/D NA 65,443,000
31-mile sour gas gathering line
Manistee County, MI (3)................. 1996 35,000 Mcf/D 5,500 NA
YEAR ACQUIRED STORAGE
OR PLACED CAPACITY ANNUAL SALES
INTO SERVICE (Gal) (Gal/YEAR)/b/
------------------------------------------------
TERMINAL AND STORAGE
Siloam Fractionation Storage
South Shore, KY (1).................................... 1988 14,000,000 94,909,000
Terminal and Storage
West Memphis, AR (5)................................... 1992 2,500,000 33,798,000
Terminal and Storage
Church Hill, TN (6).................................... 1995 240,000 4,053,000
- ------------
/a/ Mcf/D = cubic feet per day
/b/ For the year ended December 31, 1996
(1) At the Siloam Fractionation Plant facility, extracted NGLs are subjected to
various processes that cause the natural gas to separate, or fractionate,
into separate NGL products, including propane, isobutane, normal butane and
natural gasoline. The Siloam plant, situated on approximately 290 Company-
owned acres, also has over 14.0 million gallons of on-site product storage,
including an 8.4-million-gallon propane underground storage cavern, a 3.1-
million-gallon butane underground storage cavern, and approximately 3.0
million gallons of above-ground storage tanks. The Siloam plant is served by
the following modern loading and unloading facilities: four automated truck
loading docks for propane/butane; two automated truck unloading docks for
mixed feedstock; one automated bottom-loading dock for natural gasoline;
truck scales; a rail siding capable of holding over 20 railcars and
simultaneously loading or unloading eight cars; and barge facilities for the
loading of natural gasoline and butanes.
9
(2) The Boldman plant is a refrigeration plant that extracts NGLs by cooling
natural gas down to minus 20 degrees Fahrenheit. The plant includes two
60,000-gallon product storage tanks and truck-loading facilities. The
Boldman plant is currently leased to, and operated by, Columbia Gas.
(3) See "Natural Gas Processing and Related Services".
(4) The Company owns a 38.5-mile, high-pressure steel pipeline that connects its
Kenova processing plant to the Company's Siloam fractionation facility.
Because this liquids pipeline was originally designed to handle a high-
pressure ethane-rich stream, it has the capacity to handle almost twice as
much product if it becomes available.
(5) At the West Memphis terminal (a seven-acre propane terminal and storage
facility), the Company maintains 45 pressurized storage tanks that have a
storage capacity of just over 2.5 million gallons of NGLs. The terminal has
an automated loading facility with two loading docks for propane, operating
24 hours per day, seven days per week. The West Memphis terminal is capable
of serving railcar and trucking transportation. An adjoining Union Pacific
rail siding holds up to 17 railcars and has 6 loading/unloading stations.
The terminal is located approximately 1/4 mile from the Mississippi River
and is secured by a long-term lease held by the Company.
(6) The Company leases and operates a propane terminal in Church Hill,
Tennessee, which principally receives product by rail and redelivers the
product to dealers and resellers by truck. The Church Hill terminal has
240,000 gallons of pressurized storage, an automated truck loading station
and a rail siding that can hold four cars and has two unloading stations.
Executive Offices. MarkWest occupies approximately 12,000 square feet of space
at its executive offices in Denver, Colorado under a lease expiring in March
1997. While the Company will require additional office space as its business
expands, the Company believes that its existing facilities are adequate to meet
its needs for the immediate future, and that additional facilities will be
available on commercially reasonable terms as needed.
COMPETITION
The Company faces intense competition in obtaining natural gas supplies for its
gathering and processing operations, in obtaining processed NGLs for
fractionation and in marketing its products and services. The Company's
principal competitors include major integrated oil and gas companies, such as
Ashland and Amoco Oil Co.; major interstate pipeline companies, such as CNG
Transmission Corporation; NGL processing companies, such as Natural Gas
Clearinghouse; and national and local gas gatherers, brokers, marketers and
distributors of varying sizes, financial resources and experience. Many of the
Company's competitors, such as major oil and gas and pipeline companies, have
capital resources and control supplies of natural gas substantially greater than
those of the Company. Smaller local distributors may enjoy a marketing advantage
in their immediate service areas.
The Company competes against other companies in its gas processing business both
for supplies of natural gas and for customers to which it sells its products.
Competition for natural gas supplies is based primarily on location of gas
gathering facilities and gas processing plants, operating efficiency and
reliability, and ability to obtain a satisfactory price for products recovered.
Competition for customers is based primarily on price, delivery capabilities,
and maintenance of quality customer relationships.
The Company's fractionation business competes against other fractionation
facilities that serve local markets. Competitive factors affecting the Company's
fractionation business include proximity to industry marketing centers and
efficiency and reliability of service.
In marketing its products and services, the Company has numerous competitors,
including interstate pipelines and their marketing affiliates, major producers,
and local and national gatherers, brokers, and marketers of widely varying
sizes, financial resources and experience. Marketing competition is primarily
based upon reliability, transportation, flexibility and price.
OPERATIONAL RISKS AND INSURANCE
The Company's operations are subject to the usual hazards incident to the
exploration for and production, transmission, processing and storage of natural
gas and NGLs, such as explosions, product spills, leaks,
10
emissions and fires. These hazards can cause personal injury and loss of life,
severe damage to and destruction of property and equipment, and pollution or
other environmental damage, and may result in curtailment or suspension of
operations at the affected facility.
The Company maintains general public liability, property and business
interruption insurance in amounts that it considers to be adequate for such
risks. Such insurance is subject to deductibles that the Company considers
reasonable and not excessive. Consistent with insurance coverage generally
available to the NGL industry, the Company's insurance policies do not provide
coverage for losses or liabilities related to pollution or other environmental
damage, except for sudden and accidental occurrences.
The occurrence of a significant event not fully insured or indemnified against,
and/or the failure of a party to meet its indemnification obligations, could
materially and adversely affect the Company's operations and financial
condition. Moreover, no assurance can be given that the Company will be able to
maintain adequate insurance in the future at rates it considers reasonable. To
date, however, the Company has experienced no material uninsured losses.
GOVERNMENT REGULATION
Certain of the Company's pipeline activities and facilities are involved in the
intrastate or interstate transportation of natural gas and NGLs and are subject
to state and/or federal regulation. Historically, the transportation and sale
for resale of natural gas in interstate commerce have been regulated pursuant to
the Natural Gas Act of 1938 ("NGA"), the Natural Gas Policy Act of 1978
("NGPA"), and the regulations promulgated thereunder by the Federal Energy
Regulatory Commission ("FERC"). In the past, the federal government regulated
the prices at which oil and gas could be sold, as well as certain terms of
service. However, the deregulation of natural gas sales pricing began under
terms of the NGPA and was completed in January 1993 pursuant to the Natural Gas
Wellhead Decontrol Act of 1989 (the "Decontrol Act"). Thus, all sales by the
Company of NGLs and natural gas currently can be made at uncontrolled market
prices. There can be no assurance, however, that Congress will not reenact price
controls in the future which could apply to, or substantially affect, these
sales activities.
FERC's jurisdiction over the interstate transportation of natural gas was not
removed or limited by the NGPA or the Decontrol Act. FERC also retains
jurisdiction over the interstate transportation of liquid hydrocarbons, such as
NGLs and product streams derived therefrom. The processing of natural gas for
the removal of liquids currently is not viewed by the FERC as an activity
subject to its jurisdiction. If a processing plant's primary function is
extraction of NGLs and not natural gas transportation, the FERC has
traditionally maintained that the plant is not a facility for transportation or
sale for resale of natural gas in interstate commerce and therefore is not
subject to jurisdiction under the Natural Gas Act. Although the FERC has not
been requested to and has made no specific declaration as to the jurisdictional
status of the Company's gas processing operations or facilities, the Company
believes that because its gas processing plants are primarily involved in
removing NGLs, their processing activities are exempt from FERC jurisdiction.
Notwithstanding the foregoing, Columbia Gas is seeking abandonment approval of
the processing plant that was replaced by the Company's Kenova extraction plant.
The previous Columbia Gas processing plant was considered by FERC to be
transportation-related and was included in Columbia Gas's certificated
facilities. Because of this prior regulatory classification when owned by
Columbia Gas, the Company has specifically requested a ruling from FERC
confirming that the new Kenova extraction plant is exempt from FERC
jurisdiction. While there can be no assurance that FERC will issue such a
ruling, the Company believes, based upon opinions of legal counsel to the
Company, that such a ruling will be forthcoming. In the event FERC does not
confirm such exemption, the rates charged by the Company for processing services
at the Kenova plant would be subject to regulation by FERC, and such rates and
regulation could affect the volume of natural gas delivered to the facility by
producers. If imposed, such regulation could have a material adverse effect on
the Company's results of operations.
As part of the Michigan Project, the Company will own and operate pipeline
gathering facilities in conjunction with its processing plants. Under the NGA,
facilities which have as their "primary function"
11
the performance of gathering activities and are not owned by interstate gas
pipeline companies are wholly exempt from FERC jurisdiction. Interstate
transmission facilities, on the other hand, are subject to FERC jurisdiction.
The FERC distinguishes between these two types of activities on a fact-specific
basis, which may make it difficult to state with certainty the status of the
Company's pipeline gathering facilities. Although the FERC has not been
requested to or issued any order or opinion declaring the Company's facilities
as gathering rather than transmission facilities, based on opinion of legal
counsel, management believes these systems are NGA-exempt gathering facilities.
In addition, state and local regulatory authorities oversee intrastate gathering
and other natural gas pipeline operations.
Because the Company's NGL pipeline facilities do not transport liquids in
continuous flow in interstate commerce, they are not subject to FERC regulation
under the Interstate Commerce Act. However, the design, construction, operation,
and maintenance of the Company's NGL and natural gas pipeline facilities are
subject to the safety regulations established by the Secretary of the Department
of Transportation pursuant to the Natural Gas Pipeline Safety Act of 1968, as
amended ("1968 Act"), or by state agency regulations which meet or exceed the
requirements of the 1968 Act.
The Company's natural gas exploration and production operations are subject to
various types of regulation at the federal, state and local levels. Such
regulation includes requiring permits for the drilling of wells, meeting bonding
requirements in order to drill or operate wells and regulating the location of
wells, the methods of drilling and casing wells, the surface use and restoration
of properties upon which wells are drilled, the plugging and abandoning of wells
and the disposal of fluids used in connection with such operations. Production
operations are also subject to various conservation laws and regulations. These
typically include the regulation of the size of drilling and spacing or
proration units and the density of wells which may be drilled therein and the
unitization or pooling of oil and gas properties. Whether the state has forced
pooling, or integration of smaller tracts to form a tract large enough to
conduct drilling operations, or relies only on voluntary pooling can affect the
ease with which a property can be developed. State conservation laws also
typically establish maximum rates of production of natural gas, generally
prohibit the venting or flaring of gas and impose certain requirements regarding
the ratability of production and the handling of nonhydrocarbon gases, such as
carbon dioxide and hydrogen sulfide. The effect of these regulations may limit
the amount of oil and gas available to the Company or which the Company can
produce from its wells. They also substantially affect the cost and
profitability of conducting natural gas exploration and production activities.
Inasmuch as such laws and regulations are frequently expanded, amended or
reinterpreted, the Company is unable to predict the future cost or impact of
complying with these production-related regulations.
Commencing in April 1992, the FERC issued a series of orders, generally referred
to collectively as Order No. 636, which, among other things, require interstate
pipelines such as Columbia Gas to "restructure" to provide transportation
services separate or "unbundled" from the interstate pipelines sales of gas.
Order No. 636 also requires interstate pipelines to provide open-access
transportation on a basis that is equal for all shippers and all supplies of
natural gas. This order was implemented through pipeline-by-pipeline
restructuring proceedings. In many instances, the result has been to
substantially reduce or bring to an end interstate pipelines' traditional role
as wholesalers of natural gas in favor of providing only storage and
transportation services. On July 16, 1996, the United States Court of Appeals
for the District of Columbia Circuit upheld the validity of most of the
provisions and features of Order No. 636. However, in many instances, appeals
remain outstanding in the individual pipeline restructuring proceedings, so the
Company cannot predict the final outcome of these proceedings. Order No. 636 is
intended to foster increased competition within all phases of the natural gas
industry. It remains unclear what impact, if any, increased competition within
the natural gas industry under Order No. 636 will have on the Company or its
various lines of business. Additionally, the FERC has issued a number of other
orders which are intended to supplement various facets of its open access
program, all of which will continue to affect how and by whom natural gas
production and associated NGLs will be transported and sold in the marketplace.
In its current form, FERC's open access initiatives could provide the Company
with additional access to gas supplies and markets and could assist the Company
and its customers by mandating more fairly applied service rates, terms and
conditions. On the other hand, it could also subject the Company and entities
with
12
which it does business to more restrictive pipeline imbalance tolerances,
more complex operations and greater monetary penalties for violation of the
pipelines tolerances and other tariff provisions. The Company does not believe,
however, that it will be affected by any action taken with respect to Order No.
636 materially differently than any other producers, gatherers, processors or
marketers with which it competes.
ENVIRONMENTAL MATTERS
The Company is subject to environmental risks normally incident to the operation
and construction of gathering lines, pipelines, plants and other facilities for
gathering, processing, treatment, storing and transporting natural gas and other
products including, but not limited to, uncontrollable flows of natural gas,
fluids and other substances into the environment, explosions, fires, pollution,
and other environmental and safety risks. The following is a discussion of
certain environmental and safety concerns related to the Company. It is not
intended to constitute a complete discussion of the various federal, state and
local statutes, rules, regulations, or orders to which the Company's operations
may be subject. For example, the Company, without regard to fault, could incur
liability under the Comprehensive Environmental Response, Compensation, and
Liability Act of 1980, as amended (also known as the "Superfund" law), or state
counterparts, in connection with the disposal or other releases of hazardous
substances, including sour gas, and for natural resource damages. Further, the
recent trend in environmental legislation and regulations is toward stricter
standards, and this will likely continue in the future.
The Company's activities in connection with the operation and construction of
gathering lines, pipelines, plants, injection wells, storage caverns, and other
facilities for gathering, processing, treatment, storing, and transporting
natural gas and other products are subject to environmental and safety
regulation by federal and state authorities, including, without limitation, the
state environmental agencies and the federal Environmental Protection Agency
("EPA"), which can increase the costs of designing, installing and operating
such facilities. In most instances, the regulatory requirements relate to the
discharge of substances into the environment and include measures to control
water and air pollution.
Environmental laws and regulations may require the acquisition of a permit or
other authorization before certain activities may be conducted by the Company.
These laws also include fines and penalties for non-compliance. Further, these
laws and regulations may limit or prohibit activities on certain lands lying
within wilderness areas, wetlands, areas providing habitat for certain species
or other protected areas. The Company is also subject to other federal, state,
and local laws covering the handling, storage or discharge of materials used by
the Company, or otherwise relating to protection of the environment, safety and
health. The Company believes that it is in material compliance with all
applicable environmental laws and regulations.
EMPLOYEES
As of December 31, 1996, the Company had 84 employees.
Eighteen employees at the Company's Siloam fractionation facility in South
Shore, Kentucky, are represented by the Oil, Chemical and Atomic Workers
International Union, Local 3-372 (Siloam Sub-Local). The Company recently
negotiated a new collective bargaining agreement with this Union that is
effective May 1, 1996, and expires on April 30, 2000. The agreement covers only
hourly, nonsupervisory employees. The Company considers labor relations to be
satisfactory at this time.
RISK FACTORS
This Annual Report on Form 10-K contains statements which, to the extent that
they are not recitations of historical fact, constitute "forward looking
statements" within the meaning of Section 27A of the Securities and Exchange Act
of 1933 and Section 21E of the Securities and Exchange Act of 1934. All forward
13
looking statements involve risks and uncertainties. The forward looking
statements in this document are intended to be subject to the safe harbor
protection provided by Sections 27A and 21E. Factors that most typically impact
the Company's operating results and financial condition include (i) changes in
general economic conditions in regions in which the Company's products are
located, (ii) the availability and prices of NGLs and competing commodities,
(iii) the availability of raw natural gas supply, (iv) the ability of the
Company to negotiate favorable marketing agreements, (v) the risks that natural
gas exploration and production activities will not be successful, (vi) the
Company's dependence on certain significant customers, (vii) competition from
other NGL processors, including major oil and gas companies, and (viii) the
Company's ability to identify and consummate acquisitions complementary to its
business. For discussions identifying other important factors that could cause
actual results to differ materially from those anticipated in the forward
looking statements, see the Company's Securities and Exchange Commission
filings; and "Management's Discussion and Analysis of Financial Conditions and
Results of Operations" of this Form 10-K.
ITEM 3. LEGAL PROCEEDINGS
The Company is not currently a party to any legal proceedings, and is not aware
of any threatened litigation, the adverse outcome of which, individually or in
the aggregate, would have a material adverse effect on the Company's financial
condition or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the quarter
ended December 31, 1996.
14
PART II
ITEM 5. MARKET FOR THE REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
As of January 29, 1997, there were 8,485,000 shares of Common Stock outstanding
held by 410 holders of record. The Common Stock is traded on the Nasdaq
Exchange under the symbol "MWHX". The following table sets forth quarterly
high and low closing sales prices as reported by the Nasdaq National Market for
the periods indicated.
HIGH LOW
------- -------
1996
Fourth Quarter................... 15 1/2 10 1/4
The Company has paid no dividends on the Common Stock, and anticipates that, for
the foreseeable future, it will continue to retain earnings for use in the
operation of its business. Payment of cash dividends in the future will depend
upon the Company's earnings, financial condition, any contractual restrictions,
restrictions imposed by law and other factors deemed relevant by the Company's
Board of Directors.
15
ITEM 6. SELECTED FINANCIAL DATA
The selected consolidated statement of operations and balance sheet data for the
years ended December 31, 1996, 1995 and 1994 and as of December 31, 1996 and
1995 are derived from, and are qualified by reference to, audited consolidated
financial statements of the Company included elsewhere in this Form 10-K. The
selected consolidated statement of operations and balance sheet data set for
below for the years ended December 31, 1993 and 1992 and as of December 31, 1993
and 1992 have been derived from audited financial statements not included in
this Form 10-K. The selected consolidated financial information set forth below
should be read in conjunction with "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the Company's Consolidated
Financial Statements and related notes thereto included elsewhere in this Form
10-K.
Year Ended December 31,
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
(in thousands, except per share and operating data)
STATEMENT OF OPERATIONS:
Revenues................................ $ 71,952 $ 48,226 $ 52,963 $ 55,871 $ 82,977
Income (loss) before taxes,
extraordinary item and cumulative
effect of change in accounting......... 14,760 7,824 5,120 540 5,449
Income tax provision
Arising from reorganization............ 3,745 -- -- -- --
Subsequent to reorganization........... 3,246 -- -- -- --
Income before extraordinary item and
cumulative effect of change in
accounting............................. 7,769 7,824 5,120 540 5,449
Extraordinary loss...................... -- (1,750) - -- --
Cumulative effect of change in
accounting............................. -- -- -- -- 877
Net income.............................. 7,769 6,074 5,120 540 6,326
Pro forma information (1):
Historical income before extraordinary
item................................... 14,760 7,824 5,120 540 5,449
Pro forma provision for income taxes.... 5,609 2,937 1,424 228 2,060
Pro forma net income.................... 9,151 4,887 3,696 312 3,389
Pro forma earnings per share of common..
stock (2).............................. 1.16 .85
Pro forma weighted average shares
outstanding(2)......................... 7,908 5,725
BALANCE SHEET DATA:
Total assets............................ $ 78,254 $ 46,896 $ 35,913 $ 40,668 $ 41,092
Long-term debt.......................... 11,257 17,500 9,887 16,486 11,750
Partners' capital....................... -- 25,161 22,183 17,350 19,614
Stockholders' equity.................... 43,664 -- -- -- --
OPERATING DATA:
Fee gas processed (mbtu)................ 33,899,744 -- -- -- --
NGL production (gallons)................ 94,908,534 92,239,000 99,735,000 93,355,000 88,616,000
Terminal throughput (gallons)........... 37,851,450 31,206,000 32,664,000 30,116,000 26,273,000
Michigan pipeline throughput (mcf)...... 1,161,182 -- -- -- --
- ----------------------------------------
(1) Prior to October 7, 1996, the Company was organized as a partnership,
MarkWest Hydrocarbon Partners, Ltd. ("MarkWest Partnership") and
consequently, was not subject to income tax. Effective October 7, 1996 the
Company reorganized (the "Reorganization") and the existing general and
limited partners exchanged 100% of their interests in MarkWest Partnership
for 5,725,000 common shares of the Company. A pro forma provision for income
taxes has been presented for purposes of comparability as if the Company had
been a taxable entity for all periods presented.
16
(2) Pro forma weighted average shares outstanding at December 31, 1996
represents the weighted average of the period prior to the Offering, the
number of common shares issued in the Reorganization plus the number of
shares issued in the Offering for which the net proceeds were used to repay
outstanding indebtedness and, for the period subsequent to the Offering, the
total number of common shares outstanding. Pro forma weighted average shares
outstanding at December 31, 1995 represents the weighted average number of
common shares issued in the Reorganization.
ITEM 7. MANAGEMENT'S DISCUSSIONS AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion is intended to provide an analysis of the Company's
financial condition and results of operations for the three years ended December
31, 1996, and should be read in conjunction with the selected financial data and
the Company's Consolidated Financial Statements and related Notes thereto
included elsewhere in this Form 10-K.
RESULTS OF OPERATIONS
Year ended December 31, 1996 Compared to Year Ended December 31, 1995
Revenues. Plant revenue increased to $45.9 million from $33.8 million for the
year ended December 31, 1996 as compared to the year ended December 31, 1995, an
increase of $12.1 million or 36%. This increase is primarily a result of
price-related increases of all NGLs of $9.9 million, partially offset by a
volume-related decrease of $1.1 million. The volume decrease at the
fractionation plant at Siloam, which receives approximately 70% of its raw NGL
mix from the Kenova plant, was due principally to normal start-up delays in the
transition from an older processing facility at Kenova to the Company's new
plant in the first quarter of 1996. In addition, the new Kenova processing
plant, which was placed into service in January 1996, generated an additional
$3.5 million of fee revenue during 1996.
Terminal and marketing revenue increased to $22.9 million from $13.2 million for
the year ended December 31, 1996 as compared to the year ended December 31,
1995, an increase of $9.7 million, or 74%. This increase of $9.7 million was
due to a $5.4 million volume-related increase and a $4.3 million price-related
increase. Revenue from the West Memphis terminal accounted for $7.9 million of
the increase and the new terminal in Church Hill, Tennessee, which became
operational in the fall of 1995, accounted for $1.8 million of the increase.
The increase in revenues from the West Memphis terminal was due principally to
colder temperatures during the first and fourth quarters of 1996.
Oil and gas and other revenue increased to $3.0 million from $1.1 million for
the year ended December 31, 1996 as compared to the year ended December 31,
1995, an increase of $1.9 million, or 173%. This increase is principally due
to the consolidation of MarkWest Michigan revenue of $1.7 million, offset by a
decrease in miscellaneous revenue of approximately $100,000.
Costs and expenses. Plant feedstock purchases increased to $22.2 million from
$17.3 million for the year ended December 31, 1996 as compared to the year ended
December 31, 1995, an increase of $4.9 million or 28%. This increase is
principally due to price-related increases in raw materials.
Terminal and marketing purchases increased to $18.7 million from $11.9 million
for the year ended December 31, 1996 as compared to the year ended December 31,
1995, an increase of $6.8 million, or 57%. Increased propane prices resulted
in a $2.5 million increase, in addition to volume increases at West Memphis and
Churchill which resulted in increases of $2.9 million and $1.4 million,
respectively.
Operating expenses increased to $7.0 million from $4.7 million for the year
ended December 31, 1996 as compared to the year ended December 31, 1995, an
increase of $2.3 million, or 49%. This increase is partially due to new
operations at both the Kenova and Church Hill facilities which commenced
operations
17
in January 1996 and October 1995, respectively. Additional operating expenses
resulted from the consolidation of MarkWest Michigan operations, which began in
May 1996.
Depreciation and amortization increased to $2.9 million from $1.8 for the year
ended December 31, 1996 as compared to the year ended December 31, 1995, an
increase of $1.1 million or 61%. This increase is due principally to
depreciation attributable to the Company's new Kenova plant and MarkWest
Michigan's pipeline and facilities.
Net interest expense. Net interest expense increased to $900,000 from $400,000
for the year ended December 31, 1996 as compared to the year ended December 31,
1995, an increase of $500,000 or 125%. This increase resulted principally from
an increase in average outstanding long-term debt of $12 million for 1996
compared to $8.1 million for 1995. Additionally, $301,000 of interest was
capitalized in conjunction with capital projects in 1995, compared to only
$27,000 of interest capitalized for 1996 projects.
Income tax expense. Income tax expense increased $7 million for the year ended
December 31, 1996, as compared to the year ended December 31, 1995, which had $0
income tax expense. As a partnership, MarkWest Hydrocarbon Partners, Ltd. (the
Company's predecessor) was not subject to federal and state income tax, and its
income was taxed directly to its respective partners. MarkWest Hydrocarbon, Inc.
is a taxable entity and therefore, recorded income tax expense in 1996.
Year Ended December 31, 1995 Compared to Year Ended December 31, 1994
Revenues. Plant revenue increased to $33.8 million from $33.1 million for the
year ended December 31, 1995 as compared to the year ended December 31, 1994, an
increase of $767,000, or 2%. This increase resulted principally from a $2.0
million increase due to an increase in average NGL sales prices, offset by a
$1.2 million decrease due to reduced volumes sold.
Terminal and marketing revenue decreased to $13.2 million from $13.7 million for
the year ended December 31, 1995 as compared to the year ended December 31,
1994, a decrease of $494,000 or 4%. This decrease principally resulted from the
expiration of the remaining third-party brokerage sales in 1994, including a net
volume-related decrease of $3.1 million offset by a net price-related increase
of $2.6 million.
Oil and gas and other revenue decreased to $1.1 million from $1.8 million for
the year ended December 31, 1995 as compared to the year ended December 31,
1994, a decrease of $755,000 or 41%. The decrease resulted principally from the
Company's sale in 1994 of substantially all of its San Juan Basin coalbed
methane properties and associated gathering systems. The Company sold its San
Juan Basin coalbed methane properties and associated gathering systems in 1994
because it had the opportunity to do so at a substantial profit, and, at that
time, such properties did not provide natural gas dedicated to the Company's
processing operations.
Gain on sale of oil and gas properties of $4.3 million in 1994 was due to the
sale of a majority of the Company's oil and gas producing assets for
approximately $10.1 million.
Costs and expenses. Plant feedstock purchases decreased to $17.3 million from
$21.6 million for the year ended December 31, 1995 as compared to the year ended
December 31, 1994, a decrease of $4.3 million or 20%. This decrease resulted
from the acquisition of feedstock quantities during off-peak periods, when
prices typically are lower, rather than at spot prices during peak season.
Terminal and marketing purchases increased to $11.9 million from $11.5 million
for the year ended December 31, 1995 as compared to the year ended December 31,
1994, an increase of $440,000 or 4%. This increase was due principally to an
increase in the average price per gallon of propane.
18
Operating expenses increased to $4.7 million from $4.4 million for the year
ended December 31, 1995 as compared to the year ended December 31, 1994, an
increase of $313,000 or 7%. The increase was attributable to the construction
and start up of the Kenova gas processing facility.
General and administrative expenses increased to $4.2 million from $3.7 million
for the year ended December 31, 1995 as compared to the year ended December 31,
1994, an increase of $535,000 or 15%. The increase was attributable to
administrative support activities related to the Michigan Project and the new
Kenova and Church Hill facilities.
Depreciation and amortization decreased to $1.8 million from $1.9 million for
the year ended December 31, 1995 as compared to the year ended December 31,
1994, a decrease of $188,000 or 10%. This decrease resulted principally from
lower plant carrying values due to reductions made in 1994.
Reduction in carrying value of assets of $3.0 million in 1994 was due to a one-
time charge reflecting the shutdown of the isomerization unit at the Siloam
plant and a charge for the write-down of other non-productive equipment.
Net interest expense. Net interest expense decreased to $400,000 from $1.7
million for the year ended December 31, 1995 as compared to the year ended
December 31, 1994, a decrease of $1.3 million or 79%. The decrease resulted
principally from lower average borrowing levels of approximately $16.0 million
in 1994 to $8.1 million in 1995, a decrease in interest rates, the
capitalization of approximately $301,000 of interest in connection with the
construction of the Kenova gas processing plant, and the early extinguishment of
a note that required the Company to pay additional interest averaging $400,000
per year based on the throughput of the Company's Siloam facility.
LIQUIDITY AND CAPITAL RESOURCES
The Company's sources of liquidity and capital resources historically have been
net cash provided by operating activities; proceeds from issuance of long-term
debt; in 1994, the proceeds from the sale of certain oil and gas properties; and
in 1996, an initial public offering of equity. The Company's principal uses of
cash have been to fund operations and acquisitions.
The following summary table reflects comparative cash flows for the Company for
the years ended December 31, 1996, 1995 and 1994:
Year Ended December 31,
---------------------------------
1996 1995 1994
---- ---- ----
Net cash provided by operating
activities............................. $ 16,815 $ 5,436 $ 994
Net cash provided by (used in)
investing activities................... $(17,516) $(12,610) $ 9,068
Net cash provided by (used in)
financing activities................... $ 4,341 $ 2,467 $(5,886)
For the year ended December 31, 1996, net cash provided by operating activities
increased by $11.4 million over the year ended December 31, 1995. This increase
resulted primarily from an increase in revenue of $23.7 million, which was
offset by a $15.1 million increase in feedstock purchases, terminal and
marketing purchases, operating expenses and general and administrative expenses.
Cash used in investing activities increased $4.9 million for the year ended
December 31, 1996, as compared to the year ended December 31, 1995, primarily
due to capital expenditures incurred during 1996 related to the Michigan
project.
19
Cash provided by financing activities increased $1.9 million for the year ended
December 31, 1996, as compared to the year ended December 31, 1995. This
increase resulted primarily from the initial public offering in October, which
was partially offset by payments made on long-term debt.
Financing Facilities
Revolver Loan. The Company currently has a financing agreement with Norwest Bank
Denver, N.A., as agent, First American National Bank of Nashville, Tennessee,
First Chicago NBD and N M Rothschild and Sons Limited. The agreement is
structured as a revolving facility, with a maximum borrowing base of $40.0
million as of December 31, 1996. Interest rates are based on either the agent
bank's prime rate plus 1/4 % or the London Interbank Offered Rate (LIBOR) plus
2%. The repayment period begins on September 30, 1998, continuing for 16 equal
quarterly installments until June 30, 2002. Outstanding borrowings at December
31, 1996 were $4.2 million. This facility is secured by substantially all of the
Company's assets.
Working Capital Loan. The Company has a working capital line of credit with a
maximum borrowing base of $7.5 million as of December 31, 1996. Interest rates
are based on prime plus 1/4 %, with maturity on June 30, 1998. Outstanding
borrowings at December 31, 1996 were $5.7 million. The working capital loan is
secured by the Company's inventories, receivables and cash. All amounts
outstanding under this facility were repaid effective February 19, 1997.
Resources Revolver Loan. The Company's Resources subsidiary has a revolving
facility with Colorado National Bank ("CNB") with a maximum borrowing base of
$5.8 million as of December 31, 1996. Interest is based on CNB's bank rate plus
1/2 %. The facility has a maturity date of April 2003. This facility is
restricted for the exploration and development of oil and gas properties and as
of December 31, 1996, $1.2 million was outstanding. This facility is secured by
substantially all of MarkWest Resources' assets. The Company has guaranteed $1.0
million of this facility. All amounts outstanding under this facility were
repaid effective February 19, 1997.
The loan agreements contain affirmative and negative covenants customary in
commercial lending transactions, including restrictions on the incurrence of
additional debt, restrictions on the payment of dividends that would cause the
Company to violate the financial covenants contained in the loan agreements,
maintenance of a specified tangible net worth, current ratio, ratio of funded
debt to total capitalization and fixed charge coverage ratio.
Capital Investment Program
The Company expects to invest approximately $20.0 for activities in the Michigan
Core Area during 1997. The Company also expects to invest approximately $3.6
million in Resources in 1997. For the year ended December 31, 1996, the Company
made capital expenditures totaling $9.8 million.
During 1996 and 1995, the Company expended $12.2 million in connection with the
construction of the Kenova plant. During 1995, the Company expended $213,000 for
the construction and related costs for development of the Church Hill terminal
and storage facility, respectively.
During 1994, the Company expended $1.4 million for the expansion and upgrade of
existing facilities.
RISK MANAGEMENT ACTIVITIES
The Company's policy is to utilize risk management tools primarily to reduce
commodity price risk for its natural gas shrink replacement purchases. This
effectively allows the Company to fix a portion of its margin because gains or
losses in the physical market are offset by corresponding losses or gains in the
financial instruments market. The Company's hedging activities generally fall
into three categories--contracting for future purchases of natural gas at a
predetermined BTU differential based upon a basket of
20
Gulf Coast NGL prices, the fixing of margins between propane sales prices and
natural gas reimbursement costs by purchasing natural gas contracts and
simultaneously selling propane contracts (or a substitute for propane such as
crude oil) of approximately the same BTU value, and the purchase of propane
futures contracts to hedge future sales of propane at the Company's terminals or
gas plants.
The Company maintains a three-person committee that oversees all hedging
activity of the Company. This committee reports monthly to management regarding
recommended hedging transactions and positions. Gains and losses related to
qualifying hedges, as defined by Statement of Financial Accounting Standards,
("SFAS") No. 80, "Accounting for Futures Contracts", of firm commitments or
anticipated transactions are recognized in plant revenue and feedstock purchases
upon execution of the hedged physical transaction.
As of December 31, 1996, 1995 and 1994, the Company did not hold any material
notional quantities of natural gas, NGL, or crude oil futures, swaps or options.
For the year ended December 31, 1996, the Company recognized a $1.1 million loss
in operating income on the settlement of propane and natural gas futures.
This Annual Report on Form 10-K contains statements which, to the extent that
they are not recitations of historical fact, constitute "forward looking
statements" within the meaning of Section 27A of the Securities and Exchange Act
of 1933 and Section 21E of the Securities and Exchange Act of 1934. All forward
looking statements involve risks and uncertainties. The forward looking
statements in this document are intended to be subject to the safe harbor
protection provided by Sections 27A and 21E. Factors that most typically impact
the Company's operating results and financial condition include (i) changes in
general economic conditions in regions in which the Company's products are
located, (ii) the availability and prices of NGLs and competing commodities,
(iii) the availability of raw natural gas supply, (iv) the ability of the
Company to negotiate favorable marketing agreements, (v) the risks that natural
gas exploration and production activities will not be successful, (vi) the
Company's dependence on certain significant customers, (vii) competition from
other NGL processors, including major oil and gas companies, and (viii) the
Company's ability to identify and consummate acquisitions complementary to its
business. For discussions identifying other important factors that could cause
actual results to differ materially from those anticipated in the forward
looking statements, see the Company's Securities and Exchange Commission
filings; and "Management's Discussion and Analysis of Financial Conditions and
Results of Operations" of this Form 10-K.
21
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
Report of Independent Accountants......................................... 23
Consolidated Balance Sheet at December 31, 1996 and 1995.................. 24
Consolidated Statement of Operations for each of the three years ended
December 31, 1996........................................................ 25
Consolidated Statement of Cash Flows for each of the three years ended
December 31, 1996........................................................ 26
Consolidated Statement of Changes in Stockholders' Equity/ Partners'
Capital for each of the three years ended December 31, 1996.............. 27
Notes to Consolidated Financial Statements................................ 28
22
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of MarkWest Hydrocarbon, Inc.
In our opinion, the accompanying consolidated balance sheet and related
consolidated statements of operations, of cash flows and of changes in
stockholders' equity/ partners' capital present fairly, in all material
respects, the financial position of MarkWest Hydrocarbon, Inc., a Delaware
corporation (formerly MarkWest Hydrocarbon Partners, Ltd., a Colorado limited
partnership), and its subsidiaries at December 31, 1996 and 1995, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1996, in conformity with generally accepted
accounting principles. These financial statements are the responsibility of
the Company management; our responsibility is to express an opinion
on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
PRICE WATERHOUSE LLP
Denver, Colorado
March 5, 1997
23
MARKWEST HYDROCARBON, INC.
(SUCCESSOR TO MARKWEST HYDROCARBON PARTNERS, LTD.)
CONSOLIDATED BALANCE SHEET
($000S, EXCEPT SHARE DATA)
December 31,
ASSETS 1996 1995
-------- --------
Current assets:
Cash and cash equivalents............... $ 4,401 $ 761
Receivables............................. 9,755 8,909
Inventories............................. 5,632 2,830
Prepaid expenses and other assets....... 2,289 2,104
-------- -------
Total current assets.................. 22,077 14,604
-------- -------
Property and equipment:
Gas processing, gathering, storage and
marketing.............................. 45,247 23,134
Oil and gas properties and equipment.... 3,731 1,883
Construction in progress................ 5,831 10,282
Land, buildings and other equipment..... 5,647 6,216
-------- -------
60,456 41,515
Less: accumulated depreciation,
depletion and amortization............. (12,316) (9,568)
-------- -------
Total property and equipment, net..... 48,140 31,947
-------- -------
Intangible assets, net of accumulated
amortization of $315 and $152
respectively.................... 380 320
Note receivable and other assets......... 7,657 25
-------- -------
Total assets.......................... $ 78,254 $46,896
======== =======
LIABILITIES AND
STOCKHOLDERS' EQUITY/PARTNERS' CAPITAL
Current liabilities:
Trade accounts payable.................. $ 5,382 $ 3,283
Accrued liabilities..................... 1,629 952
Income taxes payable.................... 3,014 --
Current portion of long-term debt....... 156 --
-------- -------
Total current liabilities............. 10,181 4,235
Deferred income taxes.................... 3,977 --
Long-term debt........................... 11,257 17,500
-------- -------
Total liabilities..................... 25,415 21,735
Minority interest........................ 9,175 --
-------- -------
Commitments and contingencies............ -- --
-------- -------
Stockholders' equity/ partners' capital:
Common stock, par value $.01;
8,485,000 shares authorized, issued
and outstanding........................ 85 --
Additional paid-in capital.............. 42,237 --
Partners' capital....................... -- 25,161
Retained earnings....................... 1,342 --
-------- -------
Total stockholders' equity/ partners'
capital............................... 43,664 25,161
-------- -------
Total liabilities and stockholders'
equity/partners' capital................ $ 78,254 $46,896
======== =======
The accompanying notes are an integral part of these financial statements.
24
MARKWEST HYDROCARBON, INC.
(SUCCESSOR TO MARKWEST HYDROCARBON PARTNERS, LTD.)
CONSOLIDATED STATEMENT OF OPERATIONS
($000S, EXCEPT PER SHARE DATA)
For the Year Ended December 31,
1996 1995 1994
------- ------- -------
Revenues:
Plant revenue................................................... $45,880 $33,823 $33,056
Terminal and marketing revenue.................................. 22,858 13,172 13,666
Oil and gas and other revenue................................... 3,022 1,075 1,830
Interest income................................................. 192 156 136
Gain on sales of oil and gas properties......................... -- -- 4,275
------- ------- -------
Total revenues................................................ 71,952 48,226 52,963
------- ------- -------
Costs and expenses:
Plant feedstock purchases....................................... 22,231 17,308 21,582
Terminal and marketing purchases................................ 18,676 11,937 11,497
Operating expenses.............................................. 7,048 4,706 4,393
General and administrative expenses............................. 5,302 4,189 3,654
Depreciation, depletion and
amortization................................................... 2,910 1,754 1,942
Interest expense................................................ 1,090 508 1,825
Reduction in carrying value of assets........................... -- -- 2,950
------- ------- -------
Total costs and expenses...................................... 57,257 40,402 47,843
------- ------- -------
Income before minority interest, income
taxes and extraordinary item.................................... 14,695 7,824 5,120
Minority interest in net loss of
subsidiary...................................................... 65 -- --
------- ------- -------
Income before income taxes and
extraordinary item.............................................. 14,760 7,824 5,120
Income tax provision:
Arising from reorganization..................................... 3,745 -- --
Subsequent to reorganization.................................... 3,246 -- --
------- ------- -------
Income before extraordinary item................................. 7,769 7,824 5,120
Extraordinary loss on extinguishment of
debt............................................................ -- (1,750) --
------- ------- -------
Net income....................................................... $ 7,769 $ 6,074 $ 5,120
======= ======= =======
Pro forma information (Note 2):
Historical income before
extraordinary item............................................ $14,760 $ 7,824 $ 5,120
Pro forma provision for income taxes........................... 5,609 2,937 1,424
------- ------- -------
Pro forma net income........................................... $ 9,151 $ 4,887 $ 3,696
======= ======= =======
Pro forma earnings per share of
common stock.................................................. $ 1.16 $ .85
======= =======
Pro forma weighted average number of
outstanding shares of common stock............................ 7,908 5,725
======= =======
The accompanying notes are an integral part of these financial statements.
25
MARKWEST HYDROCARBON, INC.
(SUCCESSOR TO MARKWEST HYDROCARBON PARTNERS, LTD.)
CONSOLIDATED STATEMENT OF CASH FLOWS
($000S)
For the Year Ended December 31,
1996 1995 1994
-------- -------- --------
Cash flows from operating activities:
Net income............................. $ 7,769 $ 6,074 $ 5,120
Adjustments to reconcile net income to
net cash provided by operating
activities:
Depreciation, depletion and 2,910 1,754 1,942
amortization.....................
Deferred income taxes............. 3,977 -- --
Option granted in conjunction
with extinguishment of debt..... -- 1,050 --
Loss (gain) on sale of assets..... 46 -- (4,275)
Reduction in carrying value of
assets........................... -- -- 2,950
(Increase) in receivables......... (846) (4,729) (977)
(Increase) decrease in inventories (2,802) (19) 1,348
(Increase) decrease in prepaid
expenses and other assets........ (185) (86) (1,125)
Increase (decrease) in accounts
payable and accrued liabilities.. 5,946 1,392 (3,989)
-------- -------- --------
Net cash flow provided by
operating activities.... 16,815 5,436 994
Cash flows from investing activities:
Capital expenditures.............. (9,824) (12,426) (1,442)
Proceeds from sale of assets...... -- -- 10,166
Increase in long-term notes
receivable....................... (7,657) -- --
Decrease (increase) in intangible
and other assets................. (35) (184) 344
-------- -------- --------
Net cash provided by
(used in) investing
activities.............. (17,516) (12,610) 9,068
Cash flows from financing activities:
Proceeds from issuance of
long-term debt.................. 1,174 -- --
Repayments of long-term debt...... (84) (500) --
Borrowings under revolving credit
facility......................... 45,950 26,050 7,201
Payments on revolving credit
facility........................ (53,548) (18,937) (12,800)
Partners' distributions........... (14,150) (4,150) (320)
Payments on partner notes......... 320 -- --
Payments on options............... 71 4 33
Proceeds from issuance of
common stock.................... 24,608 -- --
-------- -------- --------
Net cash provided by
(used in) financing
activities.............. 4,341 2,467 (5,886)
Net increase (decrease)
in cash and cash
equivalents............. 3,640 (4,707) 4,176
Cash and cash equivalents at beginning
of year.............................. 761 5,468 1,292
-------- -------- --------
Cash and cash equivalents at end of
year................................. $ 4,401 $ 761 $ 5,468
======== ======== ========
The accompanying notes are an integral part of these financial statements.
26
MARKWEST HYDROCARBON, INC.
(SUCCESSOR TO MARKWEST HYDROCARBON PARTNERS, LTD.)
CONSOLIDATED STATEMENT OF CHANGES IN
STOCKHOLDERS' EQUITY/ PARTNERS' CAPITAL
($000S)
TOTAL
PARTNERS' COMMON ADDITIONAL PAID-IN RETAINED STOCKHOLDERS'
CAPITAL STOCK CAPITAL EARNINGS EQUITY
---------- ------ ------------------ --------- --------------
Balance, December 31, 1993 $ 17,350 $ $ -- $ $ 17,350
Net income 5,120 -- -- -- 5,120
Distributions, net of contributions (287) -- -- -- (287)
-------- ------ ------------------ -------- --------
Balance, December 31, 1994 22,183 -- -- -- 22,183
Net income 6,074 -- -- -- 6,074
Distributions, net of contributions (4,146) -- -- -- (4,146)
Option granted in conjunction with
extinguishment of debt 1,050 -- -- -- 1,050
-------- ------ ------------------ -------- --------
Balance, December 31, 1995 25,161 -- -- -- 25,161
Net income prior to reorganization 6,427 -- -- -- 6,427
Notes receivable from partners, net, 205 -- -- -- 205
prior to reorganization
Distributions prior to reorganization (14,150) -- -- -- (14,150)
Exercise of options, prior to 71 -- -- -- 71
reorganization
Reorganization from a limited
partnership to a corporation (17,714) 57 17,657 -- --
Deferred taxes relating to the
reorganization -- -- -- (3,745) (3,745)
Common stock issued -- 28 24,580 -- 24,608
Net income after reorganization -- -- -- 5,087 5,087
-------- ------ ------------------ -------- --------
Balance, December 31, 1996 $ -- $85 $42,237 $ 1,342 $ 43,664
======== ====== ================== ======== ========
The accompanying notes are an integral part of these financial statements.
27
MARKWEST HYDROCARBON, INC.
(SUCCESSOR TO MARKWEST HYDROCARBON PARTNERS, LTD.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. NATURE OF OPERATIONS AND SIGNIFICANT BUSINESS ACQUISITIONS
NATURE OF OPERATIONS AND RECENT REORGANIZATION
MarkWest Hydrocarbon, Inc. (the "Company") provides compression, gathering,
treatment, processing and natural gas liquids extraction services to natural gas
producers and pipeline companies and fractionates natural gas liquids into
marketable products for sale to third parties. The Company also purchases,
stores and markets natural gas and natural gas liquids and has begun to conduct
strategic exploration for new natural gas resources for its processing and
fractionation activities.
The Company was incorporated in June 1996 to act as the successor to MarkWest
Hydrocarbon Partners, Ltd. (the "Partnership"). Effective October 7, 1996, the
Partnership reorganized (the "Reorganization") and the existing general and
limited partners exchanged 100% of their interests in the Partnership for
5,725,000 common shares of the Company. An additional 2,400,000 shares of
common stock were offered for public sale, totaling 8,125,000 shares outstanding
as of October 15, 1996. The over-allotment of 360,000 shares was also exercised
during October, resulting in a total of 8,485,000 shares outstanding at October
31, 1996. This transaction was a reorganization of entities under common
control, and accordingly, it was accounted for at historical cost.
SIGNIFICANT BUSINESS ACQUISITIONS
Prior to July 1, 1996, the Partnership owned 49% of MarkWest Coalseam
Development Company LLC (formerly MarkWest Coalseam Joint Venture) ("Coalseam"),
a natural gas development venture, and MW Gathering LLC ("Gathering"), a natural
gas gathering venture. Effective July 1, 1996, Gathering was merged into
Coalseam. Simultaneously, the Partnership formed MarkWest Resources Inc.
("Resources"), and Coalseam distributed 49% of its assets to Resources and 51%
to MAK-J Energy Partners, Ltd. (formerly MarkWest Energy Partners, Ltd.)
("Energy"), a partnership whose general partner is a corporation owned and
controlled by the President of the Company. The consolidated financial
statements reflect Resources' 49% proportionate share of the underlying oil and
gas assets, liabilities, revenues and expenses.
Effective May 6, 1996, the Partnership acquired the right to earn up to a 60%
interest for $16.8 million in a newly formed venture, West Shore Processing, LLC
("West Shore"). The most significant asset of West Shore is Basin Pipeline,
LLC, which was contributed by the Partnership's venture partner, Michigan Energy
Company, LLC. The West Shore agreement is structured so that the Company's
ownership interest increases as capital expenditures for the benefit of West
Shore are made by the Company. As of December 31, 1996, the Company has
recorded a net investment in West Shore of $10.4 million, representing a 47%
ownership interest. The Company is committed to make capital expenditures of
approximately $21.0 million through 1997 in conjunction with the first two
phases of the agreement. Phase I of the project will be completed in early
1997. Phase II, scheduled for completion in late 1997, is underway.
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company and
its wholly-owned subsidiaries, Resources and MarkWest Michigan, Inc. All
significant intercompany accounts and transactions have been eliminated in
consolidation.
28
CASH AND CASH EQUIVALENTS
The Company considers all highly liquid investments purchased with an original
maturity of three months or less to be cash equivalents. Excess cash is used to
pay down the term/revolver loan facility. Accordingly, investments are limited
to overnight investments of end-of-day cash balances.
RECEIVABLES
Receivables comprise the following (in $000s):
At December 31,
1996 1995
------- ------
Trade and other receivables... $9,755 $5,735
Short-term advances........... -- 3,174
------ ------
$9,755 $8,909
====== ======
No allowance for doubtful accounts is considered necessary based on favorable
historical experience.
During the fourth quarter of 1995, the Partnership made several short-term
advances totaling $3,174,000 as part of an agreement with a partner to develop a
joint project. In accordance with the terms of the agreement, the Partnership
was reimbursed for the full amount of the advances at the closing date of May 6,
1996.
INVENTORIES
Inventories comprise the following (in $000s):
At December 31,
1996 1995
------- ------
Product inventory.................. $5,292 $2,718
Materials and supplies inventory... 340 112
------ ------
$5,632 $2,830
====== ======
Product inventory consists primarily of finished goods (propane, butane,
isobutane and natural gasoline) and is valued at the lower of cost, using the
first-in, first-out method, or market. Market value of the Company's product
inventory was $7.6 million and $3.8 million at December 31, 1996 and 1995,
respectively. Capitalized overhead costs of $232,000 and $219,000 were included
in product inventory at December 31, 1996, and 1995, respectively. Materials
and supplies are valued at the lower of average cost or estimated net realizable
value.
PREPAID EXPENSES AND OTHER ASSETS
Prepaid expenses and other assets comprise the following (in $000s):
At December 31,
1996 1995
------ -------
Prepaid feedstock............ $1,831 $1,729
Prepaid expenses............. 458 375
------ ------
29
$2,289 $2,104
====== ======
Prepaid feedstock consists of natural gas purchased in advance of its actual
use. It is valued on a first-in, first-out method.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is recorded at cost. Expenditures which extend the
useful lives of assets are capitalized. Repairs, maintenance and renewals which
do not extend the useful lives of the assets are expensed as incurred. Interest
costs for the construction or development of significant long-term assets are
capitalized and amortized over the related asset's estimated useful life.
Depreciation is provided principally on the straight-line method over the
following estimated useful lives: plant facilities, 20 years; buildings, 40
years; furniture, leasehold improvements and other, 3-10 years. Depreciation for
oil and gas properties is provided for using the units-of-production method.
Oil and gas properties consist of leasehold costs, producing and non-producing
gas wells and equipment, and pipelines. The Company uses the full cost method
of accounting for oil and gas properties. Accordingly, all costs associated
with acquisition, exploration and development of oil and gas reserves are
capitalized to the full cost pool.
These capitalized costs, including estimated future costs to develop the
reserves and estimated abandonment costs, net of salvage value, are amortized on
a units-of-production basis using estimates of proved reserves. Investments in
unproved properties and major development projects are not amortized until
proved reserves associated with the projects can be determined or until
impairment occurs. If the results of an assessment of such properties indicate
that the properties are impaired, the amount of impairment is added to the
capitalized cost base to be amortized. As of December 31, 1996 and 1995,
approximately $649,000 and $862,000 of investments in unproved properties were
excluded from amortization.
The capitalized costs included in the full cost pool are subject to a "ceiling
test," which limits such costs to the aggregate of the estimated present value,
using a 10 percent discount rate, of the future net revenues from proved
reserves, based on current economics and operating conditions. Impairment under
the ceiling test of $116,000 was recognized in 1994 and is included in
depreciation, depletion and amortization in the accompanying consolidated
statement of operations. No impairment existed as of December 31, 1996 and
1995.
Sales of proved and unproved properties are accounted for as adjustments of
capitalized costs with no gain or loss recognized, unless such adjustments would
significantly alter the relationship between capitalized costs and proved
reserves of oil and gas, in which case the gain or loss is recognized in the
consolidated statement of operations.
IMPAIRMENT OF LONG-LIVED ASSETS
During 1996, the Company adopted Statement of Financial Accounting Standards
("SFAS") No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of, which requires that an impairment loss be
recognized when the carrying amount of an asset exceeds the expected future
undiscounted net cash flows. There was no effect on the Company's financial
statements as a result of adopting SFAS No. 121.
INTANGIBLE ASSETS
30
Deferred financing costs and a non-compete agreement with a former officer and
director are included in intangible assets. Both are amortized using the
straight-line method over the terms of the associated agreements.
NOTE RECEIVABLE
Note receivable at December 31, 1996 consists of a note receivable (the "Note")
from Michigan Production Company, LLC ("MPC"). The Note is for all sums
necessary for the construction of the 31 mile extension to the Basin pipeline.
The Note bears an interest rate of 5.98% and is payable to the Company on the
earlier of two dates which are contingent upon certain events as defined in the
agreement.
HEDGING ACTIVITIES
The Company limits its exposure to natural gas and propane price fluctuations
related to future purchases and production with futures contracts. These
contracts are accounted for as hedges in accordance with the provisions of SFAS
No. 80, Accounting for Futures Contracts. Gains and losses on such hedge
contracts are deferred and included as a component of propane revenues and
feedstock purchases when the hedged production is sold.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company's financial instruments consist of cash and cash equivalents,
receivables, accounts payable and other current liabilities, and long-term debt.
Except for long-term debt, the carrying amounts of financial instruments
approximate fair value due to their short maturities. At December 31, 1996 and
1995, based on rates available for similar types of debt, the fair value of
long-term debt was not materially different from its carrying amount.
REVENUE RECOGNITION
Revenue for sales or services is recognized at the time the product is delivered
or at the time the service is performed.
INCOME TAXES
Deferred income taxes reflect the impact of "temporary differences" between
amounts of assets and liabilities for financial reporting purposes and such
amounts as measured by tax laws. These temporary differences are determined in
accordance with the liability method of accounting for income taxes as
prescribed by SFAS No. 109, Accounting for Income Taxes.
CONCENTRATION OF CREDIT RISK
Financial instruments which potentially subject the Company to concentrations of
credit risk consist principally of trade accounts receivable. The risk is
limited due to the large number of entities comprising the Company's customer
base and their dispersion across industries and geographic locations. At
December 31, 1996, the Company had no significant concentrations of credit risk.
STOCK COMPENSATION
As permitted under SFAS No. 123, Accounting for Stock-Based Compensation, the
Company has elected to continue to measure compensation costs for stock-based
employee compensation plans as prescribed by Accounting Principles Board Opinion
No. 25, Accounting for Stock Issued to Employees. The Company has complied with
the pro forma disclosure requirements of SFAS No. 123 as required under the
pronouncement.
31
SUPPLEMENTAL CASH FLOW INFORMATION
Interest of $1,012,000, $792,000 and $1,805,000 was paid for years ended
December 31, 1996, 1995 and 1994, respectively. Interest paid in 1996 is net of
$27,000 capitalized in relation to various construction projects.
There were no income taxes paid during the three years ended December 31, 1996.
The Consolidated Statement of Cash Flows for the year ended December 31, 1996
excludes non-cash activities related to the contribution of Basin Pipeline, LLC
by Michigan Energy, LLC ("MEC") to West Shore. MEC's contribution was valued
at approximately $9.2 million.
In 1996, the Company financed the purchase of certain assets from the Dow
Chemical Company ("Dow") with a note valued at approximately $421,000. As of
December 31, 1996, $337,000 was outstanding under this note.
PRO FORMA INFORMATION
Pro forma provision for income taxes and pro forma net income. Prior to the
Reorganization, MarkWest was organized as a partnership and, consequently, was
not subject to income tax. A pro forma provision for income taxes for the years
ended December 31, 1996, 1995 and 1994 has been presented for purposes of
comparability as if MarkWest had been a taxable entity for all periods
presented.
Pro forma weighted average shares outstanding at December 31, 1996 and December
31, 1995. Pro forma weighted average shares outstanding at December 31, 1996
represents the weighted average of, for the period prior to the Offering, the
number of common shares issued in the Reorganization plus the number of shares
issued in the Offering for which the net proceeds were used to repay outstanding
indebtedness and, for the period subsequent to the Offering, the total number of
common shares outstanding. Pro forma weighted average shares outstanding at
December 31, 1995 represents the number of common shares issued in the
Reorganization.
RECLASSIFICATIONS
Certain prior year amounts have been reclassified to conform to the 1996
presentation.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
NOTE 3. DEBT
REVOLVER/TERM LOAN
On November 20, 1992, the Partnership entered into a financing agreement with
Norwest Bank Denver, N.A. ("Norwest") and First American National Bank ("FANB")
of Nashville, Tennessee. The facility is structured as a revolver and had an
initial maximum borrowing base of $20 million. The borrowing base on the
facility is redetermined semi-annually. On September 8, 1995, the agreement was
amended to add N M Rothschild and Sons Limited ("Rothschild") as a lender,
revise the interest rate for base rate loans and institute the option of LIBOR
(London Interbank Offered Rate) interest. On May 31, 1996, the facility was
further amended to increase the maximum borrowing base to $40 million and extend
the repayment period
32
to June 30, 2002, with 16 equal quarterly installments commencing September 30,
1998. As of December 31, 1996 and 1995, outstanding borrowings were $4.2 million
and $15 million, respectively. The remaining borrowing base of $35.8 million and
$10 million was unutilized at December 31, 1996 and 1995, respectively.
Interest on a base rate loan is now calculated at prime plus 1/4 % if the
Company's total debt is less than or equal to 40% of total capitalization. If
debt exceeds 40% of capitalization, the rate increases to prime plus 1/2 %. At
December 31, 1996 and 1995, $0 million and $3 million were outstanding under a
base rate loan bearing interest at 8 1/2 % and 9 %, respectively.
The LIBOR option allows the Company to lock in a portion of the revolver balance
for a period of one, two, three or six months. Interest on a LIBOR loan is
calculated at LIBOR plus 2% if the Company's total debt is less than or equal to
40% of total capitalization. If debt exceeds 40% of capitalization, the rate
increases to LIBOR plus 2 1/4 %. At December 31, 1996 and 1995, $0 and $12
million were outstanding under the LIBOR commitment, respectively.
This debt is secured by a first mortgage on the Company's property, plant,
equipment and contracts, excluding railcars and truck trailers. The loan
agreement restricts certain activities and requires the maintenance of certain
financial ratios and other conditions.
WORKING CAPITAL LINE OF CREDIT
On November 20, 1992, the Partnership entered into a working capital line of
credit agreement with Norwest and FANB in the amount of $5 million. The
borrowing base, as defined in the credit agreement, is redetermined monthly. On
September 8, 1995, the agreement was amended to add Rothschild as a lender,
revise the interest rate, increase the maximum borrowing base to $7.5 million,
and extend the working capital commitment period and maturity date. The
extended due date on the working capital note is June 30, 1998. The interest
rate change is the same as discussed above for the revolver/term loan. No LIBOR
option is available for the working capital line. At December 31, 1996 and
1995, $5.7 million and $2.5 million were outstanding bearing interest at 8 1/2
% and 9 %, respectively. All amounts outstanding under this facility were paid
off effective February 6, 1997.
MARKWEST RESOURCES REVOLVER LOAN
The Company's MarkWest Resources subsidiary has a revolving facility with
Colorado National Bank ("CNB") with a maximum borrowing base of $5.8 million as
of December 31, 1996. Interest is based on CNB's bank rate plus 1/2 %. The
facility has a maturity date of April 2003. This facility is restricted for the
exploration and development of oil and gas properties and as of December 31,
1996 and December 31, 1995, $1.2 million and $0 were outstanding, respectively.
This facility is secured by substantially all of MarkWest Resources' assets.
The Company has guaranteed $1 million of this facility. All amounts outstanding
under this facility were repaid effective February 19, 1997.
Scheduled debt maturities under the terms of the facilities are as follows (in
$000s):
At December 31, 1996 At December 31, 1995
Revolver Line of Subsidiary Revolver Line of
loan credit Debt loan credit
-------- ------- ---------- ---------- --------
1997 $ - $ - $ 156 $ 1,875 $2,500
1998 525 5,700 156 3,750 -
1999 1,050 - 25 3,750 -
2000 1,050 - - 3,750 -
2001 and thereafter 1,575 - 1,176 1,875 -
------ ------- ------ ------- --------
33
Total $4,200 $5,700 $1,513 $15,000 $2,500
====== ======= ====== ======= ========
SOUTH SHORE NOTE
The note agreement for the purchase of the South Shore plant and the
isomerization expansion allowed for the prepayment of principal to no less than
$500,000. In November 1992, the Partnership exercised its prepayment rights
relative to this agreement by paying $9.2 million of the then-outstanding
balance. The remaining $500,000 principal balance accrued interest at 12%.
Under the terms of the note, additional interest was payable annually based on
certain operating results of the fractionation plant and proceeds from asset
dispositions. Such additional interest expense was $422,000 for 1994.
During 1995, the Partnership reached an agreement with the noteholder to fully
retire the note. Accordingly, the Partnership paid the remaining balance of
$500,000 as well as $700,000 of additional interest. In addition, the
Partnership granted to the noteholder an option to acquire 3.5% of the
Partnership. Based on management's best estimate of the fair value of the
Partnership, the option was valued at $1,050,000 which, together with the
$700,000 of additional interest, is reflected in the Consolidated Statement of
Operations as an extraordinary loss due to the early extinguishment of debt.
NOTE 4. RELATED PARTY AND CAPITAL TRANSACTIONS
The Company made contributions of $299,000, $211,000, $213,000 to a profit-
sharing plan for the years ended December 31, 1996, 1995 and 1994, respectively.
The plan is discretionary, with annual contributions determined by the
Company's Board of Directors.
The Partnership periodically extended offers to employees to purchase interests
in the Partnership. The partners and/or employees provided the Partnership with
promissory notes as part of the exercise price. According to the terms of the
notes, interest accrues at 7% and payments are required for the greater of
accrued interest or excess distributions. Notes in the amounts of $376,000 and
$512,000 have been recorded as a reduction of additional paid-in capital at
December 31, 1996 and 1995, respectively.
The Company has receivables from employees and officers of $23,000 and $74,000
at December 31, 1996 and 1995, respectively.
The Company's employees perform certain administrative functions on behalf of
its subsidiaries. At December 31, 1996 and 1995, no material amounts were due
to or from the subsidiaries for miscellaneous administrative expenses.
NOTE 5. SPECIAL ITEMS
In 1994, the Partnership shut down the South Shore plant's isomerization unit
when it was unable to find satisfactory markets for its isobutane. Accordingly,
the Partnership recorded a $2,242,000 charge to write down the unit to its
estimated realizable value. In addition, a catalyst used in the isomerization
process was sold, resulting in a $347,000 loss. The Partnership also recorded a
charge of $361,000 in 1994 for the write-down of non-productive equipment
related to various business development projects.
NOTE 6. COMMITMENTS AND CONTINGENCIES
The Company is involved in various litigation and administrative proceedings
arising in the normal course of business. In the opinion of management, any
liabilities (net of insurance) that may result from these claims will not,
individually or in the aggregate, have a material adverse effect on the
Company's financial position or results of operations.
NOTE 7. SIGNIFICANT CUSTOMERS
34
For the year ended December 31, 1995, sales to one customer accounted for
approximately 18% of total revenues. During 1996 and 1994, no sales to any one
customer accounted for more than 10% of total revenue. Management believes the
loss of these customers would not adversely impact operations, as alternative
markets are available.
NOTE 8. HEDGING ACTIVITIES
MarkWest's primary hedging objectives are to meet or exceed budgeted gross
margins by locking in budgeted or above-budgeted prices in the financial
derivatives markets and to protect margins from precipitous declines. Under
internal guidelines, speculative positions are prohibited.
The Company's hedging activities generally fall into three categories - 1)
contracting for future purchases of natural gas at a predetermined BTU
differential based upon a basket of Gulf Coast NGL prices (or a substitute for
propane such as crude oil), 2) the fixing of margins between propane sales
prices and natural gas reimbursement costs by purchasing natural gas contracts
and simultaneously selling propane contracts of approximately the same BTU
value, and 3) the purchase of propane futures contracts to hedge future sales of
propane at the Company's terminals or gas plants. The Company enters into
futures transactions on the New York Mercantile Exchange ("NYMEX"). Future gas
purchases are based on predetermined BTU differentials are negotiated with
natural gas suppliers and structured to provide similar risk protections as
NYMEX futures.
At December 31, 1996, the Company had a total of 295 short and 135 long open
propane futures contracts representing a notional quantity amounting to 160,000
barrels of production. Late in 1996, the Company entered into agreements with
certain natural gas suppliers for gas purchases (25,000 mmbtus a day) for the
summer of 1997 at differentials to crude oil futures and NGL baskets at December
31, 1996. There were no material notional quantities of natural gas or crude
oil futures or options at December 31, 1996, and no material notional quantities
of natural gas, NGL, or crude oil futures, swaps or options at December 31,
1995.
During the years ended December 31, 1996 and 1995, a $1.1 million loss and
$300,000 gain, respectively, were recognized in operating income on the
settlement of propane and natural gas futures. Financial instrument gains and
losses on hedging activities were generally offset by amounts realized from the
sale of the underlying products in the physical market.
NOTE 9. INCOME TAXES
In connection with the reorganization from a partnership to a corporation, the
Company recorded deferred income taxes as of October 7, 1996 and a one-time
charge to earnings of $3.7 million.
The total income tax provision for the year ended December 31, 1996 has been
allocated as follows (in $000s):
Arising from reorganization $3,745
Subsequent to reorganization 3,246
------
$6,991
======
35
The components of the income tax provision subsequent to reorganization
consisted of the following (in $000s):
Year ended
December 31,
1996
------------
Current federal $2,616
Current state 398
------
Total current..................... 3,014
------
Deferred federal.............................. 212
Deferred state 20
------
Total deferred.................... 232
------
Total income tax provision subsequent......... $3,246
to reorganization............................ ======
The deferred tax liability is comprised
of the following (in $000s):
December 31,
1996
------------
Property and equipment........................ $3,667
Intangible assets............................. (6)
Other assets.................................. 316
------
Net deferred tax liability.................... $3,977
======
Income taxes subsequent to reorganization as reflected in the Consolidated
Statement of Operations differ from the amounts computed by applying the
statutory federal corporate tax rate to income as follows (in $000s):
Year ended
December 31,
1996
------------
Income taxes subsequent to 2,916
reorganization at statutory rate.............
State income taxes, net of federal 140
benefit......................................
Tax credits................................... (35)
Other......................................... 225
------
Income taxes subsequent to
reorganization............................... $3,246
======
NOTE 10. STOCK COMPENSATION PLANS
At December 31, 1996, the Company has two stock-based compensation plans, which
are described below. The Company applies APB Opinion No. 25, Accounting for
Stock Issued to Employees, and related Interpretations in accounting for its
plans. Accordingly, no compensation cost has been recognized for its fixed
stock option plans. Had compensation cost for the Company's two stock-based
compensation plans been determined based on the fair value at the grant dates
(1996 and 1995 grants only) under those plans consistent with the method
prescribed by SFAS No. 123, Accounting for Stock-Based Compensation, the
36
Company's pro forma net income and earnings per share would have been reduced to
the pro forma amounts listed below (in $000s):
1996 1995
------- -------
Pro forma net income As reported $9,151 $4,887
Pro forma 9,127 4,887
Pro forma earnings per share As reported $ 1.16 $ 0.85
Pro forma 1.15 0.85
The Company historically granted employees the right to purchase partnership
interests in the Partnership. As part of the Reorganization, such employee
options to purchase partnership interests were replaced by options to purchase
shares pursuant to the Company's 1996 Stock Incentive Plan.
Under the 1996 Stock Incentive Plan, the Company may grant options to its
employees for up to 600,000 shares of common stock in the aggregate. Under the
1996 Non-employee Director Stock Option Plan, the Company may grant options to
its non-employee directors for up to 20,000 shares of common stock in the
aggregate. Under both plans, the exercise price of each option equals the
market price of the Company's stock on the date of the grant, and an option's
maximum term is 10 years. Options are granted periodically throughout the year
and vest at the rate of 20% on the first anniversary of the option grant date,
and at the rate of 20% on each subsequent anniversary thereof until fully
vested.
The fair value of each option is estimated on the date of grant using the Black-
Scholes Option-Pricing model with the following weighted-average assumptions
used for grants in 1996 and 1995, respectively: dividend yield of $0/share for
all years; expected volatility of 33% for 1996 option grants and 34% for 1995
plan options; risk-free interest rate of 6.55% for 1996 option grants and 6.22%
for 1995 option grants; and expected lives of 6 years for 1996 and 1995 option
grants.
A summary of the status of the Company's two fixed stock option plans as of
December 31, 1996 and 1995 and changes during the years ended on those dates is
presented below:
1996 1995
----------------------- ------------------
Weighted- Weighted-
Average Average
Exercise Exercise
Shares Price Shares Price
FIXED OPTIONS ------- ----------- ------ ---------
Outstanding at beginning of year 64,004 $6.99 -- --
Granted 138,032 9.65 64,004 $6.99
Exercised -- -- -- --
Forfeited (1,146) -- -- --
------- ----- ------ -----
Outstanding at end of year 200,890 $8.86 64,004 $6.99
======= ===== ====== =====
Options exercisable at 12/31/96 12,800 12,800
Weighted-average fair value of options
granted during the year $ 4.37 $ 3.16
37
The following table summarizes information about fixed stock options outstanding
at December 31, 1996:
Options Outstanding Options Exercisable
--------------------------------------- ----------------------
Weighted-
Average Weighted- Weighted-
Number Remaining Average Number Average
Outstanding Contractual Exercise Exercisable Exercise
Range of Exercise Prices at 12/31/96 Life Price at 12/31/96 Price
- ------------------------- ----------- ----------- --------- ----------- ---------
$6.99 64,004 8.6 years $6.99 12,800 $6.99
$7.00 to $10.00 136,886 9.7 years $9.65 --
---------- ------
200,890 12,800
========== ======
NOTE 11. STOCK ACTIVITY
Activity in the Company's common stock for each of the three years ended
December 31, 1996 is summarized below (in 000s of shares):
# of shares
-----------
Balance at December 31, 1993 --
Balance at December 31, 1994 --
Balance at December 31, 1995 --
Shares issued in exchange for
partnership interests 5,725
Shares issued in initial public offering 2,400
Shares issued in over-allotment 360
-----
Balance at December 31, 1996 8,485
=====
38
NOTE 12. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The following summarizes certain quarterly results of operations ($000s):
First Second Third Fourth
-------- ------- --------- --------
1996
- --------------------------------------
Revenue(1) $19,832 $8,760 $14,935 $28,233
Gross profit (2) 5,514 1,580 3,533 10,268
Pro forma net income (3) 2,588 195 1,205 5,163
Per common share data:
Pro forma net income $ .33 $ .03 $ .15 $ .65
1995
- --------------------------------------
Revenue (1) $15,566 $7,360 $ 8,665 $16,479
Gross profit (2) 4,770 1,860 1,564 4,171
Pro forma income before extraordinary
loss (3) 2,261 421 352 1,853
Extraordinary loss on extinguishment of
debt -- -- (1,750) --
Pro forma net income(3) 2,261 421 (1,398) 1,853
Per common share data:
Pro forma income before
extraordinary loss $ .40 $ .07 $ .06 $ .32
Extraordinary loss -- -- (.30) --
Pro forma net income (loss) .40 .07 (.24) .32
(1) Excludes interest income.
(2) Excludes general and administrative expenses and interest expense.
(3) During 1996, the Company reorganized and became a taxable entity. Pro forma
net income reflects the results of the Company had it been a taxable entity
for all periods presented.
39
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP AND CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12 and 13 are omitted
because the Company will file a definitive proxy statement (the "Proxy
Statement") pursuant to Regulation 14A under the Securities Exchange Act of 1934
not later than 120 days after the close of the fiscal year. The information
required by such Items will be included in the definitive proxy statement to be
so filed for the Company's annual meeting of stockholders scheduled for June 6,
1997 and is hereby incorporated by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
(1) Financial Statements:
Reference is made to the listing on page 22 for a list of all
financial statements filed as a part of this report.
(2) Financial Statement Schedules:
None required.
(3) Exhibits
3.1 Certificate of Incorporation of MarkWest Hydrocarbon, Inc. (Filed as
exhibit 3.1 to MarkWest Hydrocarbon, Inc.'s Registration Statement on
Form S-1, Registration No. 333-09513 and incorporated herein by
reference).
3.2 Bylaws of MarkWest Hydrocarbon, Inc. (Filed as exhibit 3.2 to
MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1,
Registration No. 333-09513 and incorporated herein by reference).
10.1 Amended and Restated Reorganization Agreement made as of August 1,
1996, by and among MarkWest Hydrocarbon, Inc., MarkWest Hydrocarbon
Partners, Ltd., MWHC Holding, Inc. RIMCO Associates, Inc. and each of
the limited partners of MarkWest Hydrocarbon Partners, Ltd. (Filed as
exhibit 10.1 to MarkWest Hydrocarbon, Inc.'s Registration Statement on
Form S-1, Registration No. 333-09513 and incorporated herein by
reference).
40
10.2 Loan Agreement dated November 20, 1992, among MarkWest Hydrocarbon
Partners, Ltd., Norwest Bank Denver, National Association,
individually and as Agent, and First American National Bank (Filed as
exhibit 10.21 to MarkWest Hydrocarbon, Inc.'s Registration Statement
on Form S-1, Registration No. 333-09513 and incorporated herein by
reference).
10.3 Modification Agreement, dated July 31, 1996, among MarkWest
Hydrocarbon Partners, Ltd., MarkWest Hydrocarbon, Inc., Norwest Bank
Colorado, N.A., First American National Bank N M Rothschild and Sons
Limited and Norwest (Filed as exhibit 10.2 to MarkWest Hydrocarbon,
Inc.'s Registration Statement on Form S-1, Registration No. 333-09513
and incorporated herein by reference).
10.4 Amended and Restated Mortgage, Assignment, Security Agreement and
Financing Statement, dated May 2, 1996, between West Shore Processing
Company, L.L.C. and Bank of America Illinois (Filed as exhibit 10.3
to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1,
Registration No. 333-09513 and incorporated herein by reference).
10.5 Secured Guaranty, dated May 2, 1996, between West Shore Processing
Company LLC and Bank of America Illinois (Filed as exhibit 10.4 to
MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1,
Registration No. 333-09513 and incorporated herein by reference).
10.6 Security Agreement, dated May 2, 1996, between West Shore Processing
Company L.L.C. and Bank of America Illinois (Filed as exhibit 10.5 to
MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1,
Registration No. 333-09513 and incorporated herein by reference).
10.7 Pledge Agreement, dated May 2, 1996, between West Shore Processing
Company, L.L.C. and Bank of America Illinois (Filed as exhibit 10.6
to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1,
Registration No. 333-09513 and incorporated herein by reference).
10.8 Participation, Ownership and Operating Agreement for West Shore
Processing Company, L.L.C. dated May 2, 1996 (Filed as exhibit 10.7 to
MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1,
Registration No. 333-09513 and incorporated herein by reference).
10.9 Second Amended and Restated Operating Agreement for Basin Pipeline
L.L.C., dated May 2, 1996 (Filed as exhibit 10.8 to MarkWest
Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration
No. 333-09513 and incorporated herein by reference).
10.10 Subordination Agreement, dated May 2, 1996, among MarkWest Michigan
LLC, Bank of America Illinois, West Shore Processing Company, L.L.C.,
Basin Pipeline L.L.C., Michigan Energy Company, L.L.C. (Filed as
exhibit 10.9 to MarkWest Hydrocarbon, Inc.'s Registration Statement on
Form S-1, Registration No. 333-09513 and incorporated herein by
reference).
10.11 Gas Treating and Processing Agreement, dated May 1, 1996, between
West Shore Processing Company, LLC and Shell Offshore, Inc. (Filed as
exhibit 10.10 to MarkWest Hydrocarbon, Inc.'s Registration Statement
on Form S-1, Registration No. 333-09513 and incorporated herein by
reference).
10.12 Gas Gathering, Treating and Processing Agreement, dated May 2, 1996,
between Oceana Acquisition Company and West Shore Processing Company,
LLC (Filed as exhibit 10.11 to MarkWest Hydrocarbon, Inc.'s
Registration Statement on Form S-1, Registration No. 333-09513 and
incorporated herein by reference).
10.13 Gas Gathering, Treating and Processing Agreement, dated May 2, 1996,
between Michigan Production Company, L.L.C. and West Shore Processing
Company, LLC(Filed as exhibit 10.12 to
41
MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1,
Registration No. 333-09513 and incorporated herein by reference).
10.14 Products Exchange Agreements, dated May 1, 1996, with Ferrellgas,
L.P. (Filed as exhibit 10.13 to MarkWest Hydrocarbon, Inc.'s
Registration Statement on Form S-1, Registration No. 333-09513 and
incorporated herein by reference).
10.15 Gas Processing and Treating Agreement, dated March 29, 1996, between
Manistee Gas Limited Liability Company and Michigan Production
Company, L.L.C. (Filed as exhibit 10.14 to MarkWest Hydrocarbon,
Inc.'s Registration Statement on Form S-1, Registration No. 333-09513
and incorporated herein by reference).
10.16 Processing Agreement (Kenova Processing Plant), dated March 15,
1995, between Columbia Gas Transmission Corporation and MarkWest
Hydrocarbon Partners, Ltd. (Filed as exhibit 10.15 to MarkWest
Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration
No. 333-09513 and incorporated herein by reference).
10.17 Natural Gas Liquids Purchase Agreement (Cobb Plant), between
Columbia Gas Transmission Corporation and MarkWest Hydrocarbon
Partners, Ltd. (Filed as exhibit 10.16to MarkWest Hydrocarbon, Inc.'s
Registration Statement on Form S-1, Registration No. 333-09513 and
incorporated herein by reference).
10.18 Purchase and Demolition Agreement Construction Premises, dated March
15, 1995, between Columbia Gas Transmission Corporation and MarkWest
Hydrocarbon Partners, Ltd. (Filed as exhibit 10.17 to MarkWest
Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration
No. 333-09513 and incorporated herein by reference).
10.19 Purchase and Demolition Agreement Remaining Premises, dated March
15, 1995, between Columbia Gas Transmission Corporation and MarkWest
Hydrocarbon Partners, Ltd. (Filed as exhibit 10.18 to MarkWest
Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration
No. 333-09513 and incorporated herein by reference).
10.20 Agreement to Design and Construct New Facilities, dated March 165,
1995, between Columbia Gas Transmission Corporation and MarkWest
Hydrocarbon Partners, Ltd. (Filed as exhibit 10.19 to MarkWest
Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration
No. 333-09513 and incorporated herein by reference).
10.21 Sales Acknowledgment, dated August 8, 1994, NO. 12577, confirming
sale to Ashland Petroleum Company (Filed as exhibit 10.20 to MarkWest
Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration
No. 333-09513 and incorporated herein by reference).
10.22 Contract for Construction and Lease of Boldman Plant, dated December
24, 1990, between Columbia Gas Transmission Corporation and MarkWest
Hydrocarbon partners, Ltd. (Filed as exhibit 10.22 to MarkWest
Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration
No. 333-09513 and incorporated herein by reference).
10.23 Natural Gas Liquids Purchase Agreement (Boldman Plant), dated
December 24, 1990, between Columbia Gas Transmission Corporation and
MarkWest Hydrocarbon Partners, Ltd. (Filed as exhibit 10.23 to
MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1,
Registration No. 333-09513 and incorporated herein by reference).
10.24 Natural Gas Liquids Purchase Agreement, dated April 26, 1988,
between Columbia Gas Transmission Corporation and MarkWest Hydrocarbon
Partners, Ltd. (Filed as exhibit 10.24 to
42
MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1,
Registration No. 333-09513 and incorporated herein by reference).
10.25 1996 Incentive Compensation Plan (Filed as exhibit 10.25 to MarkWest
Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration
No. 333-09513 and incorporated herein by reference).
10.26 1996 Stock Incentive Plan (Filed as exhibit 10.26 to MarkWest
Hydrocarbon, Inc.'s Registration Statement on Form S-1, Registration
No. 333-09513 and incorporated herein by reference).
10.27 1996 Nonemployee Director Stock Option Plan (Filed as exhibit 10.27
to MarkWest Hydrocarbon, Inc.'s Registration Statement on Form S-1,
Registration No. 333-09513 and incorporated herein by reference).
10.28 Form of Non-Compete Agreement between John M. Fox and MarkWest
Hydrocarbon, Inc. (Filed as exhibit 10.28 to MarkWest Hydrocarbon,
Inc.'s Registration Statement on Form S-1, Registration No. 333-09513
and incorporated herein by reference).
10.29 Sales Acknowledgment by Ashland Petroleum, 54 million gallons of
Normal Butane, dated September 9, 1996.
10.30 Sales Acknowledgment by Ashland Petroleum, 19.5 million gallons of
Isobutane, dated September 9, 1996.
10.31 Pipeline Construction and Operating Agreement between Michigan
Production Company, L.L.C. and West Shore Processing Company, L.L.C.,
dated October 1, 1996.
10.32 Non-Recourse Loan Agreement between Michigan Production Company,
L.L.C. and West Shore Processing Company, L.L.C., dated October 1,
1996.
10.33 First Amendment to Participation, Ownership and Operating Agreement
for West Shore Processing Company, L.L. C., dated October 1, 1996.
10.34 Option and Agreement to Purchase and Sell Pipeline, dated October 1,
1996.
10.35 Mortgage, Assignment, Security Agreement and Financing Statement
from Michigan Production Company, L.L.C. to West Shore Processing
Company, L.L.C., dated October 22, 1996.
10.36 Amendment to Participation, Ownership and Operating Agreement for
West Shore Processing Company, L.L.C., dated December 12, 1996.
10.37 Assignment and Bill of Sale by and between Enron Gas Processing
Company and West Shore Processing Company, L.L.C., dated January 13,
1997.
11. Statement regarding computation of per share
21. List of Subsidiaries of MarkWest Hydrocarbon, Inc.
23. Consent of Price Waterhouse LLP, independent accountants
43
SIGNATURES
Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this Report to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Englewood,
State of Colorado on March 24, 1997.
MarkWest Hydrocarbon, Inc.
(Registrant)
BY: /s/ John M. Fox
-------------------------
John M. Fox
President and Chief
Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
/s/ John M. Fox March 24, 1997
---------------------------------
John M. Fox
President, Chief Executive
Officer and Director
/s/ Brian T. O'Neill March 24, 1997
---------------------------------
Brian T. O'Neill
Senior Vice President, Chief
Operating Officer and Director
/s/ Rita E. Harvey March 24, 1997
---------------------------------
Rita E. Harvey
Director of Finance and Treasurer
(Principal Financial and
Accounting Officer)
/s/ Arthur J. Denney March 24, 1997
---------------------------------
Arthur J. Denney
Director
/s/ Norman H. Foster March 24, 1997
---------------------------------
Norman H. Foster
Director
/s/ Barry W. Spector March 24, 1997
---------------------------------
Barry W. Spector
Director
/s/ David R. Whitney March 24, 1997
---------------------------------
David R. Whitney
Director
44