<PAGE>
Filed Pursuant to Rule 424(B)(3)
Reg. No. 333-09513
2,400,000 SHARES
[LOGO OF MARKWEST APPEARS HERE]
MARKWEST HYDROCARBON, INC.
COMMON STOCK
The 2,400,000 shares of Common Stock, par value $0.01 per share (the "Common
Stock"), offered hereby are being offered by MarkWest Hydrocarbon, Inc. (the
"Company"). Prior to this offering there has been no public market for the
Common Stock. See "Underwriting" for the factors considered in determining the
initial public offering price. Proceeds from the Offering in the amount of
$10.0 million will be used by the Company to repay indebtedness incurred by the
predecessor to the Company to fund an equivalent distribution to such
predecessor's partners. See "Use of Proceeds" and "Reorganization."
The Common Stock has been approved for listing on the Nasdaq National Market
under the symbol "MWHX," subject to official notice of issuance.
FOR A DISCUSSION OF RISKS OF AN INVESTMENT IN THE SHARES OF COMMON STOCK
OFFERED HEREBY, SEE "RISK FACTORS" ON PAGES 10-16.
---------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION
PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY
REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
---------------
<TABLE>
<CAPTION>
UNDERWRITING
PRICE TO DISCOUNTS AND PROCEEDS TO
PUBLIC COMMISSIONS* COMPANY+
<S> <C> <C> <C>
Per Share................................ $10.00 $0.70 $9.30
Total++.................................. $24,000,000 $1,680,000 $22,320,000
</TABLE>
- -------
* The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933, as
amended. See "Underwriting."
+ Before deducting expenses of the offering payable by the Company estimated to
be $585,000.
++The Company has granted the Underwriters a 30-day option to purchase up to
360,000 additional shares of Common Stock on the same terms per share solely
to cover over-allotments, if any. If such option is exercised in full, the
total price to public will be $27,600,000, the total underwriting discounts
and commissions will be $1,932,000 and the total proceeds to Company will be
$25,668,000. See "Underwriting."
---------------
The Common Stock is being offered by the Underwriters as set forth under
"Underwriting" herein. It is expected that the delivery of certificates
therefor will be made at the offices of Dillon, Read & Co. Inc., New York, New
York, on or about October 15, 1996, against payment therefor. The Underwriters
include:
DILLON, READ & CO. INC. GEORGE K. BAUM & COMPANY
The date of this Prospectus is October 9, 1996.
<PAGE>
At the top center of the inside front cover page is the MarkWest logo and
centered below that is the phrase "Operating Facilities."
The center of the page contains an outlined sketch of five contiguous states
including Michigan, Ohio, West Virginia, Kentucky and Tennessee. These states
are positioned and connected as they would be on a map of the United States.
The location of several of MarkWest's operating facilities are indicated
with a circled star within the states described above.
Six pictures are included on the page, with one line from each circled star
indicated on the map to each picture. A narrative description is written
directly beneath each picture. The following pictures and narrative
descriptions appear on the page: Victory Michigan Compressor Station (top left
of page); West Memphis Terminal (middle left of page); Boldman NGL Extraction
Plant (bottom left of page); Compressor at Kenova Extraction Plan (top right
of page); Siloam Fractionation Plant (middle right of page); and Church Hill
Rail Facility (bottom right of page).
[GRAPHICS APPEAR HERE]
----------------
IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK
OFFERED HEREBY AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN
MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE NASDAQ NATIONAL MARKET OR
OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.
<PAGE>
PROSPECTUS SUMMARY
The following summary should be read in conjunction with, and is qualified in
its entirety by, the more detailed information and financial statements and
notes thereto appearing elsewhere in this Prospectus. Unless otherwise
indicated, all information in this Prospectus assumes the Underwriters' over-
allotment option is not exercised. As used in this Prospectus, the terms
"Company" and "MarkWest" refer, unless the context requires otherwise, to the
Company, its subsidiaries, joint venture entities managed by the Company or its
subsidiaries, or their interests therein, and include the business activities
of MarkWest Hydrocarbon Partners, Ltd. See "Reorganization."
THE COMPANY
MarkWest Hydrocarbon, Inc. ("MarkWest" or the "Company") 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 liquid ("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. In the
twelve months ended December 31, 1995, MarkWest produced approximately 92
million gallons of NGLs and marketed approximately 127 million gallons of NGLs.
The Company's processing and marketing operations are concentrated in two
core areas which 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 has taken several key steps intended to expand its
operations. In January 1996, the Company commissioned a new natural gas liquids
extraction plant in Wayne County, West Virginia, which replaced a 1958 vintage
extraction facility owned and operated by Columbia Gas Transmission Company
("Columbia Gas"). Because the Company owns and operates this new facility, the
Company will generate increased revenue, and fee revenues related to processing
operations will represent a greater proportion of total revenues. In addition,
the Company believes this new facility will generate greater NGL recovery from
natural gas, reduce downtime for maintenance, and significantly decrease fuel
costs compared to the replaced facility.
In May 1996, the Company established West Shore Processing Company, LLC
("West Shore"), a venture in western Michigan, which the Company will develop
as its Michigan Core Area. West Shore has exclusive gathering, treatment and
processing agreements with companies owned by Tenneco Ventures Corporation
("Tenneco") and ENCAP Investments LLC ("ENCAP") covering the natural gas
production from all wells and leases owned by it within western Michigan. West
Shore also is negotiating agreements with several exploration and production
companies that would result in additional dedication of natural gas production
to the gathering, treatment and processing facilities of West Shore. The
natural gas streams to be dedicated to West Shore will primarily
3
<PAGE>
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 have
been produced from the Northern Niagaran Reef trend. Upon completion of the
first two phases of development, West Shore's processing operations are
expected to have 30 million cubic feet per day (MMcf/D) of capacity provided by
Shell Offshore, Inc. ("Shell"), 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 will exceed
capacity. The Company also has entered into an agreement with Callon
Exploration Company ("Callon") to conduct exploration activity in the Michigan
Core Area. See "--Recent Developments."
INDUSTRY OVERVIEW
Natural gas processing and related services represent a major segment of the
oil and gas industry, providing the necessary service of converting natural gas
into marketable energy products. When natural gas is produced at the wellhead,
it must be gathered, and in some cases compressed or pressurized, for
transportation via pipelines (described as gathering services) to gas
processing plants. The processing plants remove water vapor, solids and other
contaminants, such as hydrogen sulfide or carbon dioxide in the natural gas
stream that would interfere with pipeline transportation or marketing of the
gas to consumers and also extract the NGLs from the natural gas (described as
treatment and extraction services, respectively). The NGLs are then subjected
to various processes that cause the NGLs to separate, or fractionate, into
marketable products such as propane, normal butane, isobutane and natural
gasoline (described as fractionation services).
Over the past 10 years, independent gas processing has experienced
significant growth. In 1995, independent natural gas processing companies
accounted for 319,000 barrels per day of NGL production, or approximately 23%
of total U.S. NGL production by the 20 largest U.S. natural gas producers,
compared to less than 4% of such producers' NGL production in 1985. The
increase in the independent gas processing industry has resulted in part from
the divestiture by major energy companies and interstate pipeline companies of
their gas gathering and processing assets and the decision by many such
companies to outsource their gas processing needs.
An important factor expected to contribute to the continuing growth of
independent processing companies is the upward trend of gas consumption and
production in the United States. Natural gas consumption in the United States
has increased from 16.2 trillion cubic feet (Tcf) per year in 1986 to 21.3 Tcf
per year in 1995, and is forecast to increase to 24.0 Tcf per year by the year
2000. The number of natural gas rigs in service also has recently increased.
From June 1995 to June 1996, the number of natural gas rigs in service rose
from 340 to 464. This natural gas rig count is the highest in over four years,
and, as a percentage of total oil and gas rigs in service, the highest in the
last decade. Many newly discovered gas wells and gas fields will require access
to gathering and processing infrastructure, providing significant opportunities
for growth-oriented independent gas processing companies such as MarkWest.
STRATEGY
The Company's primary objective is to achieve sustainable growth in cash flow
and earnings by increasing the volume of natural gas that it gathers and
processes and the volume of NGLs that it produces and markets. To achieve this
objective, the Company employs a number of related strategies.
Geographic Core Areas. The Company emphasizes opportunities for investment in
geographic core areas where there is significant potential to achieve a
position as the area's dominant natural gas processor. The Company believes
that growth in core areas can be achieved by developing processing facilities
both in areas where a large energy or pipeline company requires processing
services and in areas where there is significant potential for natural gas
production but not significant processing capacity.
4
<PAGE>
Long-Term Strategic Relationships. The Company seeks strategic relationships
with the dominant pipelines and gas producers in each area in which the Company
operates. In the Appalachian Core Area, MarkWest owns three processing plants
that process natural gas or NGLs dedicated by Columbia Gas. In its Michigan
Core Area, the Company has entered into gas supply and processing relationships
with Shell and Michigan Production Company, LLC ("MPC"), a company jointly
owned by Tenneco and ENCAP.
NGL Marketing. The Company strives to maximize the downstream value of its
gas and liquid products by marketing directly to distributors and resellers.
Particularly in the area of NGL marketing, the Company minimizes the use of
third party brokers and instead supports a direct marketing staff focused on
refiners, petrochemical companies, gasoline blenders, and multistate and
independent propane dealers. Additionally, the Company uses its own truck and
tank car fleet, as well as its own terminals and storage facilities, to provide
supply reliability to its customers. All of these efforts have allowed the
Company to maintain pricing of its NGL products at a premium to Gulf Coast spot
prices.
Cost-Efficient Operations. The Company seeks a competitive advantage by
utilizing in-house processing and operating expertise to provide lower-cost
service. To provide competitive processing services, the Company emphasizes
facility design, project management and operating expertise that permits
efficient installation and operation of its facilities. The Company has in-
house engineering personnel who oversee the design and construction of the
Company's processing plants and equipment.
Acquisitions. The Company believes that there are significant opportunities
to make strategic acquisitions of gathering and processing assets because of
the divestiture by major energy companies and interstate pipeline companies of
their gas gathering and processing assets. The Company pursues acquisitions
that can add to existing core area investments or can lead to new core area
investments.
Exploration as a Tool to Enhance Gas Processing. The Company maintains a
strategic gas exploration effort that is designed to permit the Company to gain
access to additional natural gas supplies within its existing core areas and to
gain foothold positions in production regions that the Company might develop as
new core processing areas.
RECENT DEVELOPMENTS
In May 1996, the Company entered into arrangements for the establishment of
West Shore, a company jointly owned with Michigan Energy Company, LLC ("MEC").
At the present time, the assets of West Shore consist of a 31-mile sour gas
pipeline that is situated in Manistee and Mason Counties, Michigan (the "Basin
Pipeline"), and a number of processing contracts. West Shore will be dedicated
to natural gas gathering, treatment and processing and NGL marketing in western
Michigan. MarkWest is the operator of West Shore.
The Company has entered into agreements to construct approximately 50 miles
of pipeline to provide access to processing services to existing shut-in wells
owned by MPC and providing it the right to construct a new 50 million cubic
feet per day plant to extract NGLs. In addition, the Company expects either to
construct a new treatment plant or to expand Shell's existing plant capacity to
treat the sour gas predominant in the Michigan Core Area. The activities
contemplated by such agreements, together with the further development of West
Shore and the Basin Pipeline, are referred to herein as the "Michigan Project."
Substantially all of the natural gas produced from the western region of the
Michigan Core Area is sour. While several successful large wells have been
developed in the region, the natural gas producers have lacked adequate
gathering and processing facilities for sour gas, and development of the trend
has been inhibited as a result. With the additional capacity to be provided by
West Shore's sour gas pipeline and processing and treatment facilities, the
Company expects further development in western Michigan which will create
demand for West Shore's gathering and processing services. See "Business--
Natural Gas Processing and Related Services--Michigan Core Area."
5
<PAGE>
REORGANIZATION
The Company was incorporated as a Delaware corporation in 1996 to act as the
successor to the business of MarkWest Hydrocarbon Partners, Ltd. ("MarkWest
Partnership"), a Colorado limited partnership formed in 1988. Upon
effectiveness of the Offering, the Company will succeed to the business, assets
and liabilities of MarkWest Partnership. See "Reorganization" and "Certain
Transactions." The description of the Company and its business included in this
Prospectus assumes the consummation of the reorganization transactions.
The Company's principal executive offices are located at 5613 DTC Parkway,
Suite 400, Englewood, Colorado 80111. Its telephone number is (303) 290-8700.
THE OFFERING
<TABLE>
<S> <C>
Common Stock offered by the Company.... 2,400,000 shares
Common Stock to be Outstanding after
the Offering (1)...................... 8,125,000 shares
Use of Proceeds........................ Repayment of indebtedness (including
$10.0 million of indebtedness incurred
to make $10.0 million of distributions
to partners
of MarkWest Partnership). See "Use of
Proceeds" and "Certain Transactions--
Partnership Distributions."
Nasdaq National Market Symbol.......... MWHX
</TABLE>
- --------
(1) Excludes (i) 163,695 shares issuable upon exercise of stock options
outstanding as of the effective date of the Offering with a weighted average
exercise price of $7.11 per share under the Company's 1996 Stock Incentive
Option Plan; (ii) 486,305 shares reserved for future issuance under the 1996
Stock Incentive Plan; and (iii) 20,000 shares reserved for future issuance
under the Company's 1996 Non-Employee Director Stock Option Plan.
6
<PAGE>
SUMMARY CONSOLIDATED FINANCIAL INFORMATION AND OTHER DATA*
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
-------------------------- -----------------
1993 1994 1995 1995 1996
------- ------- -------- -------- -------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Plant revenue.................. $34,212 $33,056 $ 33,823 $ 17,225 $18,045
Terminal and marketing
revenue....................... 19,756 13,666 13,172 5,200 9,831
Oil and gas and other
revenue....................... 1,783 1,830 1,075 501 744
Gain on sale of oil and gas
properties (1)................ -- 4,275 -- -- --
------- ------- -------- -------- -------
Total revenues............. 55,751 52,827 48,070 22,926 28,620
Costs and expenses:
Plant feedstock purchases...... 23,155 21,582 17,308 8,608 8,538
Terminal and marketing
purchases..................... 18,845 11,497 11,937 4,829 8,683
Operating expenses............. 6,504 4,393 4,706 2,005 2,979
General and administrative
expenses...................... 3,747 3,654 4,189 2,064 2,140
Depreciation, depletion and
amortization.................. 1,565 1,942 1,754 852 1,326
Reduction in carrying value of
assets (2).................... -- 2,950 -- -- --
------- ------- -------- -------- -------
Total costs and expenses... 53,816 46,018 39,894 18,358 23,666
Operating income................ 1,935 6,809 8,176 4,568 4,954
Interest expense, net of
interest income................ (1,395) (1,689) (352) (300) (466)
------- ------- -------- -------- -------
Net income before extraordinary
item........................... 540 5,120 7,824 4,268 4,488
Extraordinary loss on
extinguishment of debt......... -- -- (1,750) -- --
------- ------- -------- -------- -------
Net income (3).................. $ 540 $ 5,120 $ 6,074 $ 4,268 $ 4,488
======= ======= ======== ======== =======
PRO FORMA INFORMATION
(UNAUDITED):
Historical income before income
taxes, extraordinary item, and
cumulative effect of change in
accounting principle........... $ 540 $ 5,120 $ 7,824 $ 4,268 $ 4,488
Pro forma provision for income
taxes.......................... 228 1,424 2,937 1,667 1,670
------- ------- -------- -------- -------
Pro forma net income (3)........ $ 312 $ 3,696 $ 4,887 $ 2,601 $ 2,818
======= ======= ======== ======== =======
Pro forma net income, as
adjusted (4)................... $ 5,204 $ 3,138
======== =======
Pro forma net income, combined
(5)............................ $ 5,173 $ 3,096
======== =======
PRO FORMA PER COMMON SHARE:
Pro forma net income............ $ 0.06 $ 0.65 $ 0.86 $ 0.46 $ 0.49
======= ======= ======== ======== =======
Pro forma weighted average
common shares outstanding (6).. 5,601 5,687 5,713 5,713 5,748
======= ======= ======== ======== =======
Pro forma net income, as
adjusted (7)................... $ 0.67 $ 0.39
======== =======
Pro forma net income, combined
(5)............................ $ 0.67 $ 0.38
======== =======
Pro forma weighted average
shares outstanding, as adjusted
(6)............................ 7,716 8,148
======== =======
STATEMENT OF CASH FLOWS DATA:
Cash flows from operating
activities..................... $ 2,217 $ 994 $ 5,436 $ 10,671 $10,945
Cash flows provided by (used in)
investing activities........... $(6,917) $ 9,068 $(12,610) $ (5,212) $(2,569)
Cash flows provided by (used in)
financing activities........... $ (315) $(5,886) $ 2,467 $(10,514) $(8,471)
OTHER DATA:
NGL production (gallons)........ 93,355 99,735 92,239 49,826 43,094
EBITDA (8)...................... $ 3,500 $ 7,426 $ 9,930 $ 5,420 $ 6,280
Capital expenditures............ $ 6,941 $ 1,442 $ 12,426 $ 5,297 $ 2,522
Partnership distributions....... $ 3,040 $ 320 $ 4,150 $ 3,381 $ 3,219
</TABLE>
7
<PAGE>
<TABLE>
<CAPTION>
JUNE 30, 1996
-----------------------------------
PRO FORMA, AS
ACTUAL PRO FORMA (9) ADJUSTED (10)
------- ------------- -------------
(UNAUDITED)
<S> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents................. $ 666 $ 896 $ 281
Working capital........................... 5,144 5,274 4,759
Total assets.............................. 43,991 44,321 43,606
Total debt................................ 12,350 22,350 --
Total partners' capital/stockholders'
equity................................... 26,464 13,488 35,223
</TABLE>
- --------
* The financial information set forth is that derived from the financial
statements and operating data of MarkWest Partnership, the predecessor to the
Company.
(1)Represents the gain on the sale of a significant portion of the Company's
oil and gas producing assets for proceeds of approximately $10.1 million.
(2)Represents a $2.2 million write-down to estimated realizable value of an
isomerization unit that was shut down, a $347,000 charge relating to a catalyst
used in the isomerization process and a $361,000 charge for the write-down of
non-productive equipment related to various business development projects.
(3)Net income for all periods presented includes no income tax effects
because the Company operated as a partnership (non-taxable entity) during these
periods. Pro forma net income is presented for purposes of comparability
assuming the Company was a taxable entity for all periods presented.
(4)Pro forma net income, as adjusted, reflects pro forma net income adjusted
for the reduction in interest expense resulting from the application of a
portion of the estimated proceeds of this Offering to repay indebtedness
outstanding prior to the Offering. See "Use of Proceeds" and the Unaudited Pro
Forma Condensed Consolidated Financial Statements included elsewhere in this
Prospectus.
(5)Pro forma net income combined presents pro forma net income, as adjusted,
giving effect to the Basin acquisition. The amounts presented are computed
based on MarkWest Partnership's ownership interest in Basin as of June 30, 1996
of 5.3%. MarkWest Partnership intends to acquire additional ownership of Basin
through capital expenditures through the end of 1997, at which time it is
expected the ownership interest will be 60%. If the 60% ownership interest was
used, the pro forma net income combined per common share amounts would be $0.66
and $0.34 for the year ended December 31, 1995 and the six months ended June
30, 1996, respectively. See the Unaudited Pro Forma Condensed Consolidated
Financial Statements included elsewhere in this Prospectus for detailed
computations of the pro forma effects at both ownership levels.
(6)See the Unaudited Pro Forma Condensed Consolidated Financial Statements
included elsewhere in this Prospectus.
(7)Pro forma net income, as adjusted, per common share is presented to give
effect to the issuance of the number of shares required for net proceeds to
repay indebtedness outstanding prior to the Offering, including the
indebtedness incurred to fund the Partnership Distribution. The amount is
computed by dividing pro forma net income, as adjusted, as described in (4)
above, by the total of the pro forma weighted average common shares outstanding
prior to the Offering plus the additional shares for which the net proceeds
will be used to repay the indebtedness.
(8)EBITDA represents earnings before interest income, interest expense,
income taxes, depreciation, depletion and amortization, gain on sale of oil and
gas properties, reduction in carrying value of assets and extraordinary items.
EBITDA, as defined by the Company, may not be comparable to similarly titled
measures used by other companies. EBITDA, which is not a measure under
generally accepted accounting principles, is not intended to represent cash
flows for the period, nor has it been presented as an alternative to operating
income, or as an indicator of operating performance. It should not be
considered in isolation or as a substitute for measures of performance prepared
in accordance with generally accepted accounting principles. See the Company's
Consolidated Statements of Cash Flows in the Consolidated Financial Statements
included elsewhere in this Prospectus. The Company has included EBITDA because
it understands that such measure is used by certain investors to determine the
Company's ability to service its indebtedness. In addition, the Company uses
EBITDA to measure its performance against its industry peer group. EBITDA
should not be used as an indicator of the performance of the Company's
operating, investing or financing activities.
(9)Gives effect to the Reorganization, the accrual of $3.2 million of
deferred income tax liabilities and the Partnership Distribution (as
hereinafter defined). See "Reorganization" and the Unaudited Pro Forma
Condensed Consolidated Financial Statements included elsewhere in this
Prospectus.
(10)Further adjusted to reflect the sale of 2,400,000 shares of Common Stock
offered hereby and the application of the estimated net proceeds from the
Offering. See "Use of Proceeds."
8
<PAGE>
CERTAIN DEFINITIONS
The definitions set forth below apply to the terms used in this Prospectus:
"Bcf" means billion cubic feet of natural gas.
"Dedicated reserves" means natural gas reserves subject to long-term contracts
providing for the dedication to the Company's facilities for purchase or
processing of all gas produced from all formations on designated properties for
periods typically ranging from 10 to 20 years.
"EPA" means the Environmental Protection Agency.
"Extraction" means removing liquid and liquefiable hydrocarbons from natural
gas.
"FERC" means the Federal Energy Regulatory Commission.
"Fractionation" is the process by which the NGL stream is subjected to
controlled temperatures, causing the NGLs to separate, or fractionate, into the
separate NGL products ethane, propane, butane, isobutane and natural gasoline.
"Mcf" means thousand cubic feet of natural gas.
"MGal/D" or "MGal per day" mean thousand gallons per day.
"MMcf" means million cubic feet of natural gas.
"MMcf/D" or "MMcf per day" means million cubic feet per day.
"NGLs" means natural gas liquids.
"Processing" includes treatment, extraction and fractionation. "Processing
contracts" are those supply contracts dedicated to Company facilities whereby
title to the gas and marketing rights for such gas may remain with the gas
producer.
"Sour gas" means natural gas which contains sulfur compounds in excess of a
specified amount.
"Tcf" means trillion cubic feet of natural gas.
"Treatment" refers to the removal of water vapor, solids and other
contaminants, such as hydrogen sulfide or carbon dioxide, contained in the
natural gas stream that would interfere with pipeline transportation or
marketing of the gas to consumers.
9
<PAGE>
RISK FACTORS
In addition to the other information contained in this Prospectus, the
following factors should be considered carefully in evaluating the Company and
its business before purchasing any of the shares of Common Stock offered
hereby.
COMMODITY PRICE RISKS
The Company's products, including NGLs, natural gas and related by-products,
are commodities. As such, their prices are often subject to material changes
in response to relatively minor changes in supply and demand, general economic
conditions and other market conditions over which the Company has no control.
Other conditions affecting the Company's business include the availability and
prices of competing commodities and of alternative energy and feedstock
sources (primarily oil), government regulation, industry-wide inventory
levels, the seasons, the weather and the impact of energy conservation
efforts. The Company's principal NGL product is propane, sales of which
accounted for approximately 70% of the Company's total revenues during 1995
and approximately 69% of the Company's total revenues during the six months
ended June 30, 1996. Propane sold to the Company's customers is used primarily
for home heating, and therefore the demand tends to be seasonal, increasing
sharply in the winter months. Demand for, and prices of, propane also depend,
to a large extent, upon the severity of the weather in the Company's operating
areas during the winter months. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations--General,"
"--Seasonality" and "Business--Industry Overview."
Under the Company's keep-whole contracts, which accounted for approximately
70% of the Company's total revenues during 1995 and approximately 58% of the
Company's total revenues during the six months ended June 1996, a principal
cost of processing gas is the reimbursement to the natural gas producers for
the energy (measured in BTUs) extracted from the natural gas stream in the
form of NGLs and consumed as fuel during processing, less the amount of energy
the Company is contractually entitled to retain. Profitability under such
contracts is largely influenced by the margin between NGL sales prices and the
cost of such reimbursement (which cost is directly related to the price of
natural gas), and may be negatively affected by increases in natural gas
prices. A contraction of the margin between the two prices may result in a
reduction in the Company's operating margin. A prolonged contraction of such
margin could have a material adverse effect on the financial condition and
results of operations of the Company. See "Business--Natural Gas Processing
and Related Services--Gas Processing Contracts and Natural Gas Supply."
AVAILABILITY OF NATURAL GAS SUPPLY
Natural gas is the source of the Company's NGLs. To maintain throughput in
its NGL extraction and fractionation systems, the Company must continually
contract to process additional natural gas provided from new or existing
sources. Future natural gas supplies available for processing at the Company's
plants will be affected by a number of factors that are not within the
Company's control, including partial or complete shut downs of major pipelines
supplying the Company's processing plants, the depletion rate of gas reserves
currently connected and the extent of exploration for, production and
development of, and demand for natural gas in the areas in which the Company
operates. Over 95% of the natural gas processed by the Company is dedicated
under contracts with remaining terms of one year or more. However, long-term
contracts do not protect the Company from shut-ins or supply curtailments by
gas suppliers or from depletion of gas reserves. Although the Company has
historically been successful in contracting for new gas supplies and in
renewing gas supply contracts as they have expired, there can be no assurance
that the Company will in the future be successful in renewing or increasing
its access to natural gas supply or the throughput of its processing
facilities. See "Business--Natural Gas Processing and Related Services."
DEPENDENCE ON MAJOR PIPELINES
In recent years, all of the Company's gas volume has been delivered through
the Columbia Gas pipeline gathering systems. Columbia Gas has, from time to
time, sold portions of its transmission and gathering systems.
10
<PAGE>
The Company has been informed by Columbia Gas that it intends to engage in
negotiations with third parties regarding the possible sale of all or a
portion of the gathering systems that provide throughput to the Company's
plants. If Columbia Gas were to sell such systems or change its policies
significantly with respect to gas transported for producers, other sources of
natural gas might have to be obtained. There can be no assurance that adequate
alternative sources of natural gas will be available or that such sources will
be available at prices that are as favorable to the Company as existing
arrangements. See "Business--Natural Gas Processing and Related Services."
RISKS OF NGL AND NATURAL GAS MARKETING
The profitability of the NGL and natural gas marketing operations of the
Company depends in large part on the ability of the Company's management to
assess and respond to changing market conditions in negotiating natural gas
purchase and/or processing agreements and NGL and natural gas sales
agreements. The inability of management to respond appropriately to changing
market conditions could have a negative effect on the Company's profitability.
The duration of the Company's natural gas processing contracts range from one-
time spot purchase and processing agreements to 15 years. Under certain
longer-term agreements, the Company is obligated to purchase or sell specified
quantities of natural gas at prices related to the market price. Although the
Company attempts to match its long-term purchase obligations with long-term
sales obligations, it is still subject to price risk, particularly where the
index or market for determining the purchase price under a purchase contract
is different from the index or market for determining the sales price under
the corresponding sales contract. Because longer-term purchase contracts may
permit some variation in the amount the producer is obligated to deliver or a
purchaser is obligated to purchase, matched contracts may result in an
imbalance of the natural gas volumes the Company is obligated to purchase and
sell. See "Business--Gas Processing Contracts and Natural Gas Supply."
RISKS OF OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
To date, the Company has conducted only limited exploration and production
activities for new natural gas sources as a supporting function for its
processing services. However, the Company expects to make significant
investments in exploration and production activities in the Michigan Core Area
and elsewhere. Exploration and production activities are subject to many
risks, including the risk that no commercially productive reservoirs will be
encountered. There can be no assurance that the Company's natural gas
exploration efforts will be productive or that the Company will recover all or
any portion of its investment in such activities. Drilling for natural gas may
involve unprofitable efforts, not only from dry wells, but also from wells
that are productive but do not produce sufficient net revenues to return a
profit after drilling, operating and other costs. The cost of drilling,
completing and operating wells is often uncertain. The Company's drilling
operations may be curtailed, delayed or canceled as a result of numerous
factors, many of which are beyond the Company's control, including a
substantial or extended decline in the price for oil and natural gas, title
problems, weather conditions, compliance with governmental requirements and
shortages or delays in the delivery of equipment and services. See "Business--
Exploration and Production."
RISKS RELATING TO THE MICHIGAN PROJECT
In May 1996, the Company entered into a number of agreements providing for
the development of gathering, treatment and processing facilities in the
Michigan Core Area. See "Business--Natural Gas Processing and Related
Services--Michigan Core Area." There can be no assurance that the projects
proposed by the Company in Michigan can be completed in the time frame
projected or within the current budget or that upon completion the Company
will be able to successfully integrate the newly developed assets into the
Company's business. In addition, certain of the assets acquired in the
Michigan Core Area have a history of losses. There can be no assurance that
the Company will be able to operate its Michigan Core Area assets in a
profitable manner or recover all or any portion of its investment in the
Michigan Core Area.
11
<PAGE>
GENERAL BUSINESS RISKS
The Company and its affiliates are subject to all of the risks generally
associated with the gathering, processing, transportation and storage of
natural gas and NGLs, including damage to its own and third-party pipelines,
storage facilities, related equipment and surrounding properties caused by
weather and other acts of God, construction and farm equipment, automobiles,
fires and explosions, as well as leakage of natural gas and spills of NGLs.
The Company's exploration and production operations are subject to hazards and
risks inherent in drilling for and production of oil and natural gas, such as
fires, natural disasters, explosions, encountering formations with abnormal
pressures, blowouts, cratering, pipeline ruptures and spills, any of which
could result in the loss of hydrocarbons, environmental pollution, personal
injury claims and other damage to the property of the Company and others. The
Company's operations in the Michigan Core Area are subject to additional risks
resulting from the processing and treatment of sour gas, including an
increased risk of property damage, bodily injury or death from the highly
toxic nature of sour gas. The Company's operating storage facilities
incorporate certain primary and backup equipment which, in the event of
mechanical failure, might take some time to replace, and the operation of such
storage facility could be materially impaired. The Company does not fully
insure against such risks, nor does the Company insure against potential loss
of product in such storage facilities. Losses resulting from the occurrence of
such events in excess of the Company's insurance could have a material adverse
effect on the financial condition and results of operation of the Company. See
"Business--Operational Risks and Insurance."
POTENTIAL VARIABILITY IN QUARTERLY OPERATING RESULTS
The Company's quarterly revenues and operating results have varied
significantly in the past and are likely to vary substantially from quarter to
quarter in the future. Quarterly revenues and operating results may fluctuate
as a result of changes in availability of and prices for natural gas and
changes in demand for gas and NGLs because of weather and variability in
demand for NGLs used as feedstocks in the petrochemical, refining and other
industries. Approximately 70% of the Company's total revenues during 1995 and
approximately 69% of the Company's total revenues during the six months ended
June 1996 resulted from the sale of propane. The strongest demand for propane
and the highest propane sales margins generally occur during the winter
heating season. As a result, the Company recognizes the greatest proportion of
its operating income during the first and fourth quarters of the year.
Operating results may also vary based upon the prices of natural gas purchased
by the Company. Because of the foregoing factors, the Company's operating
results for any particular quarterly period may not be indicative of results
for future periods and there can be no assurance that the Company will be able
to achieve or maintain profitability on a quarterly or annual basis in the
future. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Results of Operations."
DEPENDENCE ON CERTAIN CUSTOMERS
Sales to Ashland Petroleum Company and Ashland Chemical Company
(collectively, "Ashland") and Ferrellgas, L.P. ("Ferrellgas") accounted for
14% and 9%, respectively, of the Company's revenues during the first six
months of 1996 and 18% and 8%, respectively, of the Company's revenues during
1995. The existing contracts with Ashland expired in August 1996. Negotiations
for renewal of these contracts have been completed, and the Company expects to
execute new contracts with Ashland by the end of September 1996 providing for
a new three-year term effective September 1, 1996. The existing contracts with
Ferrellgas expire April 30, 1997. To the extent that Ashland, Ferrellgas and
other customers may reduce volumes under existing contracts, the Company would
be adversely affected unless it were able to make comparably profitable
arrangements with other customers. See "Business--Sales and Marketing."
GOVERNMENT REGULATION
Many aspects of the gathering, processing, marketing and transportation of
gas and NGLs by the Company are subject to federal, state and local laws and
regulations that can have a significant effect upon its operations. For
example, construction and operation of the Company's facilities require
governmental permits and approvals. Changes to federal laws and regulations
applicable to interstate transportation of gas implemented primarily during
the last five years have encouraged competition in nationwide markets for
natural gas sales and have fundamentally changed the business and regulatory
environment in which the Company markets and sells natural
12
<PAGE>
gas. Many of these regulatory changes have been promulgated by the FERC. FERC
regulation is still evolving and is subject to future modifications by the
FERC and the courts. The Company cannot predict the final requirements of the
FERC initiatives or their effect on the availability or cost of transportation
services to the Company or natural gas supplies associated with such
transportation services. See "Business--Government Regulation."
The Company's Kenova extraction plant was built to replace an older plant
owned by Columbia Gas. Columbia Gas has initiated proceedings with FERC
seeking abandonment approval for the replaced plant. The Company believes that
its gas processing plants are exempt from FERC jurisdiction, and has
specifically requested a ruling from FERC confirming that the new Kenova
extraction plant is exempt from FERC jurisdiction. There can be no assurance,
however, that FERC will confirm such exemption. 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. See "Business--
Government Regulation."
ENVIRONMENTAL MATTERS
Certain aspects of the Company's activities are subject to laws and
regulations designed to protect the environment. The cost of compliance with
such environmental laws that affect the Company can be substantial and could
have a materially adverse effect on the Company's financial condition.
Additionally, these laws could impose liability for remediation costs or
result in civil or criminal penalties for non-compliance. Environmental laws
frequently impose "strict liability" on property owners, facility operators
and certain other persons, which means that in some situations the Company
could be liable for cleanup costs resulting from improper conduct or
conditions caused by previous property owners, operators, lessees or other
persons not associated with the Company. Blowouts, ruptures or spills
occurring in connection with the Company's exploration and production
activities, as well as accident or breakage in any of the Company's natural
gas gathering, processing or related facilities, or at the Company's NGL
storage facilities, could subject the Company to liability for substantial
cleanup costs for resulting spills, leaks, emissions or other damage to the
environment or other property. See "Business--Environmental Matters."
COMPETITION
The Company's competitors in its respective lines of business include major
integrated oil and gas companies, affiliates of major interstate and
intrastate pipeline companies and national and local natural gas gatherers,
NGL brokers and distributors of varying size, financial resources and
experience. Many of these competitors, particularly those affiliated with
major integrated oil and gas and interstate and intrastate pipeline companies,
have financial resources substantially greater than those of the Company and
control supplies of natural gas and NGLs substantially greater than those
available to the Company. In addition, producers of natural gas and NGLs have
the ability to sell directly to customers in competition with the Company and
in periods of ample supply may do so at prices below the prices in the
Company's natural gas and NGLs sales contracts. Certain regulatory actions of
the FERC have also increased competition in natural gas and NGL marketing. See
"Business--Competition" and "--Government Regulation."
DEPENDENCE ON KEY PERSONNEL
The Company is highly dependent on a limited number of key management
personnel, particularly John M. Fox, its Chief Executive Officer, Brian T.
O'Neill, its Chief Operating Officer and Arthur Denney, its Vice President of
Engineering and Business Development. The Company's future success will also
depend, in part, on its ability to attract and retain highly qualified
personnel. There can be no assurance that the Company will be successful in
hiring or retaining qualified personnel. The loss of key personnel to death,
disability or termination, or the inability to hire and retain qualified
personnel, could have a material adverse effect on the Company's business,
financial condition and results of operations. The Company has key-person life
insurance on Messrs. Fox and O'Neill. See "Management."
13
<PAGE>
RISKS PERTAINING TO ACQUISITIONS
An important element of the Company's business strategy has been, and
continues to be, to expand through acquisitions. The Company's future growth
is partially dependent upon its ability to identify suitable acquisitions and
effectively integrate acquired assets with the Company's operations. There can
be no assurance that suitable assets will be available for acquisition by the
Company, that such assets will be available on terms acceptable to the Company
or that competition for such assets will not render such acquisitions
economically infeasible. In addition, there can be no assurance that financing
will be available to fund future acquisitions, or, if available, that the cost
of such funds will be available on terms favorable to the Company. In
connection with certain acquisitions, the Company may also be required to
assume certain liabilities, including environmental liabilities, known or
unknown, in connection with future acquisitions. See "--Environmental
Matters."
NO PRIOR PUBLIC MARKET; DETERMINATION OF OFFERING PRICE; POSSIBLE VOLATILITY
OF STOCK PRICE
Prior to this Offering, there has been no public market for the Company's
Common Stock and there can be no assurance that an active trading market for
the Common Stock will develop or be sustained after this Offering. In the
event that the Company's Common Stock is thinly traded, stockholders may not
be able to sell a significant amount of Common Stock at the price quoted or at
all. The initial public offering price for the Common Stock will be determined
by negotiation between the Company and the Managing Underwriters based on
several factors and may bear no relationship to the market price of the Common
Stock subsequent to this Offering. Following this Offering, the market price
for the Common Stock may be highly volatile depending on various factors,
including the general economy, stock market conditions, announcements by the
Company, its suppliers or competitors and fluctuations in the Company's
operating results. In addition, the stock market historically has experienced
volatility which has affected the market price of securities of many companies
and which has sometimes been unrelated to the operating performance of such
companies. The trading price of the Common Stock could also be subject to
significant fluctuations in response to variations in quarterly results of
operations, changes in earnings estimates by analysts, governmental regulatory
action, general trends in the industry and overall market conditions, and
other factors. See "Underwriting."
CONTROL BY SIGNIFICANT STOCKHOLDERS
After giving effect to the Offering, John M. Fox, the Company's Chief
Executive Officer, and Brian T. O'Neill, the Company's Chief Operating
Officer, (collectively, the "Significant Stockholders"), will control
approximately 60% of the outstanding Common Stock (58% if the Underwriters'
over-allotment option is exercised in full). If they decide to vote together,
these stockholders would be able to elect all of the Company's directors,
control the management and policies of the Company and determine the outcome
of any matter submitted to a vote of the Company's stockholders. Provisions of
the Company's Certificate of Incorporation also strengthen the control of the
Significant Stockholders over the Company and may act to reduce the likelihood
of a successful attempt to take over the Company or acquire a substantial
amount of Common Stock without their consent. See "Principal Stockholders" and
"Description of Capital Stock."
CONFLICTS OF INTEREST
Currently, the Company and MAK-J Energy Partners, Ltd. ("MAK-J Energy"), an
entity controlled by John M. Fox, the President and Chief Executive Officer of
the Company, own 49% and 51% undivided interests, respectively, in certain oil
and gas properties that the Company operates pursuant to joint venture
agreements governing such properties. See "Business--Exploration and
Production" and "Certain Transactions--Investments with Affiliate." Pursuant
to the agreements, the Company provides certain management and administrative
services related to the properties for which MAK-J Energy pays the Company a
monthly fee. While the amount of the monthly fee will in the future be subject
to renegotiation and approval by the Company's independent directors, the
monthly fee for fiscal 1996 was not negotiated on an arm's length basis.
Moreover, conflicts of interest may arise regarding such oil and gas
activities, including decisions regarding expenses and capital expenditures
and the timing of the development and exploitation of the properties.
14
<PAGE>
Mr. Fox has agreed that as long as he is an officer or director of the
Company and for two years thereafter, he will not, directly or indirectly,
participate in any future oil and gas exploration or production activities
with the Company except and to the extent that the Company's independent and
disinterested directors deem it advisable and in the best interests of the
Company to include one or more additional participants, which participants may
include entities controlled by Mr. Fox. Additionally, Mr. Fox has agreed that
as long as he is an officer or director of the Company and for two years
thereafter, he will not, directly or indirectly participate in any future oil
and gas exploration or production activity that may be in competition with
exploration or production activities of the Company except and to the extent
that Mr. Fox has first offered the Company the opportunity to participate in
that activity and the Company's independent and disinterested directors deem
it advisable and in the best interests of the Company not to participate in
that activity. The terms of any future transactions between the Company and
its directors, officers, principal stockholders or other affiliates, or the
decision to participate or not participate in transactions offered by the
Company's directors, officers, principal stockholders or other affiliates will
be approved by a majority of the Company's independent and disinterested
directors. The Company's Board of Directors will use such procedures in
evaluating their terms as are appropriate considering the fiduciary duties of
the Board of Directors under Delaware law. In any such review the Board may
use outside experts or consultants including independent legal counsel, secure
appraisals or other market comparisons, refer to generally available
statistics or prices or take such other actions as are appropriate under the
circumstances. Although such procedures are intended to ensure that
transactions with affiliates will be on an arm's length basis, no assurance
can be given that such procedures will produce such result.
POSSIBLE ANTI-TAKEOVER EFFECTS OF PROVISIONS OF THE CERTIFICATE OF
INCORPORATION AND BYLAWS
The Certificate of Incorporation and Bylaws of the Company include certain
provisions that may be deemed to have anti-takeover effects and may delay,
defer, or prevent a takeover attempt that a stockholder of the Company might
consider to be in the best interest of the Company or its stockholders. These
provisions authorize 5,000,000 shares of preferred stock that may be issued
from time to time by the Board of Directors of the Company with such powers,
rights, preferences and limitations as may be designated by the Board of
Directors. The Company's Bylaws provide that directors are elected in three
classes for a three-year term for each class. This provision limits the
ability of a controlling stockholder to change the composition of the Board of
Directors for at least two years. The Company also is subject to Section 203
of the Delaware General Corporation Law ("Section 203") regulating corporate
takeovers. Section 203 prevents Delaware corporations from engaging, under
certain circumstances, in a business combination with any "interested
stockholder" for three years after the date such stockholder became an
"interested stockholder." See "Description of Capital Stock--Change of Control
Provisions."
DILUTION
Purchasers of Common Stock in the Offering will experience immediate and
substantial dilution in the amount of $5.72 in the net tangible book value per
share of Common Stock from the initial public offering price. See "Dilution."
SHARES ELIGIBLE FOR FUTURE SALE
The availability for sale of certain shares of Common Stock held by existing
stockholders of the Company after this Offering could adversely affect the
market price of the Common Stock. Prior to the Offering, the Company will have
outstanding 5,725,000 shares of its Common Stock. In addition, the Company
will have 163,695 shares reserved for issuance upon the exercise of options
granted under the Company's 1996 Stock Incentive Plan, 486,305 shares reserved
for future issuance under the 1996 Stock Incentive Plan and 20,000 shares
reserved for future issuance under the Company's 1996 Non-Employee Director
Stock Option Plan. Of the 8,125,000 shares of Common Stock to be outstanding
following this Offering, the 2,400,000 shares being offered by the Company
hereby will be freely tradeable without restrictions or additional
registration under the Securities Act of 1933, as amended (the "Securities
Act"). The remaining 5,725,000 shares were issued and sold by the Company in
private transactions in reliance upon exemptions from registration under the
Securities
15
<PAGE>
Act. Of these shares, except as limited by lock-up agreements, up to 5,513,279
shares will be eligible for resale pursuant to Rule 144 under the Securities
Act ("Rule 144"). In connection with this Offering, all executive officers and
directors and certain other stockholders of the Company have agreed not to
offer, sell or otherwise dispose of a total of 5,480,610 shares held by them
for a period of 180 days after the effective date of this Offering, without
the prior written consent of Dillon, Read & Co. Inc. As many as all of the
shares subject to this lockup agreement would otherwise be available for
resale upon the effective date of the Offering under Rule 144. Sales of a
substantial amount of the currently outstanding shares of Common Stock in the
public market may adversely affect the market price of the Common Stock and
the ability of the Company to raise additional capital by occurring at a time
when it would be beneficial for the Company to sell securities. See
"Description of Capital Stock," "Shares Eligible for Future Sale" and
"Underwriting."
16
<PAGE>
REORGANIZATION
The Company was incorporated in June 1996 to act as the successor to MarkWest
Partnership. MarkWest Partnership was formed in 1988 and has conducted the
business of the Company since such date. Concurrently with the effectiveness of
the Offering, the Company will acquire from the current partners of MarkWest
Partnership all of the partnership interests in MarkWest Partnership pursuant
to a reorganization agreement entered into among the Company, MarkWest
Partnership, and each of the partners of MarkWest Partnership (the
"Reorganization Agreement"). Immediately following the Company's acquisition of
the MarkWest Partnership interests, MarkWest Partnership will be dissolved and
the Company will succeed to the business, assets and liabilities of MarkWest
Partnership. In addition, pursuant to the Reorganization Agreement, RIMCO
Partners L.P. and RIMCO Partners, L.P. II, holders of an option to purchase
3.5% of the outstanding equity of MarkWest Partnership, or an equivalent
interest in its successor, have agreed to exercise such option for shares of
Common Stock of the Company upon consummation of the transactions contemplated
by the Reorganization Agreement. Approximately 200,375 shares of Common Stock
will be issued upon exercise of such option. The Company believes that the
transactions contemplated by the Reorganization Agreement (referred to in this
Prospectus as the "Reorganization") will qualify as a tax-free reorganization
for United States federal income tax purposes.
Under the terms of the Reorganization Agreement, the consideration paid by
the Company to acquire the partnership interests from the partners of MarkWest
will consist of an aggregate of 5,725,000 shares of the Company's Common Stock.
The Reorganization Agreement provides that the partners will receive shares
representing a fully diluted percentage of the Company's Common Stock to be
outstanding immediately after consummation of the Reorganization (calculated
prior to the issuance of the Shares in the Offering) substantially equivalent
to the partners' interests in MarkWest Partnership. The partnership interests
in MarkWest Partnership exchanged in the Reorganization for shares of the
Company's Common Stock were originally purchased from MarkWest Partnership for
an equivalent average price per share of Common Stock equal to $2.36. See
"Dilution."
MarkWest Partnership currently has outstanding options issued to employees
that grant such employees the right to purchase partnership interests
representing approximately 3% of the fully diluted aggregate partnership
interests in MarkWest Partnership. As part of the Reorganization, such employee
options to purchase MarkWest Partnership interests will be replaced by 163,695
options to purchase shares of the Company's Common Stock granted pursuant to
the Company's 1996 Stock Incentive Plan. These options are exercisable at a per
share price equal to the total consideration that would have been paid by a
given individual to acquire all of the interest in MarkWest Partnership that
such individual was entitled to acquire, divided by the total number of options
received by such individual as part of the Reorganization. See "Management--
Compensation Plans--1996 Stock Incentive Plan."
Immediately prior to consummation of the Reorganization, MarkWest Partnership
intends to make distributions of $10.0 million to its partners as a partial
return of capital (the "Partnership Distribution"). See "Certain Transactions--
Partnership Distributions." MarkWest Partnership intends to borrow the funds
necessary to make the Partnership Distribution under MarkWest Partnership's
bank credit facility. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Liquidity and Capital Resources--Financing
Facilities." The Company intends to repay substantially all of such borrowings
with the net proceeds of this Offering. See "Use of Proceeds."
17
<PAGE>
USE OF PROCEEDS
The net proceeds to the Company from the sale of the 2,400,000 shares of
Common Stock offered hereby, at the initial public offering price of $10.00
per share, after deduction of the underwriting discounts and commissions and
offering expenses payable by the Company, will be approximately $21.7 million
($25.1 million if the Underwriters' over-allotment option is exercised in
full).
The Company will use all of such proceeds to repay outstanding long-term
indebtedness of the Company under its bank credit facility. As of June 30,
1996, $12.4 million was outstanding under this credit facility at an average
interest rate of approximately 8.0% and with quarterly installment payments
beginning September 30, 1998 up to the maturity date of June 30, 2002. The
majority of such indebtedness was incurred to fund the construction of the
Company's Kenova natural gas processing plant in Wayne County, West Virginia.
See "Business--Natural Gas Processing and Related Services--Appalachian Core
Area--NGL Extraction--Kenova Plant."Approximately $22.4 million is expected to
be outstanding as of the effective date of the Offering at an average interest
rate of approximately 7.6%. Of such indebtedness, $10.0 million will have been
incurred as a result of the Partnership Distribution prior to the effective
date of the Offering. See "Reorganization" and "Certain Transactions--
Partnership Distributions."
DIVIDEND POLICY
The Company has never paid any cash dividends on its stock and anticipates
that, for the foreseeable future, it will continue to retain any 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 applicable law, capital requirements and
other factors deemed relevant by the Company's Board of Directors. The
Company's predecessor, MarkWest Partnership, has made partnership
distributions from time to time. See "Certain Transactions--Partnership
Distributions."
18
<PAGE>
DILUTION
The pro forma net tangible book value of the Company as of June 30, 1996,
after giving effect to the Reorganization and the Partnership Distribution, was
approximately $13.0 million or $2.28 per share of Common Stock. Net tangible
book value per share represents the amount of total tangible assets of the
Company less total liabilities, divided by the number of shares of Common Stock
issued and outstanding. After giving effect to the sale of the 2,400,000 shares
of Common Stock offered by the Company hereby at the initial public offering
price of $10.00 per share and the application of the estimated net proceeds
therefrom as described under "Use of Proceeds," the pro forma net tangible book
value of the Company as of June 30, 1996 would have been $34.8 million, or
$4.28 per share. This represents an immediate increase in net tangible book
value of $2.00 per share to existing stockholders and an immediate dilution of
$5.72 per share to new investors.
The following table illustrates this per share dilution:
<TABLE>
<S> <C> <C>
Initial public offering price................................ $10.00
Pro forma net tangible book value before the Offering...... $ 2.28
Increase in pro forma net tangible book value attributable
to new investors.......................................... 2.00
Pro forma net tangible book value after the Offering......... 4.28
------
Dilution to new investors.................................... $ 5.72
======
</TABLE>
The following table summarizes, on a pro forma basis as of June 30, 1996, the
differences in the total consideration paid and the average price per share
paid by the Company's existing stockholders and by purchasers of the shares
offered hereby:
<TABLE>
<CAPTION>
SHARES PURCHASED TOTAL CONSIDERATION AVERAGE
----------------- ------------------- PRICE
NUMBER PERCENT AMOUNT PERCENT PER SHARE
--------- ------- ----------- ------- ----------
<S> <C> <C> <C> <C> <C>
Existing stockholders......... 5,725,000 70% $13,487,000 36% $ 2.36
New investors................. 2,400,000 30% 24,000,000 64% 10.00
--------- --- ----------- ---
Total....................... 8,125,000 100% $37,487,000 100% $ 4.61
========= === =========== ===
</TABLE>
The computations in the tables above exclude: (i) 163,695 shares of Common
Stock issuable upon exercise of stock options to be outstanding on the
effective date of the Offering with a weighted average exercise price of $7.11
per share under the Company's 1996 Stock Incentive Plan; (ii) 486,305 shares of
Common Stock reserved for future issuance under the 1996 Stock Incentive Plan;
and (iii) 20,000 shares reserved for future issuance under the Company's 1996
Non-Employee Director Stock Option Plan. To the extent such options are
exercised, there will be further dilution to new investors. See "Management"
and Note 2 of Notes to Consolidated Financial Statements.
19
<PAGE>
CAPITALIZATION
The following table sets forth the capitalization of the Company as of June
30, 1996 (i) on an actual basis; (ii) on a pro forma basis after giving effect
to the consummation of the Reorganization, the Partnership Distribution and the
accrual of $3.2 million of deferred income taxes resulting from conversion of
partnership to C corporation status; and (iii) such pro forma capitalization,
as adjusted, to reflect the sale of the 2,400,000 shares of Common Stock
offered hereby at the initial public offering price of $10.00 per share and the
application of the estimated net proceeds therefrom. See "Reorganization," "Use
of Proceeds," "Certain Transactions--Partnership Distributions" and the
Unaudited Pro Forma Condensed Consolidated Financial Statements included
herein. This table should be read in conjunction with the Consolidated
Financial Statements and the notes thereto included elsewhere in this
Prospectus.
<TABLE>
<CAPTION>
JUNE 30, 1996
------------------------------
PRO FORMA,
ACTUAL PRO FORMA AS ADJUSTED
------- --------- -----------
(IN THOUSANDS) (UNAUDITED)
<S> <C> <C> <C>
LONG-TERM DEBT:
Working capital line of credit................ $ 3,850 $ 3,850 $ --
Revolver loan................................. 8,500 18,500 --
------- ------- -------
Total long-term debt........................ 12,350 22,350 --
PARTNERS' CAPITAL/STOCKHOLDERS' EQUITY:
Partners' capital............................. 27,056 -- --
Preferred stock, $.01 par value 5,000,000
shares authorized; 0 shares issued and
outstanding.................................. -- -- --
Common stock, $.01 par value 20,000,000 shares
authorized; 5,725,000 shares issued and
outstanding; 8,125,000 shares issued and
outstanding pro forma as adjusted (1)........ -- 57 81
Additional paid-in capital.................... -- 13,828 35,539
Notes receivable (2).......................... (592) (397) (397)
------- ------- -------
Total stockholders' equity.................. 26,464 13,488 35,223
------- ------- -------
Total capitalization...................... $38,814 $35,838 $35,223
======= ======= =======
</TABLE>
- --------
(1) Excludes (i) 163,695 shares to be issuable upon exercise of stock options
outstanding as of the effective date of the Offering with a weighted average
exercise price of $7.11 per share under the Company's 1996 Stock Incentive
Option Plan; (ii) 486,305 shares reserved for future issuance under the 1996
Stock Incentive Plan; and (iii) 20,000 shares reserved for future issuance
under the Company's 1996 Non-Employee Director Stock Option Plan.
(2) Represents promissory notes from officers and employees of the Company
for the purchase of interests in MarkWest Partnership that have been assigned
to the Company. Upon receipt of their pro rata share of the Partnership
Distribution, stockholders with outstanding promissory notes are required to
remit a portion of their pro rata share of the Partnership Distribution to the
Company to be applied toward their outstanding balance. See "Certain
Transactions--Related Party Indebtedness."
20
<PAGE>
SELECTED CONSOLIDATED FINANCIAL AND OTHER INFORMATION
The selected consolidated statement of operations and balance sheet data set
forth below for the years ended December 31, 1993, 1994 and 1995 and as of
December 31, 1994 and 1995 are derived from, and are qualified by reference
to, audited consolidated financial statements of MarkWest Partnership, the
predecessor to the Company, included elsewhere in this Prospectus. The
selected consolidated statement of operations and balance sheet data set forth
below for the years ended December 31, 1991 and 1992 and as of December 31,
1991, 1992 and 1993 have been derived from audited financial statements not
included in this Prospectus. The selected consolidated statement of operations
and balance sheet data set forth below as of and for the six months ended June
30, 1995 and 1996 are derived from unaudited consolidated financial statements
of MarkWest Partnership, the predecessor to the Company. Such unaudited
consolidated financial statements, in the opinion of management, have been
prepared on the same basis as the audited consolidated financial statements
and include all significant adjustments, consisting only of normal recurring
adjustments, necessary for the fair presentation of the results of the interim
periods. The results of operations for interim periods are not necessarily
indicative of the results of operations for the entire year. 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 Prospectus.
<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
------------------------------------------- ----------------
1991 1992 1993 1994 1995 1995 1996
------- ------- ------- ------- ------- ------- -------
(IN THOUSANDS, EXCEPT SHARE DATA) (UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS
DATA:
Revenues:
Plant revenue.......... $38,048 $33,803 $34,212 $33,056 $33,823 $17,225 $18,045
Terminal and marketing
revenue............... 21,944 47,340 19,756 13,666 13,172 5,200 9,831
Oil and gas and other
revenue............... 445 737 1,783 1,830 1,075 501 744
Gain on sale of oil and
gas properties (1).... -- -- -- 4,275 -- -- --
------- ------- ------- ------- ------- ------- -------
Total.................. 60,437 81,880 55,751 52,827 48,070 22,926 28,620
Costs and Expenses:
Plant feedstock
purchases............. 18,483 18,330 23,155 21,582 17,308 8,608 8,538
Terminal and marketing
purchases............. 21,266 44,596 18,845 11,497 11,937 4,829 8,683
Operating expenses..... 5,099 5,194 6,504 4,393 4,706 2,005 2,979
General and
administrative
expenses.............. 4,403 4,500 3,747 3,654 4,189 2,064 2,140
Depreciation, depletion
and amortization...... 1,415 1,477 1,565 1,942 1,754 852 1,326
Reduction in carrying
value of assets (2)... -- 310 -- 2,950 -- -- --
------- ------- ------- ------- ------- ------- -------
Total.................. 50,666 74,407 53,816 46,018 39,894 18,358 23,666
Operating income........ 9,771 7,473 1,935 6,809 8,176 4,568 4,954
Interest expense, net of
interest income........ (949) (2,024) (1,395) (1,689) (352) (300) (466)
------- ------- ------- ------- ------- ------- -------
Net income before
extraordinary item and
cumulative effect of
change in accounting
principle.............. 8,822 5,449 540 5,120 7,824 4,268 4,488
Extraordinary loss on
extinguishment of
debt................... -- -- -- -- (1,750) -- --
Cumulative effect of
change in accounting
for depreciation....... -- 877 -- -- -- -- --
------- ------- ------- ------- ------- ------- -------
Net income (3).......... $ 8,822 $ 6,326 $ 540 $ 5,120 $ 6,074 $ 4,268 $ 4,488
======= ======= ======= ======= ======= ======= =======
PRO FORMA INFORMATION
(UNAUDITED):
Historical income before
income taxes,
extraordinary item, and
cumulative effect of
change in accounting
principle.............. $ 8,822 $ 5,449 $ 540 $ 5,120 $ 7,824 $ 4,268 $ 4,488
Pro forma provision for
income taxes........... 3,336 2,060 228 1,424 2,937 1,667 1,670
------- ------- ------- ------- ------- ------- -------
Pro forma net income
(3).................... $ 5,486 $ 3,389 $ 312 $ 3,696 $ 4,887 $ 2,601 $ 2,818
======= ======= ======= ======= ======= ======= =======
Pro forma net income, as
adjusted (4)........... $ 5,204 $ 3,138
======= =======
Pro forma net income,
combined (5)........... $ 5,173 $ 3,096
======= =======
PRO FORMA PER COMMON
SHARE:
Pro forma net income.... $ 0.98 $ 0.61 $ 0.06 $ 0.65 $ 0.86 $ 0.46 $ 0.49
======= ======= ======= ======= ======= ======= =======
Pro forma weighted
average common shares
outstanding (6)........ 5,601 5,601 5,601 5,687 5,713 5,713 5,748
======= ======= ======= ======= ======= ======= =======
Pro forma net income, as
adjusted (7)........... $ 0.67 $ 0.39
======= =======
Pro forma net income,
combined (5)........... $ 0.67 $ 0.38
======= =======
Pro forma weighted
average shares
outstanding, as
adjusted (6)........... 7,716 8,148
======= =======
</TABLE>
21
<PAGE>
<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
-------------------------------------------- -----------------
1991 1992 1993 1994 1995 1995 1996
------- ------- ------- ------- -------- -------- -------
(IN THOUSANDS, EXCEPT SHARE DATA) (UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF CASH FLOWS
DATA:
Cash flows from
operating activities.. $ 7,912 $10,563 $ 2,217 $ 994 $ 5,436 $ 10,671 $10,945
Cash flows provided by
(used in) investing
activities............ $(6,787) $(7,246) $(6,917) $ 9,068 $(12,610) $ (5,212) $(2,569)
Cash flows provided by
(used in) financing
activities............ $(5,872) $ 34 $ (315) $(5,886) $ 2,467 $(10,514) $(8,471)
OTHER DATA:
NGL production
(gallons)............. 87,722 88,616 93,355 99,735 92,239 49,826 43,094
EBITDA (8)............. $11,186 $ 9,260 $ 3,500 $ 7,426 $ 9,930 $ 5,420 $ 6,280
Capital expenditures... $ 5,775 $ 5,695 $ 6,941 $ 1,442 $ 12,426 $ 5,297 $ 2,522
Partnership
distributions......... $ 5,102 $ 3,877 $ 3,040 $ 320 $ 4,150 $ 3,381 $ 3,219
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31, AS OF JUNE 30, 1996
---------------------------------- ------------------------------
PRO PRO FORMA, AS
1991 1992 1993 1994 1995 ACTUAL FORMA (9) ADJUSTED (10)
------ ------ ------ ------ ------ ------ --------- -------------
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash
equivalents........... $2,956 $6,307 $1,292 $5,468 $ 761 $ 666 $ 896 $ 281
Working capital........ 6,890 6,253 2,715 10,634 10,369 5,144 5,274 4,759
Total assets........... 32,684 41,092 40,668 35,913 46,896 43,991 44,321 43,606
Total debt............. 9,164 11,750 16,486 9,887 17,500 12,350 22,350 --
Total partners'
capital/stockholders'
equity................ 16,975 19,614 17,350 22,183 25,161 26,464 13,488 35,223
</TABLE>
- --------
(1) Represents the gain on the sale of a significant portion of the
Company's oil and gas producing assets for proceeds of approximately $10.1
million.
(2) Represents a $2.2 million write-down to estimated realizable value of an
isomerization unit that was shut down, a $347,000 charge relating to a
catalyst used in the isomerization process and a $361,000 charge for the
write-down of non-productive equipment related to various business development
projects.
(3) Net income for all periods presented includes no income tax effects
because the Company operated as a partnership (non-taxable entity) during
these periods. Pro forma net income is presented for purposes of comparability
assuming the Company was a taxable entity for all periods presented.
(4) Pro forma net income, as adjusted, reflects pro forma net income
adjusted for the reduction in interest expense resulting from the application
of a portion of the estimated proceeds of this Offering to repay average
indebtedness outstanding prior to the Offering. See "Use of Proceeds" and the
Unaudited Pro Forma Condensed Consolidated Financial Statements included
elsewhere in this Prospectus.
(5) Pro forma net income combined presents pro forma net income, as
adjusted, giving effect to the Basin acquisition. The amounts presented are
computed based on MarkWest Partnership's ownership interest in Basin as of
June 30, 1996 of 5.3%. MarkWest Partnership intends to acquire additional
ownership of Basin through capital expenditures through the end of 1997, at
which time it is expected the ownership interest will be 60%. If the 60%
ownership interest was used, the pro forma net income combined per common
share amounts would be $0.66 and $0.34 for the year ended December 31, 1995
and the six months ended June 30, 1996, respectively. See the Unaudited Pro
Forma Condensed Consolidated Financial Statements included elsewhere in this
Prospectus for detailed computations of the pro forma effects at both
ownership levels.
(6) See the Unaudited Pro Forma Condensed Consolidated Financial Statements
included elsewhere in this Prospectus.
(7) Pro forma net income, as adjusted, per common share is presented to give
effect to the issuance of the number of shares required for net proceeds to
repay indebtedness outstanding prior to the Offering, including the
indebtedness incurred to fund the Partnership Distribution. The amount is
computed by dividing pro forma net income, as adjusted, as described in (4)
above, by the total of the pro forma weighted average common shares
outstanding prior to the Offering plus the additional shares for which the net
proceeds will be used to repay the indebtedness.
(8) EBITDA represents earnings before interest income, interest expense,
income taxes, depreciation, depletion and amortization and gain on sale of oil
and gas properties, reduction in carrying value of assets and extraordinary
items. EBITDA, as defined by the Company, may not be comparable to similarly
titled measures used by other companies. EBITDA, which is not a measure under
generally accepted accounting purposes, is not intended to represent cash
flows for the period, nor has it been presented as an alternative to operating
income, or as an indicator of operating performance. It should not be
considered in isolation or as a substitute for measures of performance
prepared in accordance with generally accepted accounting principles. See the
Company's Consolidated Statements of Cash Flows in the Consolidated Financial
Statements included elsewhere in this Prospectus. The Company has included
EBITDA because it understands that such measure is used by certain investors
to determine the Company's ability to service its indebtedness. In addition,
the Company uses EBITDA to measure its performance against its industry peer
group. EBITDA should not be used as an indicator of the performance of the
Company's operating, investing or financing activities.
(9) Gives effect to the Reorganization, the accrual of $3.2 million of
deferred income tax liabilities and the Partnership Distribution. See
"Reorganization" and the Unaudited Pro Forma Condensed Consolidated Financial
Statements included elsewhere in this Prospectus.
(10) Further adjusted to reflect the sale of 2,400,000 shares of Common
Stock offered hereby and the application of the estimated net proceeds from
the Offering. See "Use of Proceeds."
22
<PAGE>
MANAGEMENT'S DISCUSSION 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, and should be read in
conjunction with the Company's Consolidated Financial Statements included
elsewhere in this Prospectus and "Selected Consolidated Financial and Other
Data."
GENERAL
MarkWest provides compression, gathering, treatment, processing and 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 and fractionation activities.
The majority of the Company's operating income is derived from gas
processing and NGL fractionation. NGL prices and the volume of liquids
extracted, fractionated, and sold are the primary determinants of revenues.
Prices of NGLs typically do not vary directly with natural gas prices, but
more closely follow the prices of crude oil.
The majority of the Company's NGL production is purchased under keep-whole
contracts. Keep-whole contracts accounted for approximately 70% of the
Company's total revenues during 1995 and approximately 58% of the Company's
total revenues during the six months ended June 1996. In keep-whole contracts,
the Company's principal cost is the reimbursement to the natural gas producers
for the energy extracted from the natural gas stream and consumed as fuel
during processing. Profitability under such contracts is largely influenced by
the margin between NGL sales prices and the cost of such reimbursement, which
is directly related to the Company's cost for natural gas. In the event there
is a contraction of the margin between the two prices, the Company's
profitability will decrease. See "Risk Factors--Commodity Price Risks."
The Company intends to emphasize fee-based processing in the future to
reduce the fluctuations in margins inherent in processing natural gas under
keep-whole arrangements. In 1995, the Company began construction of a new NGL
extraction facility in Kenova, West Virginia, which became operational in
January 1996. This facility provides services to Columbia Gas and other gas
producers in the Appalachian Core Area. Services provided by the Kenova plant
are based on a fee for volumes processed. The fee contracts related to the
Kenova plant are expected to help offset margin fluctuations in the keep-whole
contracts related to the Siloam fractionation plant. See "Business--Gas
Processing Contracts and Natural Gas Supply--Fee Contracts."
In recent years, a substantial majority of the gas received by the Company's
processing plants was received from major pipelines owned by third parties.
From time to time, such pipeline transmission systems have been partially shut
down for maintenance or repairs for up to four months. Partial or complete
shut downs of pipelines supplying the Company's processing plants could have a
material impact on the volumes of natural gas processed and on the volumes of
NGLs fractionated and sold, and correspondingly on the revenues realized by
the Company. See "Risk Factors--Availability of Natural Gas Supply" and "--
Dependence on Major Pipelines."
In addition to sales of NGLs processed by the Company, the Company generates
income from the purchase and resale of NGLs as part of its terminal and
marketing activities. The Company previously engaged in third party trading
and brokerage activities, which significantly increased revenue. Because of
minimal gross margins and significant operating costs related to the brokerage
and trading business, the Company discontinued brokerage and trading in mid-
1993. The Company continues to provide marketing activities in support of its
company-owned facilities and production and, with the acquisition of its
Church Hill facility in 1995, the Company currently operates two propane
terminals.
The Company plans to increase its investment in its new Michigan Core Area
and the Company's results of operations in the future should be increasingly
impacted by the operations in the Michigan Core Area. The
23
<PAGE>
Company's assets in the Michigan Core Area presently consist of the Basin
Pipeline and a number of processing contracts. In May 1996, the Company
entered into several related agreements providing for the further development
of gathering, treatment and processing facilities in western Michigan. The
Company also plans to invest in exploration and production activities in the
Michigan Core Area and has agreed to purchase a 17.5% working interest in the
drilling program of Callon Exploration Company. See "Business--Natural Gas
Processing and Related Services--Michigan Core Area." The operation of certain
assets acquired in the Michigan Core Area prior to their purchase by the
Company was not profitable. The Company's fiscal 1995 pro forma net income,
giving effect to the inclusion of Basin Pipeline with the Company, would have
been lower by $350,000. See the Unaudited Pro Forma Condensed Consolidated
Financial Statements included elsewhere in this Prospectus. While the Company
has entered into agreements that the Company believes will increase the
profitability of Basin Pipeline, there can be no assurance that such
operations will be profitable in the future or that the Company's planned
expansion efforts will be successful. See "Risk Factors--Risks Relating to the
Michigan Project."
The Company also plans to increase its investment in exploration and
production activities for new natural gas sources as a supporting function for
its processing services. Exploration and production activities are subject to
many risks, including the risk that no commercially productive reservoirs will
be encountered. There can be no assurance that its natural gas exploration
efforts will be productive or that the Company will recover all or a portion
of its investment in such activities. See "Risk Factors--Certain Risks of Oil
and Gas Exploration and Production Activities."
All statements other than statements of historical fact contained in this
Prospectus, including statements concerning the Company's financial position
and liquidity, results of operations, prospects for development of the
Appalachian Core Area and the Michigan Core Area, prospects for development of
exploration and production assets and other matters are forward looking
statements. Although the Company believes that the expectations reflected in
such forward looking statements are reasonable, no assurance can be given that
such expectations will prove correct. Factors that could cause the Company's
results to differ materially from the results discussed in such forward
looking statements include the risks described under "Risk Factors," such as
commodity price risks, risks involved in future supplies of natural gas,
dependence on major pipelines, general business risks in NGL marketing and
exploration and production activities, dependence on certain customers,
intense competition, regulatory and other risks in the natural gas processing
and related services industry. All forward looking statements in this
Prospectus are expressly qualified in their entirety by the cautionary
statements in this paragraph.
SEASONALITY
The Company's results of operations fluctuate from quarter to quarter, due
in large part to the impact of seasonal factors on the prices and sales
volumes of NGLs and natural gas. The Company's principal NGL product, propane,
is used primarily as home heating fuel in the Company's marketing areas. Sales
volume and prices of propane usually increase during the winter season and
decrease during the summer season. However, demand for, and prices of, propane
also depend, to a large extent, upon the severity of the weather in the
Company's operating areas during the winter months. To meet the needs of the
marketplace, the Company seasonally stores product to meet anticipated winter
demand and also increase its third party purchases to meet wintertime needs.
As a result, the Company recognizes the greatest proportion of its operating
income during the first and fourth quarters of the year. See "Risk Factors--
Potential Variability in Quarterly Operating Results."
RESULTS OF OPERATIONS
Six Months Ended June 30, 1996 Compared to Six Months Ended June 30, 1995
Revenues. Plant revenue increased to $18.0 million from $17.2 million for
the six months ended June 30, 1996 as compared to the six months ended June
30, 1995, an increase of $820,000 or 5%. The increase of $820,000 was due to a
$3.0 million price-related increase, offset by $2.2 million volume-related
decrease. The revenue increase resulted principally from $1.6 million in
additional revenue generated by the new Kenova
24
<PAGE>
processing plant during its first six months of operations, offset by a
decrease in volumes fractionated at the Siloam plant and NGLs sold to third
parties, and by higher selling prices per gallon for butanes and natural
gasoline. 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.
Terminal and marketing revenue increased to $9.8 million from $5.2 million
for the six months ended June 30, 1996 as compared to the six months ended June
30, 1995, an increase of $4.6 million, or 88%. The increase of $4.6 million was
due to a $2.9 million volume-related increase and a $1.7 million price-related
increase. Revenue from the West Memphis terminal accounted for $3.3 million of
the increase and the new terminal in Church Hill, Tennessee, which became
operational in the fall of 1995, accounted for $1.3 million of the increase.
The increase in revenues from the West Memphis terminal was due principally to
colder temperatures during January and February 1996 in the geographic areas
served by this terminal, resulting in an increased demand for propane.
Oil and gas and other revenue increased to $744,000 from $501,000 for the six
months ended June 30, 1996 as compared to the six months ended June 30, 1995,
an increase of $243,000, or 49%. This increase was due principally to a full
year of production from the Company's current complement of oil and gas
properties, which began producing in the fourth quarter of 1995. Other revenue
consists of income received from the leasing of Company-owned railcars to third
parties.
Costs and expenses. Terminal and marketing purchases increased to $8.7
million from $4.8 million for the six months ended June 30, 1996 as compared to
the six months ended June 30, 1995, an increase of $3.9 million, or 81%.
Increased product costs resulted from increased propane sales.
Operating expenses increased to $3.0 million from $2.0 million for the six
months ended June 30, 1996 as compared to the six months ended June 30, 1995,
an increase of $1.0 million, or 49%. The increase was due principally to new
operations at both the Kenova and Church Hill facilities, which commenced
operations in the first quarter of 1996 and the fourth quarter of 1995,
respectively.
Depreciation and amortization increased to $1.3 million from $852,000 for the
six months ended June 30, 1996 as compared to the six months ended June 30,
1995, an increase of $501,000 or 59%. The increase was due principally to
depreciation attributable to the Company's new Kenova plant.
Net interest expense. Net interest expense increased to $466,000 from
$300,000 for the six months ended June 30, 1996 as compared to the six months
ended June 30, 1995, an increase of $166,000 or 55%. This increase resulted
principally from an increase in outstanding long-term debt to $12.4 million at
June 30, 1996, from $3.8 million at June 30, 1995, offset by a decrease in
interest rates from 8.125% to 7.50%, in order to finance the Kenova plant.
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
1995 as compared to 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 1995 as compared to 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 in
1995 as compared to 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.
25
<PAGE>
Costs and expenses. Plant feedstock purchases decreased to $17.3 million
from $21.6 million for 1995 as compared to 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 1995 as compared to 1994, an increase of $440,000 or 4%. This
increase was due principally to an increase in the average price per gallon of
propane.
Operating expenses increased to $4.7 million from $4.4 million for 1995 as
compared to 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 1995 as compared to 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 $1.7 million from $1.9 million
for 1995 as compared to 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 $352,000 from $1.7
million for 1995 as compared to 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.
Year Ended December 31, 1994 Compared to Year Ended December 31, 1993
Revenues. Plant revenues decreased to $33.1 million from $34.2 million for
1994 as compared to 1993, a decrease of $1.1 million or 3%. This decrease
resulted principally from a $1.8 million increase due to additional volumes
sold, offset by a $2.9 million decrease due to lower average NGL sales prices.
Terminal and marketing revenue decreased to $13.7 million from $19.8 million
for 1994 as compared to 1993, a decrease of $6.1 million or 31%. This decrease
resulted principally from the Company's discontinuation of its third-party
brokerage operations which is reflected in the $6.5 million volume-related
decrease, offset by an increase of $443,000 related to price.
Costs and expenses. Plant feedstock purchases decreased to $21.6 million
from $23.2 million for 1994 as compared to 1993, a decrease of $1.6 million or
7%. This decrease was attributable to the Company's initiation in 1994 of the
practice of acquiring feedstock quantities at off-peak periods, when prices
are typically lower.
Terminal and marketing purchases decreased to $11.5 million from $18.8
million for 1994 as compared to 1993, a decrease of $7.3 million or 39%. This
decrease resulted principally from the Company's discontinuation of its third
party brokerage operations.
Operating expenses decreased to $4.4 million from $6.5 million for 1994 as
compared to 1993, a decrease of $2.1 million or 32%. This decrease resulted
from a cost containment policy implemented in fiscal 1994. The aggregate
reduction in operating expenses consisted primarily of reduced transportation
expense related to third-party brokerage operations, lower operating expenses
related to the shutdown of the Siloam isomerization plant during 1994, and
reduced repair and maintenance expense.
Depreciation and amortization increased to $1.9 million from $1.6 million
for 1994 as compared to 1993, an increase of $377,000 or 24%. The increase was
primarily due to the acquisition of certain assets, including a new computer
system, with shorter depreciable lives.
26
<PAGE>
Net interest expense. Net interest expense increased to $1.7 million from
$1.4 million for 1994 as compared to 1993, an increase of $294,000 or 21%. The
increase resulted from higher average borrowing levels of approximately $13.0
million in 1993 to $16.0 million in 1994, and an increase in interest rates.
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 and, in 1994, the proceeds from the sale of certain oil and gas
properties. 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, 1993, 1994 and 1995 and the six months ended
June 30, 1995 and 1996:
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
-------------------------- -----------------
1993 1994 1995 1995 1996
------- ------- -------- -------- -------
(IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Net cash provided by operating
activities.................... $ 2,217 $ 994 $ 5,436 $ 10,671 $10,945
Net cash provided by (used in)
investing activities.......... $(6,917) $ 9,068 $(12,610) $ (5,212) $(2,569)
Net cash provided by (used in)
financing activities.......... $ (315) $(5,886) $ 2,467 $(10,514) $(8,471)
</TABLE>
For the six months ended June 30, 1996, net cash provided by operating
activities increased by $274,000 over the six months ended June 30, 1995. This
increase resulted primarily from an increase in revenue of $5.7 million, which
was offset by a $4.8 million increase in feedstock purchases, operating
expenses and general and administrative expenses. Cash flows from operations
was further reduced by an increase in working capital requirements. At
December 31, 1995, accounts receivable increased while revenues decreased due
to a short-term, non-revenue generating advance of $3.1 million to affiliates
of MEC, the Company's partner in West Shore. Accounts payable increased while
costs and expenses decreased due to the timing of the payments for prepaid
feedstock.
Cash used in investing activities decreased $2.6 million for the period
ending June 30, 1996, as compared to the period ending June 30, 1995, due to
the completion of the Kenova facility under construction the prior year. Cash
used in investing activities in 1995 was principally due to the expenditures
resulting from the construction of the Kenova facility. Cash provided from
investing activities in 1994 was principally due to the proceeds from the sale
of the Company's San Juan Basin coalbed methane properties and associated
gathering systems. Cash used in investing activities in 1993 was principally
due to the increased expenditures related to developing the San Juan Basin
coalbed methane properties.
Financing activities during the six months ended June 30, 1995 and 1996
principally consisted of payments on long-term debt. Cash provided by
financing activities in 1995 was principally due to the increase in borrowing
levels at the end of the year to finance construction of the Kenova facility.
Cash used in financing activities in 1994 resulted from the pay-down of long-
term debt under the Company's credit facility.
The Company believes that the net proceeds from this Offering, together with
its current credit facilities and cash flows generated by its operations, will
be sufficient to meet its anticipated cash needs for working capital and
capital expenditures for at least the next twelve months. Thereafter, if cash
generated from operations is insufficient to satisfy the Company's liquidity
requirements, the Company may seek to sell additional equity or debt
securities, obtain additional credit facilities or adjust the level of its
operating and capital expenditures. The sale of additional equity securities
could result in additional dilution to the Company's stockholders.
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 and N M Rothschild and Sons Limited (collectively, the "Lenders").
The agreement is structured as a revolving facility, with a maximum borrowing
base of $40.0 million as of June 30, 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,
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<PAGE>
1998, continuing for 16 equal quarterly installments until June 30, 2002.
Outstanding borrowings at June 30, 1996 were $8.5 million. Upon application of
the net proceeds of the Offering, no amounts will be outstanding under this
facility. 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 June 30, 1996. Interest rates
are based on prime plus 1/4%, with maturity on July 1, 1998. Outstanding
borrowings at June 30, 1996 were $3.9 million. Upon application of the net
proceeds of the Offering, no amounts will be outstanding under this facility.
The working capital loan is secured by the Company's inventory, receivables
and cash.
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 new worth, current ratio, ratio of funded
debt to total capitalization and fixed charge coverage ratio.
Capital Investment Program
During 1996, the Company expects to make approximately $10.0 million in
capital investments. The Company expects to invest approximately $4.0 million
in the Company's subsidiary, MW Michigan, Inc. ("MW Michigan"), for activities
in the Michigan Core Area. Through MW Michigan, the Company is committed to
make certain capital contributions to West Shore, a venture dedicated to
natural gas gathering, treatment, processing and NGL marketing in western
Michigan. The Company has committed to fund up to $1.2 million of West Shore's
construction of a two-mile gathering pipeline and up to $10.0 million for a
30-mile extension of the Basin Pipeline. In addition, the Company has
committed to fund 60% of the costs in excess of such amounts if necessary to
complete these projects. See "Business--Natural Gas Processing and Related
Services--Michigan Core Area." The Company also expects to invest
approximately $5.0 million in the Company's exploration and production
subsidiary, MarkWest Resources, Inc. ("MarkWest Resources"). For the six
months ended June 30, 1996, the Company made capital expenditures totalling
$2.5 million, including $629,000 for MW Michigan and $1.4 million for MarkWest
Resources.
As of June 30, 1996, the Company had expended $12.2 million and $213,000 in
connection with the construction and related costs for development of the
Kenova plant and the Church Hill terminal and storage facility, respectively.
The Company expects to expend an additional $280,000 to expand the Church Hill
facility in 1996.
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 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 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, 1994 and 1995, and as of June 30, 1996, the Company did
not hold any material notional quantities of natural gas, NGL, or crude oil
futures, swaps or options.
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<PAGE>
TERMINATION OF PARTNERSHIP TAX STATUS
The Company's immediate predecessor, MarkWest Partnership, will remain a
partnership until its reorganization immediately prior to consummation of the
Offering. As such, MarkWest partnership was not subject to federal and most
state income tax and its income was taxed directly to its respective partners.
The financial data set forth in this Prospectus reflect pro forma income tax
provisions as if the Company had been taxed as a Subchapter C corporation
under the Internal Revenue Code during the relevant periods. Pro forma income
taxes giving effect to termination of MarkWest Partnership's tax status were
calculated using an effective income tax rate of approximately 42.3%, 27.8%,
37.5% and 37.2% in 1993, 1994, 1995 and for the first six months of 1996,
respectively. See Note 10 of Notes to Consolidated Financial Statements.
29
<PAGE>
BUSINESS
GENERAL
The Company 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, according to statistics
compiled by LPG Almanac, an independent natural gas data source, 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 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. In the twelve months ended December 31, 1995,
MarkWest produced approximately 92 million gallons of NGLs and marketed
approximately 127 million gallons of NGLs.
The Company's processing and marketing operations are concentrated in two
core areas which 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 has taken several key steps intended to expand its
operations. In January 1996, the Company commissioned a new natural gas
liquids extraction plant in Wayne County, West Virginia. See "--Natural Gas
Processing and Related Services--Appalachian Core Area--NGL Extraction--Kenova
Plant." In May 1996, the Company established 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--Michigan Core Area."
INDUSTRY OVERVIEW
Natural gas processing and related services represent a major segment of the
oil and gas industry, providing the necessary service of converting natural
gas into marketable energy products. When natural gas is produced at the
wellhead, it must be gathered, and in some cases compressed or pressurized,
for transportation via pipelines (described as gathering services) to gas
processing plants. The processing plants remove water vapor, solids and other
contaminants, such as hydrogen sulfide or carbon dioxide in the natural gas
stream that would interfere with pipeline transportation or marketing of the
gas to consumers and also extract the NGLs from the natural gas (described as
treatment and extraction services, respectively). The NGLs are then subjected
to various processes that cause the NGLs to separate, or fractionate, into
marketable products such as propane, normal butane, isobutane and natural
gasoline (described as fractionation services).
Over the past 10 years, independent gas processing has experienced
significant growth. In 1995, independent natural gas processing companies
accounted for 319,000 barrels per day of NGL production, or approximately 23%
of total U.S. NGL production by the 20 largest U.S. natural gas producers,
compared to less than 4% of such producers' NGL production in 1985. The
increase in the independent gas processing industry has resulted in part from
the divestiture by major energy companies and interstate pipeline companies of
their gas gathering and processing assets and the decision by many such
companies to outsource their gas processing needs.
30
<PAGE>
An important factor expected to contribute to the continuing growth of
independent processing companies is the upward trend of gas consumption and
production in the United States. Natural gas consumption in the United States
has increased from 16.2 Tcf per year in 1986 to 21.3 Tcf per year in 1995, and
is forecast to increase to 24.0 Tcf per year by the year 2000. The number of
natural gas rigs in service also has recently increased. From June 1995 to
June 1996, the number of natural gas rigs in service rose from 340 to 464.
This natural gas rig count is the highest in over four years, and as a
percentage of total oil and gas rigs in service, the highest in the last
decade. Many newly discovered gas wells and gas fields will require access to
gathering and processing infrastructure, providing significant opportunities
for growth-oriented independent gas processing companies such as MarkWest.
STRATEGY
The Company's primary objective is to achieve sustainable growth in cash
flow and earnings by increasing the volume of natural gas that it gathers and
processes and the volume of NGLs that it produces and markets. To achieve this
objective, the Company employs a number of related strategies.
Geographic Core Areas. The Company emphasizes opportunities for investment
in geographic core areas where there is significant potential to achieve a
position as the area's dominant natural gas processor. The Company believes
that growth in core areas can be achieved by developing processing facilities
both in areas where a large energy or pipeline company requires processing
services and in areas where there is significant potential for natural gas
production but not significant processing capacity.
Long-Term Strategic Relationships. The Company seeks strategic relationships
with the dominant pipelines and gas producers in each area in which the
Company operates. In the Appalachian Core Area, MarkWest owns three processing
plants that process natural gas or NGLs dedicated by Columbia Gas. In its
Michigan Core Area, the Company has entered into gas supply and processing
relationships with Shell and MPC, a company jointly owned by Tenneco and
ENCAP.
NGL Marketing. The Company strives to maximize the downstream value of its
gas and liquid products by marketing directly to distributors and resellers.
Particularly in the area of NGL marketing, the Company minimizes the use of
third party brokers and instead supports a direct marketing staff focused on
refiners, petrochemical companies, gasoline blenders, and multistate and
independent propane dealers. Additionally, the Company uses its own truck and
tank car fleet, as well as its own terminals and storage facilities, to
provide supply reliability to its customers. All of these efforts have allowed
the Company to maintain pricing of its NGL products at a premium to Gulf Coast
spot prices.
Cost-Efficient Operations. The Company seeks a competitive advantage by
utilizing in-house processing and operating expertise to provide lower-cost
service. To provide competitive processing services, the Company emphasizes
facility design, project management and operating expertise that permits
efficient installation and operation of its facilities. The Company has in-
house engineering personnel who oversee the design and construction of the
Company's processing plants and equipment.
Acquisitions. The Company believes that there are significant opportunities
to make strategic acquisitions of gathering and processing assets because of
the divestiture by major energy companies and interstate pipeline companies of
their gas gathering and processing assets. The Company pursues acquisitions
that can add to existing core area investments or can lead to new core area
investments.
Exploration as a Tool to Enhance Gas Processing. The Company maintains a
strategic gas exploration effort that is designed to permit the Company to
gain access to additional natural gas supplies within its existing core areas
and to gain foothold positions in production regions that the Company might
develop as new core processing areas.
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<PAGE>
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.
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, when the Company purchased its Siloam fractionation plant
(see
"--Fractionation"), 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.
[GRAPHIC: 43 X 33 1/2 PICA MAP OF APPALACHIAN CORE AREA]
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
32
<PAGE>
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
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 Siloam 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 in the region that are not currently processed.
For example, in 1994 in Kentucky, Ohio, Pennsylvania, Virginia and West
Virginia, only 473 MMcf/D of natural gas was processed out of a total
production of over 1,400 MMcf/D. While not all of this natural gas is
available to the Company or is economically feasible to process, the Company
believes there is significant opportunity to capture an increasing portion of
this unprocessed supply.
NGL EXTRACTION. The Company currently owns two NGL extraction plants in
Appalachia, one which it operates and one which it leases to 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, the Company will generate increased revenue, and
fee revenues related to processing operations will represent a greater
proportion of total revenues. 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. The Kenova plant was constructed under an
agreement with Columbia Gas and is situated on a main gathering line of
Columbia Gas. The Kenova plant produces revenue for the Company by charging
fees to process natural gas production. To date, substantially all of Kenova's
processing throughput has been obtained from Columbia Gas. See "--Gas
Processing Contracts and Natural Gas Supply." The Company estimates that
average natural gas throughput at the Kenova plant in 1996 will be 115 MMcf/D.
NGL production at the Kenova plant in 1996 is estimated to be 70 million
gallons.
The Kenova plant is a turbo expander plant that both processes natural gas
into pipeline quality gas and extracts NGLs from the natural gas stream. The
Kenova plant refrigerates natural gas down to -105 degrees Fahrenheit and
separates the natural gas from the NGLs formed at the low temperatures. The
Kenova plant's design allows for relatively fuel-efficient, low-pollution
extraction of a high volume of NGLs from the natural gas. The plant has a
processing capacity of 120 MMcf/D, and also has over 6,500 horsepower of inlet
compression capability. See "--Facilities." 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.
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<PAGE>
The Boldman plant is a refrigeration plant that extracts NGLs by
refrigerating natural gas down to -20 degrees Fahrenheit. The plant has a
processing capacity of 70 MMcf/D and includes two 60,000 gallon product
storage tanks and truck loading facilities. 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. See "--Facilities."
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. Natural gas
throughput at the Boldman plant in 1995 averaged 55 MMcf/D.
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. See "--
Gas Processing Contracts and Natural Gas Supply--Keep-Whole Contracts."
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 that included the construction of an
isomerization unit that has the capacity to convert up to 2,000 barrels per
day of normal butane into isobutane. Because of attractive normal butane
prices, the Company does not currently operate the isomerization unit. The
expansion program also 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. The Siloam plant, situated on approximately 290 Company-owned acres, has
a gross design capacity of 8,500 barrels per day, or approximately 130 million
gallons per year. The Siloam plant 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.
Approximately 79% 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. The terms of these contracts runs
through December 31, 2003, except for the contract at the Kenova plant which
runs through 2010, and provide for automatic two-year extensions thereafter,
unless either party gives notice to terminate the contract at least one year
in advance of an expiration date. In 1995, the Company's cost for purchases
under these contracts were $17.0 million, and such purchases represented 98%
of all NGLs fractionated by the Company.
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<PAGE>
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. Through West Shore, the Company expects to be
able to gather and process this sour gas. 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. The Michigan Project is conducted through West Shore, a venture
dedicated to natural gas gathering, treatment, processing and NGL marketing in
Manistee, Mason and Oceana Counties in Michigan. MW Michigan has the
contractual right to acquire a 60% interest in West Shore. See "--Development
Agreements."
[GRAPHIC: MAP OF MICHIGAN CORE AREA]
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.
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<PAGE>
The Michigan Project is in 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 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. Pending approval by the Michigan Public Service Commission of this
pipeline as part of the Basin Pipeline, MPC will own, and West Shore will
operate for MPC, this connecting pipeline. The Slocum well has estimated
reserves of approximately 13 Bcf, and estimated initial well deliverabilities
of approximately 8 MMcf/D. The Company currently expects to complete the first
phase of the Michigan Project in the first quarter of 1997. The first phase of
the Michigan Project is budgeted to cost $10.4 million, of which the Company's
share is $9.5 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 over $10.0 million, although the budget for such project is
not yet finalized.
Upon completion of the first two phases of development, West Shore's
processing operations are expected to have 30 MMcf/D of capacity provided by
Shell 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 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
Callon 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 Callon are considering initiating
drilling programs in the area, to begin in late 1996 or early 1997. Production
from the MPC program has been dedicated to the Basin Pipeline, and West Shore
is negotiating with Callon for dedication of its production to the Basin
Pipeline. MarkWest Resources has agreed to purchase a 17.5% working interest
in the Callon 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.
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,
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<PAGE>
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 sucess rates.
Development Agreements. West Shore was formed in May 1996 and is governed by
an operating agreement between MW Michigan, Inc. and MEC, which is owned by
Tenneco and ENCAP.
Pursuant to the West Shore operating agreement, MEC contributed various
gathering and processing assets, including gas purchase and processing
contracts, valued by MEC and the Company at $11.2 million. The most
significant assets contributed by MEC include its ownership interest in the
Basin Pipeline, which is now held by West Shore's Basin Pipeline LLC
subsidiary, 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.
The acquisition of construction and operating permits in Michigan
historically has been very difficult, particularly for sour gas. The assets
contributed by MEC to West Shore included two key permits: a certificate of
approval from the State of Michigan to transport sour natural gas via the
Basin Pipeline and a permit to construct an additional treatment plant in
Oceana County.
In addition to acting as the operator under the West Shore operating
agreement, the Company has committed to fund up to $1.2 million of West
Shore's construction of a two-mile gathering pipeline and up to $10.0 million
for a 30-mile extension of the Basin Pipeline. In addition, the Company has
committed to fund 60% of the costs in excess of such amounts if necessary to
complete these projects. The Company also intends to construct and install
processing and fractionating facilities to capitalize on the shut-in supply of
natural gas streams in the area. If the Company proceeds with this project,
the Company would pay 100% of such costs up to $5.6 million, and fund 60% of
the costs in excess of such amount if necessary to complete this project.
The Company's ownership interest in West Shore is based upon the
proportionate amount of capital funded to West Shore by the Company relative
to the overall capital of West Shore, up to a maximum ownership interest of
60%. When the first two phases of the Michigan Project are complete, and
assuming the Company has contributed capital of at least $16.8 million, the
Company will own a 60% interest in West Shore. If the Company has not funded
at least $16.8 million to West Shore prior to July 1, 1997, the Company has
the right to make capital contributions to West Shore in the amount of the
difference to obtain a 60% ownership interest. As of June 30, 1996, the
Company had contributed $629,000 to, and had a 5.3% interest in, West Shore.
Historically, Basin Pipeline's operations have not been profitable. Although
there can be no assurance that West Shore or Basin Pipeline will achieve
profitability, the Company believes that, with the capital contributions
committed by the Company, operational efficiencies will improve and the
throughput volume of the Basin Pipeline will increase as a result of the
connection of the Slocum, the Claybanks and additional natural gas wells to
the pipeline.
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. An increasing portion of
the Company's revenue is derived from fees charged for processing
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<PAGE>
third-party natural gas production. The Company intends to emphasize fee-based
processing 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. Keep-whole contracts accounted for approximately 70% of the Company's
total revenues during 1995, and approximately 58% of the Company's total
revenues during the six months ended June 30, 1996. See "Risk Factors--
Commodity Price Risks."
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 1995, deliveries by Columbia Gas to the Kenova
plant under this contract represented approximately 70% 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 the six months ended June 30, 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, 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' 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 93%, 98% and 92% of total
revenues, excluding gains on sale of property, in each of 1994, 1995 and in
the first six months of 1996, respectively. The Company markets and sells NGLs
to numerous customers, including refiners, petrochemical companies, gasoline
blenders, multistate and independent propane
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<PAGE>
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.
Marketing Assets. The Company maintains various terminalling, storage and
transportation assets designed to facilitate NGL sales and to take advantage
of seasonal variations in NGL prices.
In early 1992, the Company acquired a seven-acre propane terminal and
storage facility in West Memphis, Arkansas for approximately $4.5 million. The
West Memphis terminal is located at the terminus of an 80-mile intrastate
pipeline from McCrae Junction, Arkansas. The McCrae Junction terminal is
connected to the large interstate TEPPCO pipeline that originates in Mt.
Belvieu, Texas. At the West Memphis terminal, the Company maintains 45
pressurized storage tanks which have a storage capacity of just over 2.5
million gallons of NGLs. The terminal has a key stop 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 six 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.
The West Memphis terminal is supplied by product from three sources: the
TEPPCO pipeline, the Union Pacific railroad siding, and truck unloading. The
facility also has the capability to terminal other NGLs (butanes) during non-
peak demand periods for propane, and has dehydration facilities to ensure
minimal water contamination. During 1995, throughput at the West Memphis
terminal was approximately 30.0 million gallons. The Company's profit margin
on such throughput results from transportation, storage and handling services
to customers, which include approximately 45 area propane dealers.
The Company also 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 was
commissioned in the fall of 1995. The Company has agreed to maintain not less
than 60,000 gallons of propane in storage at the terminal during the period
from September 15 through March 15 of each year for use by Hawkins County
Utility Co. ("Hawkins"). Hawkins uses the facility for a retail propane
operation and a standby natural gas peak shaving plant, which mixes air with
propane to generate marketable natural gas. 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. Given
the relatively strong demand for NGL products, the Company expects to make
further investment in storage and loading/unloading assets of as much as
$280,000 in the last quarter of 1996.
To reach transportation and sales delivery points, the Company operates a
fleet of approximately 80 pressurized railcars. The Company owns 70 of the
railcars and leases the balance of the railcars under term leases. The Company
also owns seven pressurized truck transport trailers, which are principally
used in either the movement of mixed NGL feedstock to the Siloam fractionator
or the sale of propane in the Appalachian Core Area. The Company anticipates
increasing its owned railcar fleet prior to the end of 1997 and has budgeted a
total of $753,000 for such purpose.
The Company maintains a marketing staff of six persons in Columbus, Ohio;
West Memphis, Arkansas; and Denver, Colorado.
Sales Contracts. The Company has three significant contracts for sales of
NGLs. The Company entered into two contracts, which expired August 31, 1996,
with Ashland pursuant to which Ashland agreed to purchase all of the normal
butane produced by the Company during each calendar year the contracts were in
effect. The Company has completed negotiations with Ashland for two new
contracts that the Company anticipates to execute by the end of September
1996, effective for a new three year term commencing September 1, 1996. The
new contracts provide that Ashland will purchase the total production of
normal butane and isobutane produced at the Company's Siloam plant. The
Company currently is operating under the terms of the new contracts. In 1995,
butanes represented approximately
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24% of all NGLs produced by the Company. In 1995, Ashland purchased
approximately 21 million gallons of butanes out of a total of 92 million
gallons of NGLs produced at the Siloam plant. Sales prices for product sold to
Ashland are based upon monthly average spot market prices. In 1995, revenues
derived from NGL sales to Ashland represented $8.4 million, or approximately
18% of the Company's total revenues. The Company expects that its contract with
Ashland will be renewed prior to the expiration of its current term in August
1996, although there can be no assurance that such renewal will occur or will
occur on terms similar to the current contract.
The Company also has a significant sales contract with Ferrellgas pursuant to
which Ferrellgas has agreed to purchase approximately 12 million gallons of the
Company's annual propane production from its Siloam plant. The contract expires
in April 1997. The Company has had its contract with Ferrellgas renewed each
year since 1989. As such, the Company expects its contract with Ferrellgas to
be renewed subsequent to April 1997, although there can be no assurance that
such renewal will occur or will occur on terms similar to the current contract.
Sales prices for propane sold to Ferrellgas are based upon monthly average
market prices. In 1995, revenues derived from NGL sales to Ferrellgas
represented $3.8 million, or approximately 8% of the Company's total revenues.
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
its MarkWest Resources subsidiary, 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 three coal seam
wells that each produce approximately 300 Mcf/D of natural gas. MarkWest
Resources plans to commence a 12 well drilling program in the West
Tiffany area of the San Juan basin in September 1996. 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, Nevada, Kansas 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 natural gas in an area known as Sulfur Gulch and the purchase of
acreage and a number of existing wells. 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 Callon in the
Michigan Core Area. Callon intends to conduct a 25 square mile three-
dimensional seismic survey in the area, and thereafter acquire acreage
and conduct drilling activities. See "--Natural Gas Processing and
Related Services--Michigan Core Area."
In an attempt to mitigate certain of the risks involved in such activities,
the Company has conducted its exploration and production activities with third
parties. To date, the Company's exploration and production efforts have been
conducted jointly with MAK-J Energy, a partnership whose general partner is a
corporation owned and controlled by John Fox, President and Chief Executive
Officer of the Company. See "Certain Transactions--Investments with Affiliate."
In the future, any activities involving MAK-J Energy are required by the
Company's bylaws to be approved by a majority of the Company's independent and
disinterested directors. See "Certain Transactions--Investments with
Affiliate."
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<PAGE>
FACILITIES
The following table provides information concerning the Company's principal
gas processing plants and gathering facilities.
<TABLE>
<CAPTION>
YEAR ACQUIRED GAS NGL PRODUCTION
OR PLACED THROUGHPUT THROUGHPUT THROUGHPUT
INTO SERVICE CAPACITY (MMCF/D)(1) (MGAL/YEAR)(1)
------------- ------------ ----------- --------------
<S> <C> <C> <C> <C>
PROCESSING PLANTS
Siloam Fractionation
Plant,
South Shore, KY......... 1988 360 MGal/D N/A 100,000
Boldman Extraction
Plant,
Pike County, KY......... 1991 70.0 MMcf/D 55.0 9,300
Kenova Extraction Plant,
Wayne County, WV........ 1996 120.0 MMcf/D 115.0 70,000
PIPELINES
38.5-mile Kenova--Siloam
NGL pipeline,
Wayne County, WV to
South Shore, KY......... 1988 350 MGal/D N/A 70,000
31-mile sour gas pipe-
line
Manistee County, MI(2).. 1996 35.0 MMcf/D 9.0 N/A
</TABLE>
<TABLE>
<CAPTION>
YEAR ACQUIRED
OR PLACED STORAGE ANNUAL SALES
INTO SERVICE CAPACITY (MGAL/YEAR)(1)
------------- ----------- --------------
<S> <C> <C> <C>
TERMINAL AND STORAGE
Siloam Fractionation Storage
South Shore, KY........................ 1988 14,000 MGal 100,000
Terminal and Storage
West Memphis, AR....................... 1992 2,500 MGal 33,000
Terminal and Storage
Church Hill, TN........................ 1995 240 MGal 5,000
</TABLE>
- --------
(1) Estimated for 1996.
(2) Owned through West Shore Processing Company, LLC. See "--Natural Gas
Processing and Related Services--Michigan Core Area."
Kenova Plant. The Company's Kenova, West Virginia processing plant was
developed pursuant to certain agreements with Columbia Gas. Pursuant to
purchase and related agreements entered into between the Company and Columbia
Gas in March 1995, the Company has agreed to purchase approximately six acres
of land and facilities constituting Columbia Gas' former natural gas
processing plant located in Kenova, West Virginia, for $500,000. Under the
agreements, Columbia Gas has agreed to indemnify the Company for all
environmental liabilities and costs identified by the environmental assessment
of the Kenova properties, provided that, upon completion of the remediation
identified in the remediation plan, the Company has agreed to pay Columbia Gas
an additional $600,000 as a contribution for performing the remediation. The
Kenova plant currently is the subject of certain FERC abandonment proceedings.
See "--Government Regulation."
Boldman Plant. The Company's Boldman, Kentucky processing plant was
constructed pursuant to an agreement with Columbia Gas. The contract provided
that the Company would design and construct an NGL extraction plant on
Columbia Gas property. The Company invested approximately $4.0 million in
constructing
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the facility. Under the Company's agreement with Columbia Gas, the Company has
leased the facility to Columbia Gas for a ten year term ending February 2001.
The lease has a base monthly rental fee of $40,000 and an operating fee
measured by monthly production of liquids at the plant, which typically
results in a monthly rental ranging from $40,000 to $47,000. The lease also
contains a bonus fee arrangement pursuant to which the Company has agreed to
pay fees to Columbia Gas if NGL production at the plant exceeds certain
specified levels. The term is subject to an additional two-year extension upon
notice from Columbia Gas to the Company, subject to negotiation of acceptable
lease terms. Columbia Gas has the option, at the end of 1996, 1997, 1998 and
1999, to purchase the Boldman plant from the Company for a price equal to a
specified premium above the book value of the plant on the date of purchase.
In addition, Columbia Gas has the option to purchase the plant at the salvage
value of the plant upon expiration of the lease term. While the Company does
not expect that Columbia Gas will exercise its repurchase option, and
anticipates that it will negotiate an agreement with Columbia Gas by which the
Company will operate the plant on Columbia Gas' property after expiration of
the lease term, there can be no assurance that such results will be achieved.
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.
OPERATIONAL RISKS AND INSURANCE
The Company's operations are subject to the usual hazards incident to the
exploration for and production, transmission, processing and storage of
natural gas and NGLs, such as explosions, product spills, leaks, emissions and
fires. These hazards can cause personal injury and loss of life, severe damage
to and destruction of property and equipment, and pollution or other
environmental damage, and may result in curtailment or suspension of
operations at the affected facility. In addition, the Company's operations in
the Michigan Core Area are subject to additional risks resulting from the
processing and treatment of sour gas, including an increased risk of property
damage, bodily injury or death from the highly toxic nature of sour gas. See
"Risk Factors--General Business Risks."
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.
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.
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<PAGE>
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.
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 effect, 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' certificated facilities. See "--Natural Gas Processing and
Related Services--Appalachian Core Area--NGL Extraction" and "--Facilities."
Certain third party producers have filed for intervention in the abandonment
proceeding seeking to clarify commitments regarding dedication of production
and a determination regarding processing fees. 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" 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
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<PAGE>
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. For example, the Basin Pipeline, part of the Company's
Michigan Project, is regulated by the Michigan Public Service Commission and
local authorization is required for the connection of certain gas wells to the
Basin Pipeline. See "--Natural Gas Processing and Related Services--Michigan
Core Area."
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 NGL's will be transported
and sold in the marketplace. In its current form, FERC's open access
initiatives could provide the Company with additional access to gas supplies
and markets, and could assist the Company and its customers by mandating more
fairly applied service rates, terms and conditions. On the other hand, it
could also subject the Company and entities with which it does business to
more restrictive pipeline imbalance tolerances, more complex operations and
greater monetary penalties for violation of the pipelines tolerances and other
tariff provisions.
44
<PAGE>
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 July 1, 1996, the Company had 84 employees, including eight employees
dedicated to the Michigan Project. The Company anticipates hiring additional
employees in connection with the development of the Michigan Project.
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, non-supervisory employees. The Company considers labor relations to be
satisfactory at this time.
LEGAL PROCEEDINGS
From time to time the Company has been involved in certain legal proceedings
that have arisen in the ordinary course of business, none of which has had a
material adverse effect on the Company's financial position or results of
operations. 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.
45
<PAGE>
MANAGEMENT
EXECUTIVE OFFICERS AND DIRECTORS
The executive officers and directors of the Company are as follows:
<TABLE>
<CAPTION>
NAME AGE POSITION
- ---- --- --------
<S> <C> <C>
John M. Fox................ 56 President, Chief Executive Officer and Director
Brian T. O'Neill........... 48 Senior Vice President, Chief Operating Officer
and Director
Arthur J. Denney........... 47 Vice President of Engineering and Business
Development and Director
Robert F. Garvin........... 56 Vice President of Exploration
Rita E. Harvey............. 40 Director of Finance and Treasurer
Norman H. Foster (1)(2).... 61 Director
Barry W. Spector (2)....... 44 Director
David R. Whitney (1)(2).... 44 Director
</TABLE>
KEY EMPLOYEES
Certain key employees of the Company are as follows:
<TABLE>
<CAPTION>
NAME AGE POSITION
- ---- --- --------
<S> <C> <C>
Katherine S. Holland................. 43 Manager, NGL and Natural Gas Supply
Michael R. La Rue.................... 37 Manager, Business Development
Kimberly H. Marle.................... 38 Manager , Information Systems
Faye E. McGuar....................... 45 Controller
Randy S. Nickerson................... 35 Manager, West Shore and Basin Pipeline
Joseph D. O'Meara.................... 52 Manager, Appalachian Area
Fred R. Shato........................ 48 General Manager, Marketing
</TABLE>
- --------
(1) Member of the Compensation Committee of the Board of Directors.
(2) Member of the Audit Committee of the Board of Directors.
EXECUTIVE OFFICERS AND DIRECTORS
JOHN M. FOX has been the Company's President, Chief Executive Officer and a
member of the Board of Directors since its inception in April 1988. Mr. Fox
was a founder of Western Gas Resources, Inc., a company listed on the New York
Stock Exchange, and was Executive Vice President and Chief Operating Officer
from 1972 to 1986. Mr. Fox holds a bachelors degree in engineering from the
United States Air Force Academy and an MBA from the University of Denver.
BRIAN T. O'NEILL has been the Company's Senior Vice President, Chief
Operating Officer and a member of the Board of Directors since its inception
in April 1988. Mr. O'Neill has approximately 20 years of experience in NGL and
natural gas marketing, and served as a Marketing Manager for Western Gas
Resources, Inc., specializing in gas acquisition and sales, new business
development and NGL marketing, from 1982 to 1987. Mr. O'Neill holds a
bachelors degree in advertising and psychology from the University of Florida
and a masters degree in international marketing and finance from the American
Graduate School of International Management.
46
<PAGE>
ARTHUR J. DENNEY has been the Company's Vice President of Engineering and
Business Development since January 1990 and a member of the Board of Directors
since June 1996. Mr. Denney has over 22 years of experience in gas gathering,
gas processing and the NGL business. From 1987 to 1990, Mr. Denney served as
Manager of Business Development for Lair Petroleum, Inc. From 1974 to 1987,
Mr. Denney was employed by Enron Gas Processing Co. in a variety of positions,
including seven years as its Rocky Mountain Regional Manager for business
development. Mr. Denney holds a bachelors degree in mechanical engineering and
an MBA from the University of Nebraska.
ROBERT F. GARVIN joined MarkWest in 1988 as Manager, Exploration. Mr. Garvin
has been the Company's Vice President of Exploration since April 1996. Mr.
Garvin has more than 29 years of oil and gas industry experience. During his
career, Mr. Garvin has been employed as a geologist by Phillips Petroleum
Company, Duncan Oil Properties, Excel Energy Corporation, Ecological
Engineering Systems and has been a self-employed geologist. Mr. Garvin holds a
bachelors degree in geology from Westminster College and a masters degree in
geology from the University of Utah.
RITA E. HARVEY has been the Company's Director of Finance and Treasurer
since November 1995. From April 1994 through October 1995, Ms. Harvey served
as the Company's controller. Ms. Harvey is a certified public accountant with
over fifteen years of experience in accounting, budgeting, finance and
management. From July 1991 through March 1994, Ms. Harvey specialized in the
extractive industries as a member of the Audit and Business Advisory Services
Group of Price Waterhouse LLP. Ms. Harvey is currently in her third year as a
member of the Authority Finance Committee of the Denver Health and Hospitals
Board of Directors. Ms. Harvey holds a bachelors degree in accounting from
Metropolitan State College and is currently pursuing a masters degree in
finance at the University of Colorado at Denver.
NORMAN H. FOSTER has been a member of the Board of Directors of the Company
since June 1996. Dr. Foster has more than 33 years of experience in oil and
natural gas exploration, both domestic and international. Dr. Foster has been
an independent geologist since 1979, and has held positions with Sinclair Oil
Corporation, Trend Exploration Limited and Filon Exploration Corporation. In
1995, he co-founded Voyager Exploration, Inc., a private exploration and
production company for which he serves as President. Dr. Foster holds a
bachelors degree in general science and a masters degree in geology from the
University of Iowa and a Ph.D. in geology from the University of Kansas.
BARRY W. SPECTOR has been a member of the Board of Directors of the Company
since September 1995. Mr. Spector has practiced law as a sole practitioner
since 1979. Mr. Spector's practice emphasizes oil and gas law with a
particular emphasis in natural gas contracts, interstate and intrastate
regulation and marketing. Mr. Spector holds a bachelors degree in biology and
a J.D. from the University of Denver. Mr. Spector is also a director of
Chaparral Resources, Inc., a publicly-held company.
DAVID R. WHITNEY has been a member of the Board of Directors of the Company
since April, 1988. Since 1985, Mr. Whitney has been a Managing Director of
Resource Investors Management Company Limited Partnership ("RIMCO"), a full
service investment management company specializing in the energy industry and
the holder, after the Reorganization, of 3.5% of the Company's shares of
Common Stock. Mr. Whitney holds a bachelors degree in economics from the
University of Colorado and an MBA from the University of Connecticut.
KEY EMPLOYEES
KATHERINE S. HOLLAND joined MarkWest in 1988. She has been the Company's
Manager, NGL and Natural Gas Supply, since late 1993. Prior to that, she
served as the Company's Manager, Railcar Fleet and Distribution. Ms. Holland
has approximately 13 years' combined experience in the oil and gas industry
and the NGL and natural gas segment of the oil and gas industry. From 1983 to
1988, Ms. Holland was employed by Sherwood Exploration Company, an oil and gas
exploration and production company. Ms. Holland holds a bachelors degree in
art history from the University of Colorado.
47
<PAGE>
MICHAEL R. LA RUE joined MarkWest in 1991 as Controller. In 1993, Mr. La Rue
became Manager, Business Development for the Company, with primary
responsibility for business development in the Appalachian Core Area. From
1983 to 1991, Mr. LaRue was employed by Price Waterhouse as an accountant
specializing in tax consulting for the extractive industry. Mr. La Rue holds a
bachelors degree in accounting from Oklahoma State University.
KIMBERLY H. MARLE has been the Company's Manager, Information Systems, since
March 1995. Ms. Marle joined MarkWest in December 1993 as an information
systems consultant developing applications for the Company's accounting
systems. Ms. Marle has an extensive background in oil and gas computerization,
having worked for Forest Oil Corporation for four years prior to joining
MarkWest. Ms. Marle holds a bachelors degree in business from the University
of Memphis and is currently pursuing a masters degree in information systems
at the University of Denver.
FAYE E. MCGUAR joined MarkWest in 1996 as Controller. Ms. McGuar is a
certified public accountant with over 15 years of experience in accounting,
budgeting, treasury and finance. From 1994 to 1996, Ms. McGuar was employed by
the Southern Pacific Railroad as Budget Director, and from 1982 to 1988, she
was employed by the Anschutz Corporation, serving as its controller from 1987
to 1988. Ms. McGuar holds a bachelors degree in finance from the University of
Utah.
RANDY S. NICKERSON joined MarkWest in 1995 as Manager, New Projects, and now
serves as Manager, West Shore Processing and Basin Pipeline. From 1984 to
1990, he was a project manager and a project engineer for Chevron USA, and
from 1991 to 1995, he was a project engineer and Regional Engineering Manager
for Western Gas Resources, Inc. Mr. Nickerson holds a bachelors degree in
chemical engineering from Colorado State University.
JOSEPH D. O'MEARA joined MarkWest in 1992 as Manager, Siloam Plant. In 1995,
Mr. O'Meara was promoted to Manager, Appalachian Area. Prior to joining
MarkWest, Mr. O'Meara was employed for 26 years by Cities Service/Occidental
Petroleum, during which time he held a number of operational, supervisory and
management positions.
FRED R. SHATO joined MarkWest in 1989 as Manager, Marketing. In 1992, Mr.
Shato became the Company's General Manager, Marketing. Mr. Shato has 20 years
of experience in gasoline and NGL acquisition, trading and marketing, and
served as Manager of Trading and Product Acquisitioin for Certified Oil
Corporation from 1980 to 1989. Mr. Shato holds a bachelors degree in history
and political science from Defiance College.
BOARD OF DIRECTORS
The Company's By-Laws provide for a classified board of directors. The two
class I directors, Messrs. Denney and Foster, have been elected for an initial
term expiring at the 1997 annual meeting. The two class II directors, Messrs.
O'Neill and Spector, have been elected for an initial term expiring at the
1998 annual meeting. The two class III directors, Messrs. Fox and Whitney,
have been elected for an initial term expiring at the 1999 annual meeting. All
subsequent elections will be for successive three-year terms. No director is
selected or serves pursuant to any special arrangement or contract.
Officers serve at the discretion of the Board and are elected annually.
There are no family relationships between the directors or executive officers
of the Company.
The Board of Directors has a Compensation Committee and an Audit Committee.
The Compensation Committee makes recommendations to the Board concerning
salaries and incentive compensation for the Company's officers and employees
and administers the Company's 1996 Stock Incentive Plan, as amended (the
"Stock Incentive Plan"). The Audit Committee aids management in the
establishment and supervision of the Company's financial controls, evaluates
the scope of the annual audit, reviews audit results, consults with management
and the Company's independent auditors prior to the presentation of financial
statements to stockholders and, as appropriate, initiates inquiries into
aspects of the Company's financial affairs.
48
<PAGE>
Prior to this offering, directors have not received any compensation from
the Company for serving on the Board of Directors. All directors are
reimbursed for out-of-pocket expenses incurred while attending board and
committee meetings.
LIMITATION OF LIABILITY AND INDEMNIFICATION MATTERS
The Company is incorporated in Delaware in part to take advantage of certain
provisions in the Delaware General Corporation Law (the "Delaware Code")
relating to limitations on liability of corporate officers and directors.
The Company's Certificate of Incorporation limits the liability of directors
to the fullest extent permitted by the Delaware Code. Under current Delaware
law, a director's liability to a company or its stockholders may not be
limited with respect to (i) any breach of his duty of loyalty to the company
or its stockholders, (ii) acts or omissions not in good faith or which involve
intentional misconduct or a knowing violation of law, (iii) unlawful payments
or dividends or unlawful stock repurchases or redemptions as provided in
Section 174 of the Delaware Code or (iv) transactions from which the director
derived an improper personal benefit. The Company's Bylaws provide that the
Company shall indemnify its officers and directors and may indemnify its
employees and other agents to the fullest extent permitted under the Delaware
Code.
At present, there is no pending litigation or proceeding involving any
director, officer, employee or agent of the Company where indemnification
would be required or permitted. The Company is not aware of any overtly
threatened litigation or proceeding that might result in a claim for
indemnification.
EXECUTIVE COMPENSATION
The following table sets forth the cash and noncash compensation for the
fiscal year ended December 31, 1995, awarded to or earned by (i) the
individual who served as the Company's Chief Executive Officer ("CEO") in
fiscal 1995; and (ii) each other executive officer of the Company whose salary
and bonus in fiscal 1995 exceeded $100,000 ((i) and (ii), collectively, the
"Named Executive Officers"). No other officer had compensation in excess of
$100,000 for fiscal year 1995:
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
ANNUAL LONG TERM
COMPENSATION COMPENSATION
---------------- ------------
SALARY BONUS OPTIONS
NAME AND PRINCIPAL POSITIONS FISCAL YEAR ($) ($) (#)
- ---------------------------- ----------- -------- ------- ------------
<S> <C> <C> <C> <C>
John M. Fox........................... 1995 $140,510 $43,350 --
President and CEO.................... 1994 $109,516 $36,786 --
1993 $127,400 $ 2,997 --
Brian T. O'Neill...................... 1995 $142,191 $43,350 4,580
Senior Vice President and Chief
Operating Officer................... 1994 $117,338 $36,786 --
1993 $133,025 $ 2,997 --
Arthur J. Denney...................... 1995 $127,179 $39,235 6,331
Vice President of Engineering and
Business 1994 $109,515 $34,333 --
Development.......................... 1993 $117,875 $ 2,664 --
</TABLE>
49
<PAGE>
OPTION GRANTS
The following table sets forth information concerning stock options granted
to the Named Executive Officers during the fiscal year ended December 31,
1995, pursuant to the predecessor to the Company's Stock Incentive Plan. No
stock appreciation rights ("SARs") have been granted to these individuals to
date.
OPTION GRANTS IN LAST FISCAL YEAR
<TABLE>
<CAPTION>
NUMBER OF
SECURITIES PERCENT OF TOTAL
UNDERLYING OPTIONS GRANTED EXERCISE OR
OPTIONS TO EMPLOYEES IN BASE PRICE EXPIRATION
NAME GRANTED (#) FISCAL YEAR ($/SH) DATE
- ---- ----------- ---------------- ----------- --------------
<S> <C> <C> <C> <C>
John M. Fox............. -- -- -- --
Brian T. O'Neill........ 4,580 7.16% $6.99 August 1, 2001
Arthur J. Denney........ 6,331 9.89% $6.99 August 1, 2001
</TABLE>
FISCAL YEAR-END OPTION VALUES
The following table sets forth certain information with respect to stock
options held by each of the Company's Named Executive Officers. There have
been no option exercises by the Named Executive Officers since the formation
of the Company.
FISCAL YEAR-END OPTION VALUES
<TABLE>
<CAPTION>
NUMBER OF SECURITIES
UNDERLYING UNEXERCISED VALUE OF UNEXERCISED
OPTIONS AT FISCAL YEAR- IN-THE-MONEY OPTIONS AT
END (#) FISCAL YEAR-END ($)(1)
------------------------- -------------------------
NAME EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- ---- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C>
John M. Fox................. 5,725 1,425 $28,682 $ 7,139
Brian T. O'Neill............ 6,641 5,095 33,271 25,526
Arthur J. Denney............ 5,388 6,096 26,994 30,541
</TABLE>
- --------
(1) There was no public trading market for the Common Stock as of December
31, 1995. Accordingly, these values have been calculated on the basis of the
initial public offering price of $10.00 per share, less the applicable option
exercise price.
COMPENSATION PLANS
1996 Stock Incentive Plan. The Company's Stock Incentive Plan was adopted in
1996. The maximum number of shares authorized to be issued under the Stock
Incentive Plan is 650,000 shares of Common Stock. As of July 15, 1996, an
aggregate of approximately 486,305 shares of Common Stock had been reserved
for issuance under the Stock Incentive Plan and options to purchase an
aggregate of 163,695 shares of Common Stock were outstanding under the Stock
Incentive Plan. Outstanding options granted under the Stock Incentive Plan
generally vest and become exercisable at a rate of 20% per annum beginning on
the first anniversary after the date of grant. Generally, the term of each
outstanding option is the later to occur of three years after vesting or three
years after the closing of the Offering. The exercise price for options
granted under the Stock Incentive Plan is at least equal to 100% of the fair
market value of the Common Stock of the Company on the date of grant. The
Stock Incentive Plan permits the granting of stock options, including
incentive stock options ("ISOs") as defined under Section 422 of the Internal
Revenue Code of 1986, as amended (the "Code"), and non-qualified stock options
("NQSOs") which do not qualify as ISOs. The purpose of the Stock Incentive
Plan is to reward and provide incentives for executive officers and key
employees of the Company by providing them with an opportunity to acquire an
equity interest in the Company, thereby increasing their personal interest in
its continued success and progress. The purpose of the Stock Incentive Plan is
also to retain the services of executive officers and key employees as well as
to assist in attracting new executive officers and key employees. Non-employee
directors are not eligible to receive grants under the Stock Incentive Plan.
50
<PAGE>
The Stock Incentive Plan is administered by the Compensation Committee,
which has the sole and complete authority to select the employees (including
executive officers) who will receive options under the Stock Incentive Plan.
The Compensation Committee has the authority to determine the number of stock
options to be granted to eligible individuals, whether the options will be
ISOs or NQSOs and the terms and conditions of the options (which may vary from
grantee to grantee). The Compensation Committee determines the period for
which each stock option may be exercisable, but in no event may a stock option
be exercisable more than three years from the date the option becomes vested.
The number of shares available under the Stock Incentive Plan and the exercise
price of the options granted thereunder are subject to adjustment by the
Compensation Committee to reflect stock splits, stock dividends,
recapitalization, mergers, or other major corporate actions.
The Compensation Committee also has the authority under the Stock Incentive
Plan to grant Stock Appreciation Rights ("SARs") to employees. SARs confer on
the holder a right to receive, upon exercise, the excess of the Fair Market
Value of one Share on the date of exercise over the grant price of the SAR as
specified by the Committee, which price may not be less than 100% of the Fair
Market Value of one Share on the date of grant of the SAR. The grant price,
term, methods of exercise, dates of exercise, methods of settlement and any
other terms and conditions of any SAR are determined by the Committee.
The Board of Directors may discontinue, amend, or suspend the Stock
Incentive Plan in a manner consistent with the Stock Incentive Plan's
provisions, provided such changes do not violate the federal or state
securities laws.
In conjunction with the Reorganization, the Company will issue options to
purchase shares of Common Stock pursuant to the Stock Incentive Plan to
employees of MarkWest Partnership who currently hold outstanding options to
purchase partnership interests representing approximately 3% of the fully
diluted aggregate partnership interests in MarkWest Partnership. The aggregate
number of shares subject to such options is equal to (i) the percentage
interests of MarkWest Partnership into which the MarkWest Partnership options
were exercisable, multiplied by (ii) the fully diluted percentage of the
Company's Common Stock to be outstanding immediately after consummation of the
Reorganization (calculated prior to the issuance of the Shares in the
Offering). The exercise price per share for such options varies from $6.99 to
$7.86, and has been obtained by multiplying (i) the aggregate consideration to
have been paid pursuant to a MarkWest Partnership option, divided by (ii) the
number of shares of the Company's Common Stock into which the new option
issued pursuant to the Stock Incentive Plan is exercisable.
1996 Incentive Compensation Plan. The Company's 1996 Incentive Compensation
Plan (the "Compensation Plan") provides for cash incentive awards to
executives and employees of the Company in varying amounts, and is
administered by the Company's Compensation Committee. The Compensation Plan
was effective as of January 1, 1996. Certain bonus payments were made under
the Compensation Plan in May 1996. The Compensation Plan lists five tiers for
determining eligibility: Tier One includes all executive level employees; Tier
Two includes all management level employees; Tier Three includes all mid-level
exempt employees; Tier Four includes all lower-level exempt employees; and
Tier Five includes certain non-exempt employees. An incentive award is based
upon the financial performance of the Company compared to corporate goals for
1996. Profit sharing payments under the Compensation Plan are paid annually;
incentive payments under the Compensation Plan are paid periodically
throughout the year. The purpose of the Compensation Plan is to reward and
provide incentives for executives and employees of the Company by providing
them with an opportunity to acquire cash rewards, thereby increasing their
personal interest in the Company's continued success and progress.
During the fiscal years ended December 31, 1993, 1994 and 1995, the Company
made profit sharing payments under the Compensation Plan of approximately
$95,000, $213,000 and $211,000, respectively, and incentive compensation
payments of approximately $50,000, $315,000 and $401,000, respectively.
1996 Non-Employee Director Stock Option Plan. In July 1996, the Company
adopted the 1996 Non-Employee Director Stock Option Plan (the "Director Stock
Option Plan"), which has a five-year term. The
51
<PAGE>
Director Stock Option Plan provides for an automatic grant of NQSOs to
purchase 500 shares of Common Stock to non-employee directors upon completion
of the Offering, and an automatic grant of an option to purchase an additional
500 shares of Common Stock on the day after each subsequent annual meeting of
the Company's stockholders. The option price is equal to the fair market value
of the Common Stock on the date of grant. Initial option grants vest and
become exercisable as to one-third of the shares covered by the option on each
annual anniversary of the date of grant if the holder remains a director on
such date, provided that such options may become fully exercisable upon a
director's resignation from the Board of Directors or death of the holder.
Annual option grants vest and become exercisable as to 100% of the shares
covered by the option on the six-month anniversary of the date of grant if the
holder remains a director on such date, provided that such options may become
fully exercisable upon a director's resignation from the Board of Directors or
death of the holder. The Company has reserved 20,000 shares of Common Stock
for issuance under the Director Stock Option Plan. Upon completion of the
Offering, Messrs. Foster, Spector and Whitney will each receive options to
acquire 500 shares of Common Stock at the price of the shares offered to the
public in the Offering.
CERTAIN TRANSACTIONS
REORGANIZATION
The Company's business historically has been conducted by MarkWest
Partnership. Concurrently with the effectiveness of the Offering, the Company
will acquire from the current partners of MarkWest Partnership all of the
partnership interests in MarkWest Partnership in exchange for shares of the
Company pursuant to the Reorganization Agreement. Immediately following the
acquisition of MarkWest Partnership, MarkWest Partnership will be dissolved
and the Company will succeed to the business, assets and liabilities of
MarkWest Partnership. The Company believes that the transactions contemplated
by the Reorganization will qualify as a tax-free reorganization for United
States federal income tax purposes.
Pursuant to the Reorganization, the partners of MarkWest will receive an
aggregate of 5,725,000 shares of the Company's Common Stock. The terms of the
Reorganization Agreement provide that the partners will receive a fully
diluted percentage of the Company's Common Stock to be outstanding immediately
after consummation of the Reorganization (calculated prior to the issuance of
the Shares in the Offering) substantially equivalent to the partners'
interests in MarkWest Partnership. See "Reorganization."
MarkWest Partnership currently has outstanding options issued to current and
former employees that granted such employees the right to purchase partnership
interests representing approximately 3% of the fully diluted aggregate
partnership interests in MarkWest Partnership. As part of the Reorganization,
such employee options to purchase MarkWest Partnership interests will be
replaced by options to purchase shares of the Company's Common Stock issuable
pursuant to the Company's Stock Incentive Plan. Such options will be subject
to all of the terms and conditions of the Stock Incentive Plan. See
"Management--Compensation Plans--1996 Stock Incentive Plan."
PARTNERSHIP DISTRIBUTIONS
Immediately prior to consummation of the Reorganization, MarkWest
Partnership intends to make cash distributions to its partners equal to $10.0
million as a partial distribution of partnership capital. Such distribution
will be distributed pro rata to partners of MarkWest based upon such partners'
percentage interests in the partnership at the time of the distribution.
MarkWest Partnership intends to borrow the money necessary to make such
distribution under MarkWest Partnership's credit facility with the Lenders. As
MarkWest Partnership's successor, the Company will become obligated for such
borrowing. See "Management's Discussion and Analysis of Financial Condition--
Liquidity and Capital Resources--Credit Facilities." The Company intends to
repay substantially all of the indebtedness owed to Norwest Bank Denver, N.A.
under the Company's credit facility with the Lenders from the net proceeds of
this Offering. See "Use of Proceeds."
MarkWest Partnership is and has been a partnership for purposes of federal
income taxes. As a result, the net income of MarkWest Partnership was taxed
for federal and state income tax purposes directly to the partners
52
<PAGE>
of MarkWest Partnership rather than to MarkWest Partnership. MarkWest
Partnership distributed to its partners an aggregate of $995,000, $320,000 and
$4.2 million during the 1993, 1994 and 1995 fiscal years to cover income taxes
and an aggregate of $2.1 million during the 1993 fiscal year as a distribution
of partnership net earnings. No distributions of partnership net earnings were
made during fiscal years 1994 and 1995. The Partnership has distributed an
aggregate of $3.2 million to date in 1996 for partner income tax liabilities
through June 1996.
MWHC Holding, Inc., a Colorado corporation (the "MarkWest General Partner"),
received 70%, 69% and 69% of such distributions during the 1993, 1994 and 1995
fiscal years, respectively, and Erin Partners, Ltd., a Colorado limited
partnership ("Erin Partners"), received 11% of such distributions during each
of the 1993, 1994 and 1995 fiscal years. The MarkWest General Partner is
controlled by John Fox, President and Chief Executive Officer of the Company.
Erin Partners is controlled by Brian O'Neill, Senior Vice President and Chief
Operating Officer of the Company. See "Principal Stockholders."
INVESTMENTS WITH AFFILIATE
The Company, through its MarkWest Resources subsidiary, holds a 49%
undivided interest in several exploration and production assets ("E&P Assets")
owned jointly with MAK-J Energy, which owns a 51% undivided interest in such
properties. See "Business--Exploration and Production." The general partner of
MAK-J Energy is a corporation owned and controlled by John Fox, President and
Chief Executive Officer of the Company. The properties are held pursuant to
joint venture agreements entered into between MarkWest Resources and MAK-J
Energy. MarkWest Resources is the operator under such agreements. As the
operator, MarkWest Resources is obligated to provide certain engineering,
administrative and accounting services to the joint ventures. The joint
venture agreements provide for a monthly fee payable to MarkWest Resources for
all such expenses. While the amount of the monthly fee will in the future be
subject to review by the Company's independent directors, the monthly fee for
fiscal 1996 was not negotiated on an arm's length basis. Moreover, conflicts
of interest may arise regarding such oil and gas activities, including
decisions regarding expenses and capital expenditures and the timing of the
development and exploitation of the properties. Management nevertheless
believes that the terms of the Company's co-investments with MAK-J Energy are
as favorable to the Company as could have been obtained from unaffiliated
third parties. As of June 30, 1996, MarkWest had invested $3.3 million in E&P
Assets owned jointly with MAK-J Energy. See "Risk Factors--Conflicts of
Interest."
The E&P Assets were originally developed by MarkWest Coalseam Development
Company LLC ("Coalseam LLC"), a natural gas development venture, and MW
Gathering LLC ("Gathering LLC"), a natural gas gathering venture. Coalseam LLC
and Gathering LLC originally were owned 51% by MAK-J Energy and 49% by the
Company. In connection with the Reorganization, in June 1996 Coalseam LLC and
Gathering LLC were merged, the Company transferred its interest in the
combined company to MarkWest Resources, and the combined company dissolved and
distributed its properties to MarkWest Resources and MAK-J Energy in
proportion to their respective interests.
Mr. Fox has agreed that as long as he is an officer or director of the
Company and for two years thereafter, he will not, directly or indirectly,
participate in any future oil and gas exploration or production activities
with the Company except and to the extent that the Company's independent and
disinterested directors deem it advisable and in the best interests of the
Company to include one or more additional participants, which participants may
include entities controlled by Mr. Fox. Additionally, Mr. Fox has agreed that
as long as he is an officer or director of the Company and for two years
thereafter, he will not, directly or indirectly participate in any future oil
and gas exploration or production activity that may be in competition with
exploration or production activities of the Company except and to the extent
that Mr. Fox has first offered the Company the opportunity to participate in
that activity and the Company's independent and disinterested directors deem
it advisable and in the best interests of the Company not to participate in
that activity. The terms of any future transactions between the Company and
its directors, officers, principal stockholders or other affiliates, or the
decision to participate or not participate in transactions offered by the
Company's directors, officers, principal stockholders or other affiliates will
be approved by a majority of the Company's independent and disinterested
53
<PAGE>
directors. The Company's Board of Directors will use such procedures in
evaluating their terms as are appropriate considering the fiduciary duties of
the Board of Directors under Delaware law. In any such review the Board may
use outside experts or consultants including independent legal counsel, secure
appraisals or other market comparisons, refer to generally available
statistics or prices or take such other actions as are appropriate under the
circumstances. Although such procedures are intended to ensure that
transactions with affiliates will be on an arm's length basis, no assurance
can be given that such procedures will produce such result.
RELATED PARTY INDEBTEDNESS
MarkWest Partnership periodically extended offers to partners and employees
to purchase initial or additional interests in MarkWest Partnership. The
partners and/or employees have provided MarkWest Partnership with promissory
notes as part of the purchase price for such interests. According to the terms
of the promissory notes, interest accrues at 7% and payments are required for
the greater of accrued interest or distributions made by MarkWest Partnership
to partners in excess of the partner's income tax liability. An aggregate of
$592,000 principal amount of such notes are outstanding as of June 30, 1996. A
minimum of 50% of each individual's pro rata share of the Partnership
Distribution expected to be made prior to the effective date of the Offering
will be applied, in the case of distributions made to partners who issued
promissory notes to MarkWest Partnership, to outstanding amounts owed under
such promissory notes. Assuming application of such distribution to
outstanding amounts owed under the promissory notes, an aggregate of $397,000
principal amount of such notes will be outstanding subsequent to such
distribution. As part of the Reorganization, such remaining promissory notes
will be replaced by promissory notes owed to the Company. These new notes will
accrue interest at 7%, payable annually, and require full payment of principal
and outstanding interest on the third anniversary of the effective date of the
Reorganization.
54
<PAGE>
PRINCIPAL STOCKHOLDERS
The following table sets forth certain information regarding beneficial
ownership of the Company's Common Stock as of September 30, 1996, (i) by each
person (or group of affiliated persons) who is known by the Company to own
beneficially more than five percent (5%) of the Company's Common Stock, (ii)
by each of the Named Executive Officers, (iii) by each of the Company's
directors, and (iv) by all directors and executive officers as a group. The
Company believes that the persons and entities named in the table have sole
voting and investment power with respect to all shares of Common Stock shown
as beneficially owned by them, subject to community property laws, where
applicable.
<TABLE>
<CAPTION>
BENEFICIAL OWNERSHIP (1)
------------------------------------
PERCENTAGE
NUMBER OF SHARES BENEFICIALLY
BENEFICIALLY OWNED OWNED (2)
------------------ -----------------
BEFORE AFTER
NAME AND ADDRESS OF BENEFICIAL OWNER (3) OFFERING OFFERING
- ---------------------------------------- -------- --------
<S> <C> <C> <C>
MWHC Holding, Inc. (4)................... 3,806,084 66.5% 46.8%
Erin Partners, Ltd. (5).................. 601,663 10.5 7.4
John M. Fox (6).......................... 4,069,661 71.0 50.1
Brian T. O'Neill (7)..................... 831,894 14.4 10.2
Arthur J. Denney......................... 66,314 1.2 *
David R. Whitney (8)..................... 200,375 3.5 2.5
Barry W. Spector......................... 5,699 * *
Norman H. Foster......................... 0 * *
All directors and executive officers as a
group (8 persons) (6)(7)................ 5,183,627 90.2% 63.6%
</TABLE>
- --------
* Represents less than 1% of the outstanding shares
(1) All percentages have been determined at September 30, 1996 in accordance
with Rule 13d-3 under the Securities Exchange Act of 1934, as amended (the
"Exchange Act"). For purposes of this table, a person or group of persons is
deemed to have "beneficial ownership" of any shares of Common Stock that such
person or group has the right to acquire within sixty days after September 30,
1996. For purposes of computing the percentage of outstanding shares of Common
Stock held by each person or group of persons named above, any security which
such person or group has the right to acquire within sixty days after
September 30, 1996 is deemed to be outstanding, but is not deemed to be
outstanding for the purpose of computing the percentage ownership of any other
person. At September 30, 1996, a total of 5,725,000 shares of Common Stock
were issued and outstanding, options to acquire a total of 19,384 shares of
Common Stock were exercisable within sixty days and 19,384 shares are
exercisable at the consummation of the Offering pursuant to the Stock
Incentive Plan. The applicable percentage of "beneficial ownership" after this
Offering is based upon 8,125,000 shares of Common Stock outstanding, which
includes all of the numbers discussed above.
(2) Assumes no exercise of the Underwriters' over-allotment option.
(3) Unless otherwise indicated, the address for each listed stockholder is
c/o MarkWest Hydrocarbon, Inc., 5613 DTC Parkway, Suite 400, Englewood,
Colorado 80111.
(4) MWHC Holding, Inc. is an entity controlled by John M. Fox.
(5) Erin Investments, Inc., an entity controlled by Brian T. O'Neill, is the
general partner of Erin Partners, Ltd.
(6) Includes an aggregate of 257,853 shares held in the Brent A. Crabtree
Trust, the Brian T. Crabtree Trust and the Carrie L. Crabtree Trust (the
"Crabtree Trusts"), for which Mr. Fox is the Trustee. Also includes all shares
owned directly by MWHC Holding, Inc., an entity controlled by Mr. Fox. As a
result of Mr Fox's control of MWHC Holding, Inc., Mr. Fox may be deemed to
have an indirect pecuniary interest (within the
55
<PAGE>
meaning of Rule 16a-1 under the Exchange Act), in an indeterminate portion of
the shares beneficially owned by MWHC Holding, Inc. Mr. Fox disclaims
"beneficial ownership" of these shares within the meaning of Rule 13d-3 under
the Exchange Act, and also disclaims beneficial ownership of the shares held
in the Crabtree Trusts.
(7) Includes all shares owned directly by Erin Partners, Ltd., the general
partner of which is Erin Investments, Inc., an entity controlled by Mr.
O'Neill. As a result of Mr. O'Neill's control of Erin Investments, Inc. and
his indirect control of Erin Partners, Ltd., Mr. O'Neill may be deemed to have
an indirect pecuniary interest (within the meaning of Rule 16a-1 under the
Exchange Act), in an indeterminate portion of the shares beneficially owned by
Erin Partners, Ltd. Mr. O'Neill disclaims "beneficial ownership" of these
shares within the meaning of Rule 13d-3 under the Exchange Act.
(8) All of the shares indicated as owned by Mr. Whitney are owned by certain
limited partnerships whose general partner is RIMCO, and are included because
Mr. Whitney is a Managing Director of RIMCO. As such, Mr. Whitney may be
deemed to have an indirect pecuniary interest (within the meaning of Rule 16a-
1 under the Exchange Act), in an indeterminate portion of the shares
beneficially owned by RIMCO. Mr. Whitney disclaims "beneficial ownership" of
these shares within the meaning of Rule 13d-3 under the Exchange Act.
56
<PAGE>
DESCRIPTION OF CAPITAL STOCK
Upon the closing of this Offering, the authorized capital stock of the
Company will consist of twenty million (20,000,000) shares of Common Stock,
$0.01 par value, and five million (5,000,000) shares of Preferred Stock, $0.01
par value, for a total of twenty-five million (25,000,000) shares of capital
stock.
COMMON STOCK
Upon consummation of the Reorganization, there will be 5,725,000 shares of
Common Stock outstanding held of record by approximately 30 stockholders. The
holders of Common Stock are entitled to one vote per share on all matters to
be voted on by the stockholders. Subject to preferences that may be applicable
to outstanding shares of Preferred Stock, if any, the holders of Common Stock
are entitled to receive ratably such dividends as may be declared from time to
time by the Board of Directors out of funds legally available therefor. In the
event of the liquidation, dissolution or winding up of the Company, the
holders of Common Stock are entitled to share ratably in all assets remaining
after payment of liabilities, subject to prior liquidation rights of Preferred
Stock, if any, then outstanding. The Common Stock has no preemptive conversion
rights or other subscription rights. There are no redemption or sinking funds
provisions applicable to the Common Stock. All outstanding shares of Common
Stock are fully paid and non-assessable, and the shares of Common Stock to be
outstanding upon completion of this offering will be fully paid and non-
assessable.
PREFERRED STOCK
After the closing of the Offering, the Company will be authorized to issue
5,000,000 shares of undesignated Preferred Stock. The Board of Directors will
have the authority to issue the undesignated Preferred Stock in one or more
series and to fix the rights, preferences, privileges and restrictions granted
to or imposed upon any wholly unissued series of undesignated Preferred Stock
and to fix the number of shares constituting any series in the designations of
such series, without any further vote or action by the stockholders. The Board
of Directors, without stockholder approval, can issue Preferred Stock with
voting and conversion rights which could adversely affect the voting power of
the holders of Common Stock. The issuance of Preferred Stock may have the
effect of delaying, deferring or preventing a change in control of the
Company. The Company has no present plan to issue Preferred Stock.
CHANGE OF CONTROL PROVISIONS
Certain provisions of the Company's Certificate of Incorporation and Bylaws
may have the effect of preventing, discouraging or delaying a change in the
control of the Company and may maintain the incumbency of the Board of
Directors and management. The authorization of undesignated Preferred Stock
makes it possible for the Board of Directors to issue Preferred Stock with
voting or other rights or preferences that could impede the success of any
attempt to change control of the Company. In addition, the Company's Bylaws
limit the ability of stockholders of the Company to raise matters at a meeting
of stockholders without giving advance notice. The Bylaws also classify the
Company's Board of Directors into three classes, each class serving a three-
year term. Without the vote of 80% of the Company's capital stock, directors
may not be removed without cause by the stockholders. These provisions have
the effect of delaying a stockholder's ability to replace a majority of the
Board of Directors.
The Company is subject to the provisions of Section 203 of the Delaware
General Corporation Law ("Section 203") regulating corporate takeovers.
Section 203 prevents certain Delaware corporations, including those whose
securities are listed on the Nasdaq National Market, from engaging, under
certain circumstances, in a "business combination" (which includes a merger or
sale of more than 10% of the corporation's assets) with any "interested
stockholder" (a stockholder who acquired 15% or more of the corporation's
outstanding voting stock without the prior approval of the corporation's Board
of Directors) for three years following the date that such stockholder became
an "interested stockholder." A Delaware corporation may "opt out" of Section
203 with an express provision in its original certificate of incorporation or
an express provision in its certificate of
57
<PAGE>
incorporation or bylaws resulting from a stockholders' amendment approved by
at least a majority of the outstanding voting shares. The Company has not
"opted out" of the provisions of Section 203.
REGISTRATION RIGHTS
Under the terms of the Reorganization Agreement, 181 days after the closing
of this Offering, holders of approximately 1,019,675 shares of Common Stock
(the "Registrable Securities") will be entitled to certain rights with respect
to the registration of such shares of Common Stock under the Securities Act.
Specifically, certain beneficial owners of interests in MarkWest Partnership
(including certain limited partnerships whose general partner is RIMCO) who
will receive shares of Common Stock as part of the Reorganization and who are
not officers, directors or employees of the Company, and who are not the
beneficial holders of ten percent or more of the outstanding shares of Common
Stock either at the time immediately following the Reorganization or at the
time of a request for registration of shares of Common Stock, shall be
entitled to such registration rights. Under the Reorganization Agreement, if
the Company proposes to register any of its Common Stock under the Securities
Act, such holders of Registrable Securities are entitled to notice of such
registration and to include their Registrable Securities therein. The Company
may, in certain circumstances, defer such registration.
TRANSFER AGENT AND REGISTRAR
The Transfer Agent and Registrar for the Common Stock is American Securities
Transfer Inc.
LISTING
The Common Stock has been approved for listing on the Nasdaq National Market
under the trading symbol "MWHX," subject to official notice of issuance.
58
<PAGE>
SHARES ELIGIBLE FOR FUTURE SALE
Prior to this Offering, there has not been any public market for the Common
Stock. Sale of a substantial number of shares of Common Stock into the public
market following the Offering could adversely affect prevailing market prices
for the Common Stock.
Following this Offering, the Company will have outstanding an aggregate of
8,125,000 shares of Common Stock, assuming no exercise of the Underwriters'
over-allotment option. In addition to the 2,400,000 shares of Common Stock
offered hereby, as of the effective date of the Offering, there will be
5,725,000 shares of Common Stock outstanding, all of which are Restricted
Shares under the Securities Act. All executive officers, directors and certain
other stockholders and optionees of the Company have agreed they will not sell
5,480,610 shares of Common Stock held by them without the prior consent of
Dillon, Read & Co. Inc. for a period of 180 days from the date of this
Prospectus (the "180-day Lockup Period"). Following the 180-day Lockup Period,
up to 5,513,279 Restricted Shares will become eligible for sale in the public
market pursuant to Rule 144 subject to the volume and other restrictions
pursuant to such Rule. The Underwriters may, in their sole discretion and at
any time without notice, release all or any portion of the securities subject
to lock-up agreements.
In general, under Rule 144 as currently in effect, a person (or persons
whose shares are aggregated), who has beneficially owned shares for at least
two years (including the holding period of any prior owner except an
affiliate) is entitled to sell in "broker's transactions" or to market makers,
within any three-month period, a number of shares that does not exceed the
greater of (i) one percent of the then outstanding shares of Common Stock, or
(ii) generally, the average weekly trading volume in the Common Stock during
the four calendar weeks preceding the sale. Sales under Rule 144 are also
subject to the filing of a Form 144 with respect to such sale and certain
other limitations and restrictions. Under Rule 144(k), a person who is not
deemed to have been an affiliate of the Company at any time during the ninety
(90) days preceding a sale, and who has beneficially owned the shares proposed
to be sold for at least three years, would be entitled to sell such shares
without having to comply with the manner of sale, volume limitation or notice
filing provisions described above.
The Company is unable to estimate the number of shares that will be sold
under Rule 144, as this will depend on the market price for the Common Stock
of the Company, the personal circumstances of the sellers and other factors.
Prior to this Offering, there has been no public market for the Common Stock,
and there can be no assurance that a significant public market for the Common
Stock will develop or be sustained after the Offering. Any future sale of
substantial amounts of the Common Stock in the open market may adversely
affect the market price of the Common Stock offered hereby.
The Company intends to file a registration statement on Form S-8 under the
Securities Act to register up to 650,000 shares of Common Stock reserved for
issuance under its Stock Incentive Plan, thus permitting the resale of such
shares by nonaffiliates in the public market without restriction under the
Securities Act, subject to vesting restrictions with the Company or the lock-
up agreements described above. Upon the completion of this Offering, there
will be a total of approximately 163,695 shares subject to options which are
expected to be the subject matter of such registration statement.
59
<PAGE>
UNDERWRITING
The names of the Underwriters of the shares of Common Stock offered hereby
and the aggregate number of shares which each has severally agreed to purchase
from the Company, subject to the terms and conditions specified in the
Underwriting Agreement, are as follows:
<TABLE>
<CAPTION>
NUMBER OF
UNDERWRITER SHARES
----------- ---------
<S> <C>
Dillon, Read & Co. Inc. ........................................... 690,000
George K. Baum & Company........................................... 460,000
Bear, Stearns & Co. Inc. .......................................... 50,000
Alex. Brown & Sons Incorporated.................................... 50,000
Dean Witter Reynolds Inc. ......................................... 50,000
Donaldson, Lufkin & Jenrette Securities Corporation................ 50,000
A.G. Edwards & Sons, Inc. ......................................... 50,000
Goldman, Sachs & Co. .............................................. 50,000
Howard, Weil, Labouisse, Friedrichs Incorporated................... 50,000
Lazard Freres & Co. LLC ........................................... 50,000
Lehman Brothers Inc. .............................................. 50,000
Merrill Lynch, Pierce, Fenner & Smith Incorporated................. 50,000
Morgan Stanley & Co. Incorporated.................................. 50,000
Oppenheimer & Co., Inc. ........................................... 50,000
Prudential Securities Incorporated................................. 50,000
Salomon Brothers Inc .............................................. 50,000
Schroder Wertheim & Co. Incorporated............................... 50,000
Smith Barney Inc. ................................................. 50,000
The Chicago Corporation............................................ 25,000
First Albany Corporation........................................... 25,000
Hanifen, Imhoff Inc. .............................................. 25,000
Janney Montgomery Scott Inc. ...................................... 25,000
Jefferies & Company................................................ 25,000
Johnson Rice & Company L.L.C. ..................................... 25,000
McDonald & Company Securities, Inc. ............................... 25,000
The Ohio Company................................................... 25,000
Petrie Parkman & Co. .............................................. 25,000
Principal Financial Securities, Inc. .............................. 25,000
Rauscher Pierce Refsnes, Inc. ..................................... 25,000
Rodman & Renshaw, Inc. ............................................ 25,000
Roney & Co., L.L.C. ............................................... 25,000
Simmons & Company International.................................... 25,000
Southcoast Capital Corporation..................................... 25,000
Auerbach Pollak & Richardson Inc. ................................. 15,000
David A. Noyes & Company........................................... 15,000
Prime Charter Ltd ................................................. 15,000
Value Investing Partners, Inc. .................................... 15,000
Wellington (H.G.) & Co. Inc. ...................................... 15,000
---------
Total............................................................ 2,400,000
=========
</TABLE>
The Managing Underwriters are Dillon, Read & Co. Inc. and George K. Baum &
Company.
The Underwriters are committed to purchase all of the shares of Common Stock
offered hereby, if any are so purchased. The Underwriting Agreement contains
certain provisions whereby, if any Underwriter defaults in its obligation to
purchase such shares, and the aggregate obligations of the Underwriters so
defaulting do not exceed ten percent of the shares of Common Stock offered
hereby, some or all of the remaining Underwriters must assume such obligations.
60
<PAGE>
The Underwriters propose to offer the shares of Common Stock directly to the
public initially at the offering price per share set forth on the cover page of
this Prospectus and to certain dealers at such price less a concession not in
excess of $0.42 per share. The Underwriters may allow, and such dealers may re-
allow, concessions not in excess of $0.10 per share to certain other dealers.
The offering of the shares of Common Stock is made for delivery when, as and if
accepted by the Underwriters and subject to prior sale and withdrawal,
cancellation or modification of this offer without notice. The Underwriters
reserve the right to reject any order for the purchase of the shares. After the
public offering of the shares of Common Stock, the public offering price and
the concessions may be changed by the Managing Underwriters.
The Company has granted to the Underwriters an option for 30 days from the
date of this Prospectus, to purchase up to 360,000 additional shares of Common
Stock, at the initial public offering price less the underwriting discount set
forth on the cover page of this Prospectus. The Underwriters may exercise such
option only to cover over-allotments of the shares of Common Stock offered
hereby. To the extent the Underwriters exercise this option, each Underwriter
will be obligated, subject to certain conditions, to purchase the number of
additional shares of Common Stock proportionate to such Underwriter's initial
commitment.
The Company has agreed to indemnify the Underwriters against certain
liabilities under the Securities Act, or to contribute to payments the
Underwriters may be required to make in respect thereof.
The Company, certain pre-Offering stockholders, and all directors and
executive officers of the Company have agreed, subject to certain exceptions,
that they will not offer, sell, contract to sell, transfer or otherwise
encumber or dispose of any shares of Common Stock or securities convertible
into or exchangeable for Common Stock, or exercise demand registration rights,
for a period of 180 days from the date of this Prospectus, without the written
consent of Dillon, Read & Co. Inc.
Prior to the Offering, there has been no public market for the Common Stock.
Consequently, the initial public offering price for the Common Stock will be
determined by negotiation among the Company and the Managing Underwriters.
Factors to be considered in determining the initial public offering price will
be prevailing market conditions, the state of the Company's development, recent
financial results of the Company, the future prospects of the Company and its
industry, market valuations of securities of companies engaged in activities
deemed by the Managing Underwriters to be similar to those of the Company and
other factors deemed relevant.
The Underwriters do not intend to confirm sales to accounts over which they
exercise discretionary authority.
LEGAL MATTERS
The validity of the issuance of shares of Common Stock offered hereby will be
passed upon for the Company by Dorsey & Whitney LLP, Denver, Colorado. Certain
legal matters in connection with this Offering will be passed upon for the
Underwriters by Baker & Botts, L.L.P., Dallas, Texas.
EXPERTS
The financial statements of MarkWest Hydrocarbon, Inc. as of June 30, 1996
and of MarkWest Hydrocarbon Partners, Ltd. as of December 31, 1994 and 1995,
and for each of the three years in the period ended December 31, 1995 included
in this Prospectus have been so included in reliance on the reports of Price
Waterhouse LLP, independent accountants, given on the authority of said firm as
experts in auditing and accounting. The financial statements of Basin Pipeline
L.L.C. as of December 31, 1995, and the related statements of operations and
accumulated deficit and cash flows for the year then ended have been audited by
BDO Seidman, LLP, independent certified public accountants, and are included in
this Prospectus upon the authority of said firm as experts in auditing and
accounting.
61
<PAGE>
ADDITIONAL INFORMATION
The Company has filed with the Securities and Exchange Commission (the
"Commission") a Registration Statement on Form S-1 with respect to the shares
of Common Stock offered hereby, of which this Prospectus forms a part. In
accordance with the rules of the Commission, this Prospectus omits certain
information contained in the Registration Statement. For further information
with respect to the Company and the securities offered hereby, reference is
made to the Registration Statement and the exhibits and schedules filed
therewith. Statements contained in this Prospectus concerning the provisions of
such documents are necessarily summaries of such documents and each such
statement is qualified in its entirety by reference to the copy of the
applicable document filed with the Commission as an exhibit to the Registration
Statement. Copies of the Registration Statement and the exhibits and schedules
thereto may be inspected, without charge, at the offices of the Commission, or
obtained at prescribed rates from the Public Reference Section of the
Commission at 450 Fifth Street, N.W., Washington, D.C. 20549.
The Company intends to furnish to its stockholders annual reports containing
audited financial statements certified by its independent auditors and
quarterly reports for the first three quarters of each fiscal year containing
unaudited financial information.
62
<PAGE>
MARKWEST HYDROCARBON, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
MARKWEST HYDROCARBON, INC. BALANCE SHEET AS OF JUNE 30, 1996
Report of Independent Accountants........................................ F-2
Balance Sheet............................................................ F-3
Notes to Balance Sheet .................................................. F-4
MARKWEST HYDROCARBON PARTNERS, LTD. CONSOLIDATED FINANCIAL STATEMENTS AS
OF DECEMBER 31, 1994 AND 1995 AND JUNE 30, 1996 (UNAUDITED), AND FOR
EACH OF THE THREE YEARS IN THE PERIOD ENDED DECEMBER 31, 1995 AND FOR
THE SIX MONTHS ENDED JUNE 30, 1995 AND 1996 (UNAUDITED)
Report of Independent Accountants........................................ F-5
Consolidated Balance Sheet............................................... F-6
Consolidated Statement of Operations..................................... F-7
Consolidated Statement of Changes in Partners' Capital................... F-8
Consolidated Statement of Cash Flows..................................... F-9
Notes to Consolidated Financial Statements............................... F-10
BASIN PIPELINE, L.L.C. FINANCIAL STATEMENTS AS OF DECEMBER 31, 1995 AND
JUNE 30, 1996 (UNAUDITED), FOR THE YEAR ENDED DECEMBER 31, 1995 AND FOR
THE SIX MONTHS ENDED JUNE 30, 1995 AND 1996 (UNAUDITED)
Report of Independent Certified Public Accountants....................... F-18
Balance Sheet............................................................ F-19
Statement of Operations and Accumulated Deficit.......................... F-20
Statement of Cash Flows.................................................. F-21
Summary of Accounting Policies........................................... F-22
Notes to Financial Statements............................................ F-23
MARKWEST HYDROCARBON, INC. UNAUDITED PRO FORMA CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
Introduction............................................................. F-25
PRO FORMA AS ADJUSTED
Unaudited Pro Forma Condensed Consolidated Balance Sheet as of June 30,
1996................................................................... F-26
Unaudited Pro Forma Condensed Consolidated Statement of Operations for
the year ended December 31, 1995....................................... F-27
Unaudited Pro Forma Condensed Consolidated Statement of Operations for
the six months ended June 30, 1996..................................... F-28
PRO FORMA COMBINED
Unaudited Pro Forma Condensed Consolidated Balance Sheet as of June 30,
1996................................................................... F-29
Unaudited Pro Forma Condensed Consolidated Statement of Operations for
the year ended December 31, 1995:
5.3% Ownership Basis................................................... F-30
60% Ownership Basis.................................................... F-31
Unaudited Pro Forma Condensed Consolidated Statement of Operations for
the six months ended June 30, 1996:
5.3% Ownership Basis................................................... F-32
60% Ownership Basis.................................................... F-33
Notes to Unaudited Pro Forma Condensed Consolidated Financial
Statements.............................................................. F-34
</TABLE>
F-1
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of MarkWest Hydrocarbon, Inc.
In our opinion, the accompanying balance sheet presents fairly, in all
material respects, the financial position of MarkWest Hydrocarbon, Inc. at
June 30, 1996, in conformity with generally accepted accounting principles.
This financial statement is the responsibility of the management of MarkWest
Hydrocarbon, Inc.; our responsibility is to express an opinion on this
financial statement based on our audit. We conducted our audit of this
statement in accordance with generally accepted auditing standards which
require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statement is free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statement, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for the opinion expressed above.
Price Waterhouse LLP
Denver, Colorado
August 2, 1996
F-2
<PAGE>
MARKWEST HYDROCARBON, INC.
BALANCE SHEET
($000S)
<TABLE>
<CAPTION>
JUNE 30,
1996
--------
<S> <C>
ASSETS
Cash.................................................................. $ 1
----
Total current assets.................................................. 1
----
Deferred offering costs............................................... 100
----
Total assets.......................................................... $101
====
LIABILITIES AND STOCKHOLDERS' EQUITY
Accrued offering costs................................................ $100
----
Stockholders' equity:
Preferred stock, $.01 par value; 5,000,000 shares authorized, no
shares issued or outstanding....................................... --
Common stock, $.01 par value; 20,000,000 shares authorized, 100
shares issued and outstanding...................................... --
Additional paid-in capital.......................................... 1
----
Total stockholders' equity............................................ 1
----
Total liabilities and stockholders' equity............................ $101
====
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-3
<PAGE>
MARKWEST HYDROCARBON, INC.
NOTES TO BALANCE SHEET
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
MarkWest Hydrocarbon, Inc. (the "Company") was incorporated in June 1996 to
act as the successor to MarkWest Hydrocarbon Partners, Ltd. ("MWHP"). On the
effective date of the registration statement for the Company, MWHP will be
reorganized from a limited partnership into a corporation ("the
Reorganization"). The existing general and limited partners of MWHP will
exchange 100% of the Partnership interests in MWHP for 5,725,000 shares of
common stock of the Company. This transaction represents a reorganization of
entities under common control and will be accounted for at historical cost.
INCOME TAXES
Following the Reorganization, income taxes will be determined using the
asset and liability approach in accordance with Statement of Financial
Accounting Standards ("SFAS") No. 109, Accounting for Income Taxes. This
method gives consideration to the future tax consequences of temporary
differences between the carrying amounts and the tax bases of assets and
liabilities.
Provisions of the Internal Revenue Code provide that any future tax
liabilities resulting from the operation of the Company will be obligations of
the Company. Accordingly, the cumulative effect of deferred taxes related to
temporary differences that originated when the Company was a general
partnership and that will reverse subsequent to the reorganization will be
accounted for on the balance sheet on the date of the reorganization. In
accordance with SFAS 109, the Company will establish the appropriate deferred
taxes with a corresponding charge to the statement of operations.
NOTE 2. EMPLOYEE BENEFIT PLANS
The Company has adopted, subject to approval by stockholders, the 1996 Stock
Incentive Plan (the "Plan"). By the terms of the Plan, 650,000 shares have
been authorized for issuance of awards to officers and employees. The awards
may include incentive stock options ("ISOs") as defined under Section 422 of
the Internal Revenue Code of 1986, as amended (the "Code"), and non-qualified
stock options which do not qualify as ISOs, stock appreciation rights,
restricted stock and restricted stock units, performance awards, dividend
equivalents or other stock-based awards.
Stock options will be granted at an exercise price of not less than fair
market value at the date of grant, vest over a five-year period from the date
of grant, and are exercisable for a period of three years from the date the
options become vested. In conjunction with the Reorganization, the Company
will exchange options to purchase shares of common stock for outstanding
options to purchase partnership interests of MarkWest Hydrocarbon Partners,
Ltd. currently held by employees.
The Company accounts for its stock-based awards in accordance with the
provisions of APB 25 and will make the disclosures required by SFAS No. 123,
Accounting for Stock-Based Compensation.
F-4
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners of MarkWest Hydrocarbon Partners, Ltd.
In our opinion, the accompanying consolidated balance sheet and related
consolidated statements of operations, of cash flows and of changes in
partners' capital present fairly, in all material respects, the financial
position of MarkWest Hydrocarbon Partners, Ltd. and its subsidiaries at
December 31, 1995 and 1994, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1995, in
conformity with generally accepted accounting principles. These financial
statements are the responsibility of the management of MarkWest Hydrocarbon
Partners, Ltd.; 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
August 2, 1996
F-5
<PAGE>
MARKWEST HYDROCARBON PARTNERS, LTD.
CONSOLIDATED BALANCE SHEET
($000S)
<TABLE>
<CAPTION>
PRO FORMA
DECEMBER 31, JUNE 30, CAPITALIZATION
--------------- 1996 (NOTE 10)
1994 1995 (UNAUDITED) (UNAUDITED)
------- ------- ----------- --------------
<S> <C> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents......... $ 5,468 $ 761 $ 666
Trade receivables................. 4,180 5,735 3,588
Short-term advances............... -- 3,174 --
Product inventory................. 2,669 2,718 3,287
Materials and supplies inventory.. 142 112 264
Prepaid expenses and other
assets........................... 304 375 359
Prepaid feedstock................. 1,714 1,729 2,157
------- ------- -------
Total current assets............ 14,477 14,604 10,321
Property, plant and equipment, at
cost, net of accumulated
depreciation, depletion and
amortization of $7,913, $9,568 and
$10,810, respectively.............. 21,194 31,947 32,598
Intangible assets, net of
accumulated amortization of $71,
$152 and $233, respectively........ 141 320 443
Investment in West Shore
Processing......................... -- -- 629
Other assets........................ 101 25 --
------- ------- -------
Total assets........................ $35,913 $46,896 $43,991
======= ======= =======
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Trade accounts payable............ $ 1,924 $ 3,283 $ 4,430
Accrued liabilities............... 275 404 418
Interest payable.................. 431 147 99
Accrued bonus and profit sharing.. 213 401 230
Current portion of long-term
debt............................. 1,000 -- --
------- ------- -------
Total current liabilities....... 3,843 4,235 5,177
Long-term debt...................... 9,887 17,500 12,350 22,350
------- ------- ------- ------
Total liabilities............... 13,730 21,735 17,527
Commitments and contingencies (Note
5)................................. -- -- --
Partners' capital................... 22,183 25,161 26,464 16,464
------- ------- ------- ------
Total liabilities and partners'
capital............................ $35,913 $46,896 $43,991
======= ======= =======
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-6
<PAGE>
MARKWEST HYDROCARBON PARTNERS, LTD.
CONSOLIDATED STATEMENT OF OPERATIONS
($000S)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------- ------------------
1993 1994 1995 1995 1996
------- ------- ------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues:
Plant revenue................ $34,212 $33,056 $33,823 $ 17,225 $ 18,045
Terminal and marketing
revenue..................... 19,756 13,666 13,172 5,200 9,831
Oil and gas and other
revenue..................... 1,783 1,830 1,075 501 744
Gain on sales of oil and gas
properties.................. -- 4,275 -- -- --
------- ------- ------- -------- --------
Total revenue................ 55,751 52,827 48,070 22,926 28,620
------- ------- ------- -------- --------
Costs and Expenses:
Plant feedstock purchases.... 23,155 21,582 17,308 8,608 8,538
Terminal and marketing
purchases................... 18,845 11,497 11,937 4,829 8,683
Operating expenses........... 6,504 4,393 4,706 2,005 2,979
General and administrative
expenses.................... 3,747 3,654 4,189 2,064 2,140
Depreciation, depletion and
amortization................ 1,565 1,942 1,754 852 1,326
Reduction in carrying value
of assets................... -- 2,950 -- -- --
------- ------- ------- -------- --------
Total costs and expenses..... 53,816 46,018 39,894 18,358 23,666
------- ------- ------- -------- --------
Earnings from operations....... 1,935 6,809 8,176 4,568 4,954
Other income (expense):
Interest expense............. (1,515) (1,825) (508) (402) (509)
Interest income.............. 120 136 156 102 43
------- ------- ------- -------- --------
Total other income
(expense)................... (1,395) (1,689) (352) (300) (466)
------- ------- ------- -------- --------
Income before extraordinary
item.......................... 540 5,120 7,824 4,268 4,488
Extraordinary loss on
extinguishment of debt........ (1,750)
------- ------- ------- -------- --------
Net income..................... $ 540 $ 5,120 $ 6,074 $ 4,268 $ 4,488
======= ======= ======= ======== ========
Pro forma information
(unaudited) (Note 10):
Historical income before
extraordinary item.......... $ 540 $ 5,120 $ 7,824 $ 4,268 $ 4,488
Pro forma provision for
income taxes................ 228 1,424 2,937 1,667 1,670
------- ------- ------- -------- --------
Pro forma net income......... $ 312 $ 3,696 $ 4,887 $ 2,601 $ 2,818
======= ======= ======= ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-7
<PAGE>
MARKWEST HYDROCARBON PARTNERS, LTD.
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL
(UNAUDITED AS TO THE SIX MONTHS ENDED JUNE 30, 1996)
($000S)
<TABLE>
<CAPTION>
TOTAL
GENERAL LIMITED PARTNERS'
PARTNER PARTNERS CAPITAL
------- -------- ---------
<S> <C> <C> <C>
Balance, December 31, 1992........................ $13,824 $5,790 $19,614
Net income........................................ 376 164 540
Payments on notes receivable from partners........ -- 236 236
Distributions..................................... (1,919) (1,121) (3,040)
------- ------ -------
Balance, December 31, 1993........................ 12,281 5,069 17,350
Net income........................................ 3,533 1,587 5,120
Purchase of partnership interests financed by
notes receivable................................. -- 422 422
Notes receivable from partners.................... -- (422) (422)
Contributions..................................... -- 33 33
Distributions..................................... (214) (106) (320)
------- ------ -------
Balance, December 31, 1994........................ 15,600 6,583 22,183
Net income........................................ 4,203 1,871 6,074
Purchase of partnership interests financed by
notes receivable................................. -- 11 11
Notes receivable from partners.................... -- (11) (11)
Contributions/transfers........................... (30) 34 4
Distributions..................................... (2,876) (1,274) (4,150)
Option granted in conjunction with extinguishment
of debt.......................................... 726 324 1,050
------- ------ -------
Balance, December 31, 1995........................ 17,623 7,538 25,161
Net income for the six months ended June 30,
1996............................................. 3,099 1,389 4,488
Purchase of partnership interests financed by
notes receivable................................. -- 68 68
Notes receivable from partners.................... -- (68) (68)
Contributions..................................... -- 34 34
Distributions..................................... (2,203) (1,016) (3,219)
------- ------ -------
Balance, June 30, 1996............................ $18,519 $7,945 $26,464
======= ====== =======
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-8
<PAGE>
MARKWEST HYDROCARBON PARTNERS, LTD.
CONSOLIDATED STATEMENT OF CASH FLOWS
($000S)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------- -------------------
1993 1994 1995 1995 1996
------- ------- ------- --------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash Flows From Operating
Activities:
Net income.................... $ 540 $ 5,120 $ 6,074 $ 4,268 $ 4,488
Adjustments to reconcile net
income to net cash provided
by operating activities:
Depreciation, depletion and
amortization............... 1,565 1,942 1,754 852 1,326
Option granted in
conjunction with
extinguishment of debt..... -- -- 1,050 -- --
Gain on sale of assets...... -- (4,275) -- -- --
Reduction in carrying value
of assets.................. -- 2,950 -- -- --
(Increase) decrease in
accounts receivable........ 3,307 (977) (4,729) 1,976 5,321
(Increase) decrease in
inventories................ (1,296) 1,348 (19) 33 (721)
(Increase) decrease in
prepaids................... (345) (1,125) (86) 746 (412)
Increase (decrease) in
accounts payable and
accrued liabilities........ (1,554) (3,989) 1,392 2,796 943
------- ------- ------- --------- -------
Net cash flow from operating
activities................... 2,217 994 5,436 10,671 10,945
------- ------- ------- --------- -------
Cash Flows From Investing
Activities:
Capital expenditures.......... (6,941) (1,442) (12,426) (5,297) (2,566)
Proceeds from sale of assets.. -- 10,166 -- -- --
Decrease (increase) in
intangible and other assets.. 24 344 (184) 85 (3)
------- ------- ------- --------- -------
Net cash provided by (used in)
investing activities......... (6,917) 9,068 (12,610) (5,212) (2,569)
------- ------- ------- --------- -------
Cash Flows From Financing
Activities:
Proceeds from issuance of
long-term debt............... 23,513 7,201 17,500 3,750 3,500
Repayments of long-term debt.. (21,024) (12,800) (10,887) (10,887) (8,650)
Partners' distributions....... (3,040) (320) (4,150) (3,381) (3,219)
Other......................... 236 33 4 4 (102)
------- ------- ------- --------- -------
Net cash provided by (used in)
financing activities......... (315) (5,886) 2,467 (10,514) (8,471)
------- ------- ------- --------- -------
Net increase (decrease) in
cash and cash equivalents.... (5,015) 4,176 (4,707) (5,055) (95)
Cash and cash equivalents at
beginning of period............ 6,307 1,292 5,468 5,468 761
------- ------- ------- --------- -------
Cash and cash equivalents at end
of period...................... $ 1,292 $ 5,468 $ 761 $ 413 $ 666
======= ======= ======= ========= =======
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-9
<PAGE>
MARKWEST HYDROCARBON PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
MarkWest Hydrocarbon Partners, Ltd. (the "Partnership") is a Colorado
limited partnership formed on March 28, 1988. MWHC Holding, Inc. ("Holding")
is the general partner. The Partnership operates under a limited partnership
agreement (the "Agreement") which provides that net income or loss, certain
defined capital events and cash distributions (all as defined in the
Agreement) are generally allocated in accordance with the partners' respective
ownership percentages.
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 Partnership also purchases, stores and markets
natural gas and natural gas liquids and has begun to conduct strategic
exploration for new natural gas sources for its processing and fractionation
activities.
ACCOUNTING POLICIES
The interim consolidated financial statements and related notes thereto
presented herein are unaudited, but reflect, in the opinion of management, all
adjustments (which include only normal recurring adjustments) necessary for
fair presentation of the results for such periods. Footnote disclosures as of
June 30, 1996 and for the six months ended June 30, 1995 and 1996 are
presented only where significant.
The significant accounting policies followed by the Partnership and its
subsidiaries are presented herein to assist the reader in evaluating the
financial information contained herein. The Partnership's accounting policies
are in accordance with generally accepted accounting principles.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the
Partnership and its wholly-owned subsidiaries, MarkWest Resources, Inc.
("Resources") and MarkWest Michigan, LLC. All material intercompany
transactions have been eliminated in consolidation.
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
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 MarkWest Hydrocarbon Partners, Ltd. The
consolidated financial statements reflect Resources' 49% proportionate share
of the underlying oil and gas assets, liabilities, revenues and expenses.
WEST SHORE PROCESSING ACQUISITION (UNAUDITED)
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 Partnership's ownership interest increases as capital expenditures
for the benefit of West Shore are made by the Partnership. As of June 30,
1996, the Partnership has recorded a net investment in West Shore of $629,000
representing a 5.3% ownership interest. The Partnership is committed to make
capital expenditures of approximately $10.0 million through early 1997 in
conjunction with the first phase of the agreement.
F-10
<PAGE>
MARKWEST HYDROCARBON PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
CASH AND CASH EQUIVALENTS
The Partnership considers all highly liquid investments purchased with an
original maturity of three months or less to be cash equivalents.
Cash and cash equivalents comprise the following (in $000s):
<TABLE>
<CAPTION>
DECEMBER 31,
-------------- JUNE 30,
1994 1995 1996
------- -----------------
(UNAUDITED)
<S> <C> <C> <C>
Cash and overnight investments........................ $ 1,665 $ 761 $666
Cash held in escrow................................... 3,803 -- --
------- ----- ----
$ 5,468 $ 761 $666
======= ===== ====
</TABLE>
Excess cash is used to pay down the revolver facility. Accordingly,
investments are limited to overnight investments of end-of-day cash balances.
Cash held in escrow was comprised of funds received from the sale of oil and
gas properties which were held in escrow pending the consummation of a
transaction structured to qualify as a like-kind exchange of property for tax
purposes, within the meaning of Section 1031 of the Internal Revenue Code of
1986. Such transaction was consummated in 1995. The amounts were accessible by
the Partnership as of December 31, 1994 without restriction and, consequently,
are classified as cash equivalents.
INVENTORY
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 Partnership's
inventory was $3,618,000, $3,807,000 and $3,975,000 (unaudited) at December
31, 1994 and 1995 and June 30, 1996, respectively.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is recorded at cost. Expenditures which extend
the useful lives of assets are capitalized. Repairs, maintenance and renewals
which do not extend the useful lives of the assets are expensed as incurred.
The components of property, plant and equipment and the respective useful
lives and depreciation, depletion and amortization methods (straight line (SL)
or units of production (UOP)) are as follows (in $000s):
<TABLE>
<CAPTION>
DECEMBER 31,
---------------- JUNE 30, USEFUL DD&A
1994 1995 1996 LIVES METHOD
------- ------- ----------- ---------- ------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Land.......................... $ 730 $ 730 $ 830 -- --
Plant facilities.............. 21,604 31,699 32,319 20 years SL
Buildings..................... 264 308 491 40 years SL
Furniture, leasehold
improvements and other....... 5,770 6,895 6,476 3-10 years SL
Oil and gas properties........ 739 1,883 3,292 -- UOP
------- ------- -------
29,107 41,515 43,408
Accumulated depreciation,
depletion and amortization... (7,913) (9,568) (10,810)
------- ------- -------
$21,194 $31,947 $32,598
======= ======= =======
</TABLE>
F-11
<PAGE>
MARKWEST HYDROCARBON PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Oil and gas properties consist of leasehold costs, producing and non-
producing gas wells and equipment, and pipelines. The Partnership 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, 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, 1995 and June 30,
1996, approximately $862,000 and $2,271,000 (unaudited) of investments in
unproved properties were excluded from amortization, respectively.
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,
1995 and June 30, 1996.
Sales of proved and unproved properties are accounted for as adjustments of
capitalized costs with no gain or loss recognized, unless such adjustments
would significantly alter the relationship between capitalized costs and
proved reserves of oil and gas, in which case the gain or loss is recognized
in the consolidated statement of operations.
INTANGIBLE ASSETS
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.
REVENUE RECOGNITION
Revenue is recognized when product is shipped or when services are rendered.
INCOME TAXES
No provision for income taxes is necessary in the financial statements of
the Partnership because, as a partnership, it is not subject to income tax and
the tax effects of its activities accrue to the respective partners.
HEDGED TRANSACTIONS
The Partnership limits its exposure to propane and natural gas price
fluctuations related to future production with futures contracts. These
contracts are accounted for as hedges in accordance with the provisions of
Statement of Financial Accounting Standards ("SFAS") No. 80, Accounting for
Futures Contracts. Gains and losses on such hedge contracts are deferred and
included as a component of plant revenues and feedstock purchases when the
hedged production is sold.
As of December 31, 1994 and 1995, and as of June 30, 1996, the Partnership
did not hold any material notional quantities of natural gas, NGL, or crude
oil futures, swaps or options.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The Partnership's financial instruments consist of cash and cash
equivalents, receivables, trade accounts payable, accrued 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, 1995 and June 30, 1996, based on rates available
for similar types of debt, the fair value of long-term debt was not materially
different from its carrying amount.
F-12
<PAGE>
MARKWEST HYDROCARBON PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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 2. DEBT
REVOLVER LOAN
On November 20, 1992, the Partnership entered into a financing agreement
(the "Facility") with Norwest Bank Denver, N.A. ("Norwest") and First American
National Bank ("FANB") of Nashville, Tennessee. The Facility is structured as
a revolver, and the borrowing base is redetermined semi-annually. As of
December 31, 1995 and June 30, 1996, maximum borrowing bases of $25 million
and $40 million, respectively, were available to the Partnership, $10 million
and $31.5 million, respectively, of which were unutilized.
On September 8, 1995, the Facility was further amended to add N M Rothschild
and Sons Limited ("Rothschild") as a lender, revise the interest rate for base
rate loans, institute the option of a LIBOR (London Interbank Offered Rate)
interest rate, and extend the revolver commitment period and maturity dates.
Interest on a base rate loan is currently calculated at prime plus .25% if
the Partnership'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 .50%. At December 31, 1995 and June 30, 1996, $3 million and $2.5
million were outstanding under a base rate loan bearing interest at 9.00% and
8.50%, respectively.
The LIBOR option allows the Partnership 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 Partnership'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 2.25%. At December 31, 1995
and June 30, 1996, $12 million and $6 million were outstanding under a 90-day
LIBOR and 30-day LIBOR commitment bearing interest at 8.125% and 7.50%,
maturing February 16, 1996 and July 12, 1996, respectively. On May 31, 1996,
the Facility was amended to increase the maximum borrowing base to $40 million
and extend the repayment period to June 30, 2002, with 16 equal quarterly
installments commencing September 30, 1998.
This debt is secured by a first mortgage on the Partnership's property,
plant, equipment and contracts, excluding railcars and truck trailers. The
Facility 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/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, 1997. At December
31, 1995 and June 30, 1996, the full amount of the borrowing base was
available under the working capital line. The interest rate is the same as
discussed above for base rate loans. No LIBOR option is available for the
working capital line. At December 31, 1995 and June 30, 1996, $2.5 million and
$3.85 million (unaudited) were outstanding under base rate loans bearing
interest at 9.00% and 8.5%, respectively. On
F-13
<PAGE>
MARKWEST HYDROCARBON PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
May 31, 1996, the commitment period was extended to June 30, 1998. The
agreement is secured by the Partnership's inventory, receivables and cash.
Scheduled debt maturities under the terms of each facility are as follows
(in $000s):
<TABLE>
<CAPTION>
DECEMBER 31, 1995 JUNE 30, 1996
---------------------------- ----------------------------
(UNAUDITED)
REVOLVER LOAN LINE OF CREDIT REVOLVER LOAN LINE OF CREDIT
------------- -------------- ------------- --------------
<S> <C> <C> <C> <C>
1996................. $ -- $ -- $ -- $ --
1997................. 1,875 2,500 -- --
1998................. 3,750 -- 1,062 3,850
1999................. 3,750 -- 2,125 --
2000 and thereafter.. 5,625 -- 5,313 --
------- ------ ------ ------
Total................ $15,000 $2,500 $8,500 $3,850
======= ====== ====== ======
</TABLE>
SILOAM NOTE
On December 15, 1989, the Partnership entered into a note agreement in
conjunction with the purchase of the Siloam plant and the isomerization
expansion. The note agreement 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 $405,000 and
$422,000 for 1993 and 1994, respectively.
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 for $35,000. 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 3. RELATED PARTY AND PARTNERS' CAPITAL TRANSACTIONS
The Partnership made contributions of $95,000, $213,000, and $211,000 to a
profit-sharing plan maintained by the general partner for the years ended
December 31, 1993, 1994 and 1995, and accrued a liability of $113,000 for
estimated contributions for the six months ended June 30, 1996. The plan is
discretionary, with annual contributions determined by the general partner's
board of directors.
The Partnership periodically extends offers to partners and employees to
purchase initial or additional interests in the Partnership. The partners
and/or employees have provided the Partnership with promissory notes as part
of the purchase 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 dated December 31, 1990, January 1, 1994, October 1,
1994, and January 1, 1995 in the amounts of $80,000, $313,000, $109,000, and
$11,000, respectively, have been reflected as reductions of partners' capital
at December 31, 1995.
During 1992, the management of the Partnership granted limited partnership
options to certain employees. The options are exercisable at a fixed price and
subject to certain conditions and restrictions. The options vest ratably over
5 years and are non-transferable. In 1993 and 1995, management granted
additional limited
F-14
<PAGE>
MARKWEST HYDROCARBON PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
partnership interest options with a fixed exercise price of $40 per .0001%
interest. In addition, the previously issued options were amended to reduce
the option price from $50 to $40, which was estimated to be the fair value at
that date. Options to purchase 1.3%, 2.5% and 2.9% of the Partnership were
outstanding at December 31, 1994 and 1995 and June 30, 1996, respectively, of
which .3%, .6 %, and .9%, respectively, were exercisable. These percentages do
not include the option to acquire 3.5% of the Partnership described in Note 2.
The Partnership's employees perform certain administrative functions on
behalf of Holding, Energy, Coalseam and Gathering. At December 31, 1995 and
June 30, 1996, no material amounts were due to or receivable from Holding,
Energy, Coalseam or Gathering for miscellaneous administrative expenses. The
Partnership charged $324,000 and $178,000 (unaudited) of administrative
expenses to Holding, Energy, Coalseam and Gathering for the year ended
December 31, 1995 and the six months ended June 30, 1996, respectively, which
represented management's best estimate of the actual cost of such services. No
material amounts of administratives expenses were charged to Holding, Energy,
Coalseam and Gathering for the years ended December 31, 1993 and 1994.
NOTE 4. REDUCTION IN CARRYING VALUE OF ASSETS
In 1994, the Partnership shut down the Siloam plant 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 in 1994. 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 5. COMMITMENTS AND CONTINGENCIES
Rental expense was $160,000, $166,000, $195,000 and $102,000 (unaudited) for
the years ended December 31, 1993, 1994 and 1995 and for the six months ended
June 30, 1996, respectively.
Future minimum lease payments under all operating leases are as follows (in
$000s):
<TABLE>
<CAPTION>
DECEMBER 31, 1995 JUNE 30, 1996
--------------------------------------------- ---------------------------------------------
(UNAUDITED)
RAILCAR LEASES OTHER LEASES TOTAL OBLIGATIONS RAILCAR LEASES OTHER LEASES TOTAL OBLIGATIONS
-------------- ------------ ----------------- -------------- ------------ -----------------
<S> <C> <C> <C> <C> <C> <C>
1996.................... $107 $176 $283 $22 $100 $122
1997.................... -- 51 51 -- 51 51
1998.................... -- 6 6 -- 6 6
1999.................... -- 5 5 -- 5 5
2000.................... -- 5 5 -- 5 5
---- ---- ---- --- ---- ----
Total................... $107 $243 $350 $22 $167 $189
==== ==== ==== === ==== ====
</TABLE>
The Partnership leases railcars to ensure efficient movement of natural gas
liquids to fulfill sales obligations. The Partnership has obtained commitments
for railcar subleases to receive payments of $221,000 and $81,000 during 1996
and 1997, respectively.
NOTE 6. ACCOUNTS RECEIVABLE
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.
At December 31, 1995 and June 30, 1996, trade receivables totaled $5,735,000
and $3,588,000 (unaudited), respectively, which included receivables from
employees and officers of $74,000 and $80,000 (unaudited), respectively. No
allowance for doubtful accounts is considered necessary based on favorable
historical experience.
F-15
<PAGE>
MARKWEST HYDROCARBON PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE 7. SIGNIFICANT CUSTOMERS
For the years ended December 31, 1993 and 1995 and the six months ended June
30, 1996, sales to one customer accounted for approximately 16%, 18% and 14%
(unaudited) of total revenues, respectively. During 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. SUPPLEMENTAL CASH FLOW INFORMATION
Interest of $1,408,000, $1,805,000, $792,000, $545,000 (unaudited) and
$557,000 (unaudited) was paid for the years ended December 31, 1993, 1994 and
1995 and for the six-month periods ended June 30, 1995 and 1996, respectively.
Interest paid in 1995 is net of $301,000 capitalized in relation to
construction projects.
NOTE 9. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The following summarizes certain quarterly results of operations ($000s):
<TABLE>
<CAPTION>
OPERATING GROSS PROFIT PRETAX INCOME
REVENUES (LOSS) (A) (LOSS)(B)
--------- ------------ -------------
<S> <C> <C> <C>
QUARTER ENDED:
March 31, 1994............................ $16,342 $ 2,421 $1,492
June 30, 1994............................. 2,911 (1,023) (1,939)
September 30, 1994........................ 9,707 1,955 893
December 31, 1994......................... 23,867 5,785 4,674 (c)
------- ------- ------
$52,827 $ 9,138 $5,120
======= ======= ======
March 31, 1995............................ $15,566 $ 4,770 $3,589
June 30, 1995............................. 7,360 1,860 679
September 30, 1995........................ 8,665 1,564 (1,182)(d)
December 31, 1995......................... 16,479 4,171 2,988
------- ------- ------
$48,070 $12,365 $6,074
======= ======= ======
March 31, 1996............................ $19,832 $ 5,514 $4,174
June 30, 1996............................. 8,788 1,580 314
------- ------- ------
$28,620 $ 7,094 $4,488
======= ======= ======
</TABLE>
- --------
(a) Excludes gain on sale of oil and gas properties, general and
administrative expenses, reduction in carrying value of assets and net
interest expense.
(b) Excludes income taxes since the Partnership is not subject to income
taxes.
(c) Includes $4,275 gain on sale of oil and gas properties and $2,950 charge
for reduction in carrying value of assets.
(d) Includes $1,750 extraordinary loss on extinguishment of debt.
F-16
<PAGE>
MARKWEST HYDROCARBON PARTNERS, LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE 10. PLANNED REORGANIZATION AND PARTNERSHIP DISTRIBUTION
In connection with a planned offering of common stock to the public, the
Partnership intends to reorganize and the existing general and limited
partners will exchange their interests in the Partnership for common shares of
MarkWest Hydrocarbon, Inc., a corporation formed to be the successor to the
Partnership ("MHI"). Since MHI will be a taxable entity, a pro forma provision
for income taxes has been presented in the financial statements as if the
Partnership had been a taxable entity for all periods presented.
Pro forma earnings per share has not been presented due to the planned
significant change in capital structure.
The pro forma capitalization as of June 30, 1996 presented on the face of
the balance sheet reflects only the $10.0 million distribution to the partners
planned to occur just prior to the reorganization and does not include the pro
forma income tax effect of the reorganization.
F-17
<PAGE>
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
The Members
Basin Pipeline L.L.C.
Englewood, Colorado
We have audited the accompanying balance sheet of Basin Pipeline L.L.C. (the
"Company") as of December 31, 1995 and the related statements of operations
and accumulated deficit and cash flows for the year then ended. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards 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. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Basin Pipeline, L.L.C. at
December 31, 1995, and the results of its operations and its cash flows for
the year then ended in conformity with generally accepted accounting
principles.
The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. As discussed in Note 1 to the
financial statements, the Company has incurred recurring losses from
operations, has a working capital deficiency and is in default on a
significant portion of its debt. These conditions raise substantial doubt
about the Company's ability to continue as a going concern. Management's plans
in regard to these matters are also described in Note 1. The financial
statements do not include any adjustments that might result from the outcome
of this uncertainty.
BDO Seidman, LLP
Denver, Colorado
April 5, 1996
F-18
<PAGE>
BASIN PIPELINE L.L.C.
BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
1995 1996
------------ -----------
(UNAUDITED)
(SEE
NOTE 5)
<S> <C> <C>
ASSETS (NOTE 2)
CURRENT:
Cash................................................................................................ $ 3,646 $ 9,353
Accounts receivable, related party.................................................................. 29,401 260,955
Other current assets................................................................................ -- 8,072
----------- -----------
Total current assets.................................................................................. 33,047 278,380
----------- -----------
PROPERTY AND EQUIPMENT--
Gas gathering and processing........................................................................ 9,393,405 10,332,817
Less accumulated depreciation....................................................................... 1,566,981 80,118
----------- -----------
Net property and equipment............................................................................ 7,826,424 10,252,699
----------- -----------
$ 7,859,471 $10,531,079
=========== ===========
LIABILITIES AND MEMBERS' CAPITAL DEFICIT
CURRENT:
Accounts payable.................................................................................... $ 1,749,511 $ 92,814
Interest payable.................................................................................... 178,938 --
Accrued expenses.................................................................................... 3,302 31,811
Current maturities of long-term debt (Note 2)....................................................... 9,112,275 --
----------- -----------
Total current liabilities............................................................................. 11,044,026 124,625
Commitments and contingencies (Notes 1 and 3)
MEMBERS' CAPITAL DEFICIT:
Contributed capital................................................................................. 2,000 10,359,404
Accumulated deficit................................................................................. (3,186,555) --
Retained earnings................................................................................... -- 47,050
----------- -----------
Total members' capital deficit........................................................................ (3,184,555) 10,406,454
----------- -----------
$ 7,859,471 $10,531,079
- --------------------------------------------------
=========== ===========
</TABLE>
See accompanying report of independent certified public accountants, summary of
accounting policies and notes to financial statements.
F-19
<PAGE>
BASIN PIPELINE L.L.C.
STATEMENT OF OPERATIONS AND ACCUMULATED DEFICIT
<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED ENDED FROM JANUARY 1 FROM MAY 6
DECEMBER 31, JUNE 30, THROUGH MAY 5, THROUGH JUNE 30,
1995 1995 1996 1996
------------ ----------- -------------- ----------------
(UNAUDITED) (UNAUDITED) (UNAUDITED)
(SEE NOTE 5)
<S> <C> <C> <C> <C>
REVENUE:
Pipeline and transportation fees................................. $ 841,380 $ 420,690 $ 304,361 $229,850
Other income..................................................... 74 10 -- --
----------- ----------- --------- --------
Total revenue...................................................... 841,454 420,700 304,361 229,850
----------- ----------- --------- --------
COSTS AND EXPENSES:
Pipeline operating and other costs............................... 669,004 253,298 202,907 92,316
General and administrative....................................... 205,219 92,562 61,280 10,366
----------- ----------- --------- --------
Total costs and expenses........................................... 874,223 345,860 264,187 102,682
----------- ----------- --------- --------
OTHER EXPENSES:
Depreciation..................................................... 899,728 449,864 299,909 80,118
Interest......................................................... 1,100,022 660,513 516,362 --
----------- ----------- --------- --------
Total other expenses............................................... 1,999,750 1,110,377 816,271 80,118
----------- ----------- --------- --------
Net loss........................................................... (2,032,519) $(1,035,537) $(776,097) $ 47,050
=========== ========= ========
Accumulated deficit, beginning of year............................. (1,154,036)
-----------
Accumulated deficit, end of year................................... $(3,186,555)
- --------------------------------------------------
===========
</TABLE>
See accompanying report of independent certified public accountants,summary of
accounting policies and notes to financial statements.
F-20
<PAGE>
BASIN PIPELINE L.L.C.
STATEMENT OF CASH FLOWS
INCREASE (DECREASE) IN CASH
<TABLE>
<CAPTION>
FROM
JANUARY 1 FROM MAY 6
YEAR ENDED SIX MONTHS THROUGH THROUGH
DECEMBER 31, ENDED MAY 5, JUNE 30,
1995 JUNE 30, 1995 1996 1996
------------ ------------- ----------- ------------
(UNAUDITED) (UNAUDITED) (UNAUDITED)
(SEE NOTE 5)
<S> <C> <C> <C> <C>
OPERATING ACTIVITIES:
Net loss............................................................... $(2,032,519) $(1,035,537) $(776,097) $ 47,050
Adjustments to reconcile net loss to net cash provided by operating
activities--
Depreciation.......................................................... 899,728 449,864 816,271 80,118
Changes in operating assets and liabilities:
Trade accounts receivable............................................ 24,407 12,847 7,193 8,072
Intercompany accounts................................................ 180,287 94,977 -- 260,955
Trade accounts payable............................................... 488,264 619,329 462,235 92,814
Interest payable..................................................... 512,200 39,722 (178,938) --
Accrued expenses..................................................... 3,302 -- 209,077 (83,631)
----------- ----------- --------- --------
Cash provided by operating activities.................................... 75,669 181,202 539,741 405,378
----------- ----------- --------- --------
CASH USED IN INVESTING ACTIVITIES--
Purchase of property and equipment....................................... (489,828) (678,159) (543,224) (396,188)
----------- ----------- --------- --------
CASH PROVIDED BY FINANCING ACTIVITIES--
Proceeds from long-term debt............................................. 417,114 506,199 -- --
----------- ----------- --------- --------
Net increase (decrease) in cash.......................................... 2,955 9,242 (3,483) 9,190
Cash, beginning of year.................................................. 691 691 3,646 163
----------- ----------- --------- --------
Cash, end of year........................................................ $ 3,646 $ 9,933 $ 163 $ 9,353
- --------------------------------------------------
=========== =========== ========= ========
</TABLE>
See accompanying report of independent certified public accountants,summary of
accounting policies and notes to financial statements.
F-21
<PAGE>
BASIN PIPELINE L.L.C.
SUMMARY OF ACCOUNTING POLICIES
ORGANIZATION AND BUSINESS
Basin Pipeline L.L.C. (the "Company") owns and operates a sour gas gathering
system in Western Michigan and is also responsible for transportation and
marketing operations.
FINANCIAL INSTRUMENTS AND CREDIT RISK CONCENTRATION
Financial instruments that potentially subject the Company to concentrations
of credit risk consist primarily of cash. The Company maintains cash in bank
deposit accounts that at times may exceed Federally insured limits. To date,
the Company has not incurred a loss relating to these concentrations of credit
risk.
The Company derived all of its revenue from one customer.
USE OF ESTIMATES
The preparation of the Company's financial statements in conformity with
generally accepted accounting principles requires the Company's management to
make estimates and assumptions that affect the amounts reported in the
accompanying financial statements. Actual results could differ from those
estimates.
PROPERTY, EQUIPMENT AND DEPRECIATION
Property and equipment are recorded at cost. Renewals and betterments that
substantially extend the useful life of the assets are capitalized.
Maintenance and repairs are expensed when incurred. Depreciation is computed
using the straight-line method over estimated useful lives ranging from seven
to ten years. Gains and losses on retirements are included in operations.
INCOME TAXES
As a Limited Liability Company, the tax consequences of the Company's
operations are the responsibility of each member. Accordingly, the
accompanying financial statements do not include a provision for current or
deferred income taxes.
CASH EQUIVALENTS
The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents.
REVENUE RECOGNITION
Revenue is recognized upon the sale of gas at the wellhead.
RECENT ACCOUNTING PRONOUNCEMENTS
The Financial Accounting Standards Board has recently issued Statement of
Financial Accounting Standards ("SFAS") No. 121, "Accounting for the
Impairment of Long-Lived Assets." SFAS No. 121 requires that long-lived assets
and certain identifiable intangibles be reported at the lower of the carrying
amount or their estimated recoverable amount and the adoption of the statement
by the Company is not expected to have an impact on the financial statements.
This statement is effective for fiscal years beginning after December 15,
1995.
F-22
<PAGE>
BASIN PIPELINE L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. GOING CONCERN
As reflected in the accompanying financial statements, the Company incurred
a net loss of $2,032,519 for the year ended December 31, 1995 and its current
liabilities exceeded its current assets by approximately $11,000,000.
Additionally, the Company is in default on a significant portion of its debt,
resulting in classification of such amounts as current liabilities. These
conditions raise substantial doubt about the Company's ability to continue as
a going concern.
Management's plans with regard to the Company's ability to continue as a
going concern include the contribution of the members' capital to a new entity
in exchange for an interest in the newly formed entity. The Company believes
the execution of this plan will provide sufficient liquidity for the Company
to continue as a going concern. The financial statements do not include any
adjustments that might result from the outcome of this uncertainty.
2. LONG-TERM DEBT
During December 1993, the Company and its affiliate Manistee Gas Limited
Liability Company (the "Companies") entered into a credit agreement ("Credit
Agreement") with Gas Fund to finance the construction and acquisition of
certain processing facilities, gathering systems, and oil and gas properties.
The original amount of the credit agreement was for up to $13,800,000. During
1995, the maximum amount available under the Credit Agreement was increased to
$18,700,000. At December 31, 1995, the Company owes $9,112,275 to Gas Fund
under the Credit Agreement. The Companies incur a placement fee of one and
one-half percent (1 1/2%) of the amounts funded under the Credit Agreement,
and are charged a commitment fee of one-half percent ( 1/2%) of the unused
portion of the maximum loan amount. The Credit Agreement bears interest at 17%
per annum as the combined balance due exceeds $16 million, with interest
payments due quarterly. Principal payments are payable quarterly out of
available cash flows, subject to annual mandatory prepayments. In addition to
the payment terms, the Companies are subject to various restrictive covenants,
including a current ratio requirement of not less than one to one from and
after December 31, 1994. The Credit Agreement is collateralized by a first
lien on substantially all of the Companies' assets. Borrowings under the
Credit Agreement and related amounts are allocated between the Company and its
affiliate based upon their proportionate amount of assets acquired with the
proceeds received under the Credit Agreement.
The Companies are in default on certain prepayment requirements and other
covenants under the Credit Agreement. As such, the Companies have classified
the entire balance owing to Gas Fund as current liabilities as of December 31,
1995. See Note 5.
As a condition of the Credit Agreement, the Companies granted a net profits
interest and preferred LLC interest (the "NPI") to Gas Fund. The NPI is based
on net cash flows from operations, as adjusted for limitations on debt service
payments, general and administrative expenses, and various other expenditures.
The NPI is 22% after pay-out and is to be calculated quarterly and paid, if
applicable, within thirty days following the end of each quarter. As of
December 31, 1995, the Companies had amounts owing to Gas Fund totalling
approximately $23,000 which are recorded in royalties payable of Manistee Gas
Limited Liability Company.
Interest expense was approximately $1,100,000 for the year ended December
31, 1995.
Statement of Financial Accounting Standards No. 107 requires that the fair
value of short-term notes payable, loans payable, and commercial paper be
disclosed. The carrying amount of the Company's debt approximates fair value
due to its short-term maturity.
F-23
<PAGE>
BASIN PIPELINE L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
3. COMMITMENTS AND CONTINGENCIES
The Company's operations may impose certain environmental and dismantlement
commitments in future years. Management does not believe the Company currently
has any material commitments of this nature. Accordingly, no accrual has been
recorded for potential future costs.
The Company leases certain vehicles and compressor equipment under the terms
of noncancellable operating lease agreements. The original unexpired lease
terms range from one to five years. Minimum future rental payments are as
follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
- ------------------------
<S> <C>
1996.................................................................. $156,316
1997.................................................................. 155,125
1998.................................................................. 154,032
1999.................................................................. 53,562
2000.................................................................. 2,880
--------
$521,915
========
</TABLE>
Rent expense under operating leases for the year ended December 31, 1995 was
approximately $162,000.
4. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash payments of interest totalled $572,970 for the year ended December 31,
1995.
Excluded from the statement of cash flows for the year ended December 31,
1995 was $474,516, representing accrued interest on debt added back to debt
principal.
5. ACQUISITION OF THE COMPANY (UNAUDITED)
On May 6, 1996, the Company was acquired by West Shore Processing Company,
LLC ("West Shore") (98%), MarkWest Michigan LLC. ("MML") (1.2%) and Michigan
Energy Company LLC ("MEC") (.8%). West Shore is a newly formed entity which is
currently owned 95% by MEC and 5% by MML. MEC is also a newly formed Company
controlled by shareholders of Gas Fund, the entity which made loans to the
Company under the Credit Agreement described in Note 2.
The net assets of the Company, principally the pipeline and minor amounts of
working capital, were acquired in consideration for forgiveness of amounts due
by the Company to Gas Fund under the Credit Agreement. This transaction has
been accounted for in accordance with purchase accounting and, accordingly,
the purchase price of $10.4 million has been allocated to the property and
equipment ($10.3 million) and working capital ($.1 million) acquired based on
estimates of their relative fair values at the date of acquisition. The
amounts reflected in the June 30, 1996 balance sheet and the statements of
operations and of cash flows for the period from May 6, 1996 through June 30,
1996 reflect the revised basis of assets and liabilities resulting from the
change in ownership.
F-24
<PAGE>
MARKWEST HYDROCARBON, INC.
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The accompanying unaudited pro forma consolidated balance sheet and pro
forma consolidated statements of operations give effect to the reorganization
of the Company from a limited partnership into a corporation, to the
application of the net proceeds from the initial public offering of 2,400,000
shares of common stock in the Corporation, and to the planned acquisition of
an interest in Basin Pipeline, L.L.C., and are based on the assumptions set
forth in the notes to such statements. These adjustments have been presented
in two separate sets of pro forma financial statements. The Reorganization and
Offering Adjustments have been reflected in the first set of pro formas, with
the resultant balances being labeled "Pro Forma, As Adjusted." These
statements are presented on pages F-26 through F-28. The second set of pro
formas adjusts the Pro Forma, As Adjusted balances to give effect to the
planned acquisition of Basin, with the resultant balances labeled "Pro Forma
Combined." In addition, because the Company's interest in Basin at June 30,
1996 is 5.3% but is expected to increase to 60% by the end of 1997 separate
pro forma statements have been presented to reflect both ownership levels.
Although the Company would not consolidate Basin's financial statements until
it achieved control of Basin, full consolidation has been assumed at both
ownership levels for purposes of these presentations.
The unaudited pro forma consolidated financial statements comprise
historical financial data included elsewhere in this Prospectus which have
been retroactively adjusted to reflect the effect of the above proposed
transactions. The pro forma information assumes that the transactions were
consummated on June 30, 1996 for the pro forma consolidated balance sheet and
on January 1, 1995 for the pro forma consolidated statements of operations.
Such pro forma information should be read in conjunction with the related
historical financial information and is not necessarily indicative of the
results which would actually have occurred had the transactions been
consummated on the dates or for the periods indicated or which may occur in
the future.
F-25
<PAGE>
MARKWEST HYDROCARBON, INC.
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET
(PRO FORMA, AS ADJUSTED)
JUNE 30, 1996
($000S)
<TABLE>
<CAPTION>
MARKWEST
MARKWEST HYDROCARBON
HYDROCARBON PARTNERS, REORGANIZATION OFFERING PRO FORMA,
INC. LTD. ADJUSTMENTS ADJUSTMENTS AS ADJUSTED
----------- ----------- -------------- ----------- -----------
<S> <C> <C> <C> <C> <C>
ASSETS
Current assets:
Cash and cash
equivalents............ $ 1 $ 666 $ 229 (b) $ (615) (c) $ 281
Accounts receivable..... -- 3,588 -- -- 3,588
Product inventory....... -- 3,287 -- -- 3,287
Materials and supplies
inventory.............. -- 264 -- -- 264
Prepaid expenses and
other assets........... -- 359 -- -- 359
Prepaid feedstock....... -- 2,157 -- -- 2,157
---- -------- -------- -------- -------
Total current assets.... 1 10,321 229 (615) 9,936
---- -------- -------- -------- -------
Property, plant and
equipment, at cost..... -- 43,408 -- -- 43,408
Accumulated
depreciation, depletion
and amortization....... -- (10,810) -- -- (10,810)
---- -------- -------- -------- -------
Net property, plant and
equipment.............. -- 32,598 -- -- 32,598
---- -------- -------- -------- -------
Intangible assets, net
of accumulated
amortization........... -- 443 -- -- 443
Other assets............ 100 629 -- (100)(i) 629
---- -------- -------- -------- -------
Total assets............ $101 $ 43,991 $ 229 $ (715) $43,606
==== ======== ======== ======== =======
LIABILITIES AND EQUITY
Current liabilities:
Trade accounts payable.. $-- $ 4,430 $ -- $ -- $ 4,430
Accrued liabilities..... 100 418 -- (100)(i) 418
Interest payable........ -- 99 -- -- 99
Accrued bonus and profit
sharing................ -- 230 -- -- 230
---- -------- -------- -------- -------
Total current
liabilities............ 100 5,177 -- (100) 5,177
Deferred income taxes... -- -- 3,206 (a) -- 3,206
Long-term debt.......... -- 12,350 10,000 (d) (22,350)(g) --
---- -------- -------- -------- -------
Total liabilities....... 100 17,527 13,206 (22,450) 8,383
Minority interest....... -- -- -- -- --
Common stock............ -- -- 57 (f) 24 (h) 81
Additional Paid-in
Capital................ 1 -- 13,430 (f) 21,711 (h) 35,142
Partners' capital....... -- 26,464 (12,977)(e) -- --
(13,487)(f)
Retained earnings....... -- -- -- -- --
---- -------- -------- -------- -------
Partners'
capital/stockholders'
equity................. 1 26,464 (12,977) 21,735 35,223
---- -------- -------- -------- -------
Total liabilities and
equity................. $101 $ 43,991 $ 229 $ (715) $43,606
==== ======== ======== ======== =======
</TABLE>
F-26
<PAGE>
MARKWEST HYDROCARBON, INC.
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(PRO FORMA, AS ADJUSTED)
FOR THE YEAR ENDED DECEMBER 31, 1995
($000S, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
MARKWEST
MARKWEST HYDROCARBON
HYDROCARBON PARTNERS, REORGANIZATION OFFERING PRO FORMA,
INC. LTD. ADJUSTMENTS ADJUSTMENTS AS ADJUSTED
----------- ----------- -------------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Revenues:
Plant revenue........... $-- $33,823 $ -- $ -- $33,823
Terminal and marketing
revenue................ -- 13,172 -- -- 13,172
Oil and gas and other
revenue................ -- 1,075 -- -- 1,075
---- ------- ----- ------- -------
Total revenue........... -- 48,070 -- -- 48,070
---- ------- ----- ------- -------
Costs and Expenses:
Plant feedstock
purchases.............. -- 17,308 -- -- 17,308
Terminal and marketing
purchases.............. -- 11,937 -- -- 11,937
Operating expenses...... -- 4,706 -- -- 4,706
General and
administrative
expenses............... -- 4,189 -- -- 4,189
Depreciation, depletion
and amortization....... -- 1,754 -- -- 1,754
---- ------- ----- ------- -------
Total costs and
expenses............... -- 39,894 -- -- 39,894
---- ------- ----- ------- -------
Earnings (loss) from
operations............. -- 8,176 8,176
Interest income
(expense), net......... -- (352) -- 508 (j) 156
---- ------- ----- ------- -------
-- 7,824 508 8,332
Minority interest....... -- -- -- -- --
---- ------- ----- ------- -------
Income (loss) before
income taxes........... -- 7,824 508 8,332
(Provision) benefit for
income taxes........... -- -- -- (3,128)(k) (3,128)
---- ------- ----- ------- -------
Net income.............. $-- $ 7,824 $ -- $(2,620) $ 5,204
==== ======= ===== ======= =======
Weighted average common
shares outstanding..... 7,716 (t)
=======
Net income per common
share.................. $ .67
=======
</TABLE>
F-27
<PAGE>
MARKWEST HYDROCARBON, INC.
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(PRO FORMA, AS ADJUSTED)
FOR THE SIX MONTHS ENDED JUNE 30, 1996
($000S, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
MARKWEST
MARKWEST HYDROCARBON
HYDROCARBON PARTNERS, REORGANIZATION OFFERING PRO FORMA,
INC. LTD. ADJUSTMENTS ADJUSTMENTS AS ADJUSTED
----------- ----------- -------------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Revenues:
Plant revenue........... $-- $18,045 $ -- $ -- $18,045
Terminal and marketing
revenue................ -- 9,831 -- -- 9,831
Oil and gas and other
revenue................ -- 744 -- -- 744
---- ------- ----- ------- -------
Total revenue........... -- 28,620 -- -- 28,620
---- ------- ----- ------- -------
Costs and Expenses:
Plant feedstock
purchases.............. -- 8,538 -- -- 8,538
Terminal and marketing
purchases.............. -- 8,683 -- -- 8,683
Operating expenses...... -- 2,979 -- -- 2,979
General and
administrative
expenses............... -- 2,140 -- -- 2,140
Depreciation, depletion
and amortization....... -- 1,326 -- -- 1,326
---- ------- ----- ------- -------
Total costs and
expenses............... -- 23,666 -- -- 23,666
---- ------- ----- ------- -------
Earnings (loss) from
operations............. -- 4,954 4,954
Interest income
(expense), net......... -- (466) -- 509(j) 43
---- ------- ----- ------- -------
-- 4,488 509 4,997
Minority interest....... -- -- -- -- --
---- ------- ----- ------- -------
Income (loss) before
income taxes .......... -- 4,488 509 4,997
(Provision) benefit for
income taxes........... -- -- (1,859)(k) (1,859)
---- ------- ----- ------- -------
Pro forma net income.... $-- $ 4,488 $ -- $(1,350) $ 3,138
==== ======= ===== ======= =======
Weighted average common
shares outstanding..... 8,148 (t)
=======
Net income per common
share.................. $ .39
=======
</TABLE>
F-28
<PAGE>
MARKWEST HYDROCARBON, INC.
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET
(PRO FORMA COMBINED)
JUNE 30, 1996
($000S)
<TABLE>
<CAPTION>
BASIN
HISTORICAL PIPELINE PRO
PRO FORMA, BASIN ACQUISITION FORMA
AS ADJUSTED PIPELINE (U) ADJUSTMENTS COMBINED
----------- ------------ ----------- --------
<S> <C> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents..... $ 281 $ 9 $ (290) $ --
Accounts receivable........... 3,588 261 -- 3,849
Product inventory............. 3,287 -- -- 3,287
Materials and supplies
inventory.................... 264 -- -- 264
Prepaid expenses and other
assets....................... 359 8 -- 367
Prepaid feedstock............. 2,157 -- -- 2,157
------- ------- ------- -------
Total current assets.......... 9,936 278 (290) 9,924
------- ------- ------- -------
Property, plant and equipment,
at cost...................... 43,408 10,333 18,039 (l) 71,780
Accumulated depreciation,
depletion and amortization... (10,810) (80) -- (10,890)
------- ------- ------- -------
Net property, plant and
equipment.................... 32,598 10,253 18,039 60,890
------- ------- ------- -------
Intangible assets, net of
accumulated amortization..... 443 -- -- 443
Other assets.................. 629 -- (629)(m) --
------- ------- ------- -------
Total assets.................. $43,606 $10,531 $17,120 $71,257
======= ======= ======= =======
LIABILITIES AND EQUITY
Current liabilities:
Trade accounts payable........ $ 4,430 $ 93 $ -- $ 4,523
Accrued liabilities........... 418 32 -- 450
Interest payable.............. 99 -- 1,194 (l) 1,293
Accrued bonus and profit
sharing...................... 230 -- -- 230
------- ------- ------- -------
Total current liabilities..... 5,177 125 1,194 6,496
Deferred income taxes......... 3,206 -- -- 3,206
Long-term debt................ -- -- 15,926 (l) 15,926
------- ------- ------- -------
Total liabilities............. 8,383 125 17,120 25,628
Minority interest............. -- -- 10,406 (o) 10,406
Partners' capital/stockholders
equity:
Contributed capital........... -- 10,359 (10,359)(n) --
Common stock.................. 81 -- -- 81
Additional paid-in-capital.... 35,142 -- -- 35,142
Retained earnings............. -- 47 (47)(n) --
------- ------- ------- -------
Total partners
capital/stockholders equity.. 35,223 10,406 (10,406) 35,223
------- ------- ------- -------
Total liabilities and equity.. $43,606 $10,531 $17,120 $71,257
======= ======= ======= =======
</TABLE>
F-29
<PAGE>
MARKWEST HYDROCARBON, INC.
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(PRO FORMA COMBINED)
FOR THE YEAR ENDED DECEMBER 31, 1995
($000S, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
BASIN
PIPELINE
ACQUISITION
HISTORICAL ADJUSTMENTS PRO
PRO FORMA, BASIN @ 5.3% FORMA
AS ADJUSTED PIPELINE OWNERSHIP COMBINED
----------- ---------- ----------- --------
<S> <C> <C> <C> <C>
Revenues:
Plant revenue................ $33,823 $ -- $ -- $33,823
Terminal and marketing
revenue..................... 13,172 -- -- 13,172
Oil and gas and other
revenue..................... 1,075 841 -- 1,916
------- ------- ------ -------
Total revenue................ 48,070 841 -- 48,911
------- ------- ------ -------
Costs and Expenses:
Plant feedstock purchases.... 17,308 -- -- 17,308
Terminal and marketing
purchases................... 11,937 -- -- 11,937
Operating expenses........... 4,706 669 -- 5,375
General and administrative
expenses.................... 4,189 205 -- 4,394
Depreciation, depletion and
amortization................ 1,754 900 -- 2,654
------- ------- ------ -------
Total costs and expenses..... 39,894 1,774 -- 41,668
------- ------- ------ -------
Earnings (loss) from
operations.................. 8,176 (933) -- 7,243
Interest income (expense),
net......................... 156 (1,100) 1,100 (q) 156
------- ------- ------ -------
8,332 (2,033) 1,100 7,399
Minority interest............ -- -- 884 (p) 884
------- ------- ------ -------
Income (loss) before income
taxes....................... 8,332 (2,033) 1,984 8,283
(Provision) benefit for
income taxes................ (3,128) -- 18 (k) (3,110)
------- ------- ------ -------
Net income................... $ 5,204 $(2,033) $2,002 $ 5,173
======= ======= ====== =======
Weighted average common
shares outstanding.......... 7,716(t) 7,716(t)
======= =======
Net income per common share.. $ .67 $ .67
======= =======
</TABLE>
F-30
<PAGE>
MARKWEST HYDROCARBON, INC.
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(PRO FORMA COMBINED)
FOR THE YEAR ENDED DECEMBER 31, 1995
($000S, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
BASIN
PIPELINE
ACQUISITION
HISTORICAL ADJUSTMENTS PRO
PRO FORMA, BASIN @ 60% FORMA
AS ADJUSTED PIPELINE OWNERSHIP COMBINED
----------- ---------- ----------- --------
<S> <C> <C> <C> <C>
Revenues:
Plant revenue............... $33,823 $ -- $ -- $33,823
Terminal and marketing
revenue.................... 13,172 -- -- 13,172
Oil and gas and other
revenue.................... 1,075 841 -- 1,916
------- ------- ------ -------
Total revenue............... 48,070 841 -- 48,911
------- ------- ------ -------
Costs and Expenses:
Plant feedstock purchases... 17,308 -- -- 17,308
Terminal and marketing
purchases.................. 11,937 -- -- 11,937
Operating expenses.......... 4,706 669 -- 5,375
General and administrative
expenses................... 4,189 205 -- 4,394
Depreciation, depletion and
amortization............... 1,754 900 -- 2,654
------- ------- ------ -------
Total costs and expenses.... 39,894 1,774 -- 41,668
------- ------- ------ -------
Earnings (loss) from
operations................. 8,176 (933) -- 7,243
Interest income (expense),
net........................ 156 (1,100) 1,100(q) 156
------- ------- ------ -------
8,332 (2,033) 1,100 7,399
Minority interest........... -- -- 373(p) 373
------- ------- ------ -------
Income (loss) before income
taxes...................... 8,332 (2,033) 1,473 7,772
(Provision) benefit for
income taxes............... (3,128) -- 210(k) (2,918)
------- ------- ------ -------
Net income.................. $ 5,204 $(2,033) $1,683 $ 4,854
======= ======= ====== =======
Weighted average common
shares outstanding......... 7,716 (t) 7,716 (t)
======= =======
Net income per common
share...................... $ .67 $ .63
======= =======
</TABLE>
F-31
<PAGE>
MARKWEST HYDROCARBON, INC.
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(PRO FORMA COMBINED)
FOR THE SIX MONTHS ENDED JUNE 30, 1996
($000S, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
BASIN
PIPELINE
ACQUISITION
HISTORICAL ADJUSTMENTS PRO
PRO FORMA, BASIN @ 5.3% FORMA
AS ADJUSTED PIPELINE OWNERSHIP COMBINED
----------- ---------- ----------- --------
<S> <C> <C> <C> <C>
Revenues:
Plant revenue............... $18,045 $ -- $ -- $18,045
Terminal and marketing
revenue.................... 9,831 -- -- 9,831
Oil and gas and other
revenue.................... 744 534 -- 1,278
------- ----- ----- -------
Total revenue............... 28,620 534 -- 29,154
------- ----- ----- -------
Costs and Expenses:
Plant feedstock purchases... 8,538 -- -- 8,538
Terminal and marketing
purchases.................. 8,683 -- -- 8,683
Operating expenses.......... 2,979 295 -- 3,274
General and administrative
expenses................... 2,140 72 -- 2,212
Depreciation, depletion and
amortization............... 1,326 380 427 (r) 2,133
------- ----- ----- -------
Total costs and expenses.... 23,666 747 427 24,840
------- ----- ----- -------
Earnings (loss) from
operations................. 4,954 (213) (427) 4,314
Interest income (expense),
net........................ 43 (516) 516 (q) (554)
(597)(s)
------- ----- ----- -------
4,997 (729) (508) 3,760
Minority interest........... -- -- 1,171 (p) 1,171
------- ----- ----- -------
Income (loss) before income
taxes...................... 4,997 (729) 663 4,931
(Provision) benefit for
income taxes............... (1,859) -- 24 (k) (1,835)
------- ----- ----- -------
Pro forma net income........ $ 3,138 $(729) $ 687 $ 3,096
======= ===== ===== =======
Weighted average common
shares outstanding......... 8,148 (t) 8,148 (t)
======= =======
Net income per common
share...................... $ .39 $ .38
======= =======
</TABLE>
F-32
<PAGE>
MARKWEST HYDROCARBON, INC.
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(PRO FORMA COMBINED)
FOR THE SIX MONTHS ENDED JUNE 30, 1996
($000S, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
BASIN
PIPELINE
ACQUISITION
HISTORICAL ADJUSTMENTS PRO
PRO FORMA, BASIN @ 60% FORMA
AS ADJUSTED PIPELINE OWNERSHIP COMBINED
----------- ---------- ----------- --------
<S> <C> <C> <C> <C>
Revenues:
Plant revenue............... $18,045 $ -- $-- $18,045
Terminal and marketing
revenue.................... 9,831 -- -- 9,831
Oil and gas and other
revenue.................... 744 534 -- 1,278
------- ----- ---- -------
Total revenue............... 28,620 534 -- 29,154
------- ----- ---- -------
Costs and Expenses:
Plant feedstock purchases... 8,538 -- -- 8,538
Terminal and marketing
purchases.................. 8,683 -- -- 8,683
Operating expenses.......... 2,979 295 -- 3,274
General and administrative
expenses................... 2,140 72 -- 2,212
Depreciation, depletion and
amortization............... 1,326 380 427 (r) 2,133
------- ----- ---- -------
Total costs and expenses.... 23,666 747 427 24,840
------- ----- ---- -------
Earnings (loss) from
operations................. 4,954 (213) (427) 4,314
Interest income (expense),
net........................ 43 (516) 516 (q) (554)
(597)(s)
------- ----- ---- -------
4,997 (729) (508) 3,760
Minority interest........... -- -- 495 (p) 495
------- ----- ---- -------
Income (loss) before income
taxes...................... 4,997 (729) (13) 4,255
(Provision) benefit for
income taxes............... (1,859) -- 276 (k) (1,583)
------- ----- ---- -------
Pro forma net income........ $ 3,138 $(729) $263 $ 2,672
======= ===== ==== =======
Weighted average common
shares outstanding......... 8,148 (t) 8,148 (t)
======= =======
Net income per common
share...................... $ .39 $ .33
======= =======
</TABLE>
F-33
<PAGE>
MARKWEST HYDROCARBON, INC.
NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
- --------
(a) Represents the estimated deferred taxes to be recorded when the
Partnership reorganizes into a corporation and, consequently, becomes a
taxable entity.
(b) Represents receipt of cash from employees who financed their acquisition
of stock with notes receivable and proceeds received upon exercise of
options.
(c) Represents the use of cash, together with net proceeds of the Offering, to
retire debt of $22.4 million, including the debt incurred to fund the
$10.0 million Partnership Distribution.
(d) Represents debt incurred to fund the Partnership Distribution.
(e) Represents decreases in partners' capital resulting from the Partnership
Distribution and the deferred taxes recorded upon the Reorganization (see
(a) above), offset by increases resulting from cash received as described
in (b) above.
(f) Represents the issuance of shares in exchange for the contribution of
partners' capital.
(g) Reflects the retirement of existing debt with existing cash and proceeds
from the Offering.
(h) Represents the issuance of shares for net proceeds from the Offering of
$21.7 million.
(i) Represents the elimination of deferred offering costs and the related
accrued liabilities because these have been reflected in the computation
of net proceeds.
(j) Reflects the elimination of the historical interest expense of the Company
because all outstanding debt is assumed to be retired with the proceeds of
the Offering.
(k) Represents the income tax effects of the pro forma adjustments to income
as well as the pro forma provision for income taxes assuming the Company
will be a taxable entity after the reorganization.
(l) Reflects the planned increase in the investment in Basin Pipeline, L.L.C.
of $16.2 million, funded by the $.3 million remaining cash after the
Offering and $15.9 million in borrowings. While the planned investment is
expected to be made through capital expenditures over a period of
approximately 18 months, the entire amount is reflected as if it had been
invested on June 30, 1996 for purposes of the pro forma balance sheet at
that date and as if it had been invested on January 1, 1995 for purposes
of the pro forma statements of operations for the year ended December 31,
1995 and for the six months ended June 30, 1996. Since the assets will be
under construction for approximately 12 months, no depreciation expense
has been recorded for the year ended December 31, 1995 and all interest
expense assumed to be incurred during 1995 ($1.2 million using an interest
rate of 7.5%) has been capitalized. A change of .125% in the assumed
interest rate would result in an increase or decrease of $20,000 in the
amount of capitalized interest. Finally, while the planned investment will
be made in increments through capital expenditures and may never be made
up to the $16.2 million level, the full amount, which represents a 60%
interest in Basin, has been reflected for pro forma purposes.
(m) Represents reclassification of the initial investment in Basin from other
assets to property, plant and equipment.
(n) Represents the elimination of the book equity accounts of Basin.
(o) Represents the 40% minority interest in Basin, assuming the Company owns
60% of Basin as discussed in (l) above.
(p) Represents the 40% minority interest impact of the Basin adjustments.
(q) Represents the elimination of the historical interest expense of Basin
because all debt of Basin was forgiven prior to and as a condition of the
Company's investment in Basin.
(r) Represents depreciation expense on the property, plant and equipment
constructed with the amounts invested by the Company, assuming such assets
were under construction for all of 1995 and were placed in service
effective January 1, 1996. The total cost of the assets constructed is
estimated to be $18.0 million, including $1.2 million of capitalized
interest, and is depreciated using the straight-line method over the
estimated useful life of the assets of 20 years. The historical
depreciation expense of Basin was not adjusted to reflect the new basis of
the assets resulting from the acquisition because such adjustment was not
material.
(s) Represents interest expense at 7.5% on the amount assumed to be borrowed
in conjunction with the Basin acquisition (see (l) above). A change of
.125% in the assumed interest rate would result in an increase or decrease
in interest expense of $10,000.
(t) Represents the weighted average number of common shares outstanding during
the applicable period, which is computed by adding the number of common
and common equivalent shares issued in the Reorganization, which are
assumed to be outstanding for all periods presented, to the number of
shares issued in the Offering for which the net proceeds will be used to
repay average outstanding indebtedness during the applicable period,
including the indebtedness incurred to fund the Partnership Distribution.
(u) The Company's investment is in West Shore Processing Company, LLC, which
owns assets other than its investment in Basin. However, such assets are
of minimal value and, consequently, have not been reflected in the
unaudited pro forma condensed consolidated financial statements.
F-34
<PAGE>
At the top center of the inside back cover page, within a text box, is the
phrase "The Critical Link between the Gas Well and the Market is provided by"
followed by the MarkWest logo.
Below that, arranged from left to right on the page are several icons
depicting five different phases of natural gas lifecycle, beginning with
"Exploration & Production" and ending with "End-Use Customers."
The following icons and narrative descriptions are included on the page:
Natural Gas Wellhead icon labeled "Exploration & Production" followed by two
narrative phrases (3rd party natural gas production) and (planned exploration
activity in Michigan); Pipeline icon labeled "Gas Gathering & Compression"
followed by two narrative phrases (31 mile regulated pipeline in Michigan) and
(50+ mile Michigan planned expansion); Natural Gas Refinery Plant icon labeled
"Gas Processing Services" followed by four narrative phrases (2 extraction
plants in Appalachia), (1 NGL Fractionator in Appalachia), (38 mile NGL
pipeline in Appalachia) and (1 planned Extraction/Fractionation plant in
Michigan); Barge, train car and tanker truck icons labeled "Marketing Services"
followed by six narrative phrases (West Memphis, AR Terminal), (Church Hill, TN
Terminal), (Mined Siloam, KY Caverns), (7 owned LPG transport trailers), (Fleet
of 70+ rail cars) and (Marketing contracts & programs); and House, factory and
home propane storage tank icons labeled "End-Use Customers" followed by four
narrative phrases (Gas Consumers), (Petrochemical Plants), (Refineries) and
(LPG Fuel Users).
<PAGE>
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFOR-
MATION OR TO MAKE ANY REPRESENTATION OTHER THAN THOSE CONTAINED IN THIS PRO-
SPECTUS IN CONNECTION WITH THE OFFER CONTAINED HEREIN, AND IF GIVEN OR MADE,
SUCH INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS HAVING BEEN AU-
THORIZED BY THE COMPANY OR ANY UNDERWRITER. THIS PROSPECTUS DOES NOT CONSTI-
TUTE AN OFFER TO SELL, OR A SOLICITATION OF AN OFFER TO BUY, SHARES OF COMMON
STOCK IN ANY JURISDICTION TO ANY PERSON TO WHOM IT IS NOT LAWFUL TO MAKE ANY
SUCH OFFER OR SOLICITATION IN SUCH JURISDICTION OR IN WHICH THE PERSON MAKING
SUCH OFFER OR SOLICITATION IS NOT QUALIFIED TO DO SO. NEITHER THE DELIVERY OF
THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES,
CREATE AN IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COM-
PANY SINCE THE DATE HEREOF.
---------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Prospectus Summary....................................................... 3
Risk Factors............................................................. 10
Reorganization........................................................... 17
Use of Proceeds.......................................................... 18
Dividend Policy.......................................................... 18
Dilution................................................................. 19
Capitalization........................................................... 20
Selected Consolidated Financial and Other Information.................... 21
Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................... 23
Business................................................................. 30
Management............................................................... 46
Certain Transactions..................................................... 52
Principal Stockholders................................................... 55
Description of Capital Stock............................................. 57
Shares Eligible for Future Sale.......................................... 59
Underwriting............................................................. 60
Legal Matters............................................................ 61
Experts.................................................................. 61
Additional Information................................................... 62
Financial Statements..................................................... F-1
</TABLE>
---------------
UNTIL NOVEMBER 4, 1996 (25 DAYS AFTER THE DATE OF THIS PROSPECTUS), ALL
DEALERS EFFECTING TRANSACTIONS IN THE REGISTERED SECURITIES, WHETHER OR NOT
PARTICIPATING IN THIS DISTRIBUTION, MAY BE REQUIRED TO DELIVER A PROSPECTUS.
THIS IS IN ADDITION TO THE OBLIGATION OF DEALERS TO DELIVER A PROSPECTUS WHEN
ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UNSOLD ALLOTMENTS OR
SUBSCRIPTIONS.
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
[LOGO OF MARKWEST APPEARS HERE]
MARKWEST HYDROCARBON, INC.
---------------
2,400,000 SHARES
COMMON STOCK
PROSPECTUS
OCTOBER 9, 1996
---------------
DILLON, READ & CO. INC.
GEORGE K. BAUM & COMPANY
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
