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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] Annual report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934 for the fiscal year ended December 31, 1999.
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the transition period from __________ to
____________.
COMMISSION FILE NUMBER 1-11566
MARKWEST HYDROCARBON, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 84-1352233
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
155 INVERNESS DRIVE WEST, SUITE 200, ENGLEWOOD, CO 80112-5000
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 303-290-8700
Securities registered pursuant to Section 12(b) of the Act: COMMON STOCK, $0.01
PAR VALUE, AMERICAN STOCK EXCHANGE
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes __X__ No _____
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. ____
The aggregate market value of voting common stock held by non-affiliates of the
registrant on February 29, 2000, was $28,545,586.
The number of shares outstanding of the registrant's common stock as of February
29, 2000, was 8,449,816.
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Report (Items 10, 11, 12 and 13) is
incorporated by reference from the registrant's proxy statement to be filed
pursuant to Regulation 14A with respect to the annual meeting of stockholders
scheduled to be held on May 18, 2000.
1
MARKWEST HYDROCARBON, INC.
FORM 10-K
TABLE OF CONTENTS
PAGE
----
PART I
Items 1. and 2. Business and Properties
General.................................................................................................. 3
Strategy................................................................................................. 3
Significant 1999 Developments............................................................................ 3
Segments................................................................................................. 4
Processing and Related Services.......................................................................... 4
Exploration and Production............................................................................... 7
Seasonality.............................................................................................. 7
Competition ............................................................................................. 7
Operational Risks and Insurance.......................................................................... 7
Governmental Regulation.................................................................................. 8
Environmental Matters.................................................................................... 8
Employees................................................................................................ 8
Risk Factors............................................................................................. 9
Item 3. Legal Proceedings................................................................................. 9
Item 4. Submission of Matters to a Vote of Security Holders............................................... 9
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters......................... 9
Item 6. Selected Financial Data........................................................................... 10
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations............. 12
Item 7A. Quantitative and Qualitative Disclosures About Market Risk........................................ 15
Item 8. Financial Statements and Supplementary Data....................................................... 17
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.............. 35
PART III
Item 10. Directors and Executive Officers of the Registrant................................................ 35
Item 11. Executive Compensation............................................................................ 35
Item 12. Security Ownership of Certain Beneficial Owners and Management.................................... 35
Item 13. Certain Relationships and Related Transactions.................................................... 35
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.................................. 35
GLOSSARY OF TERMS
bbls barrels
Btu British thermal unit, an energy measurement
EBITDA earnings before gain on sale, interest income, interest expense,
income taxes, depreciation, depletion and amortization; a cash flow
financial measure commonly used in the oil and gas industry
Mcf thousand cubic feet of natural gas
Mcfd thousand cubic feet of natural gas per day
MMBtu million British thermal units
MMcf million cubic feet of natural gas
MMcfd million cubic feet of natural gas per day
NGL natural gas liquids, such as propane, butanes and natural gasoline
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PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
GENERAL
MarkWest Hydrocarbon, Inc., and its subsidiaries (referred to collectively as
the "Company" or "MarkWest") provide natural gas processing and related services
and conduct strategic exploration for new natural gas sources. The Company's
natural gas processing and related activities include providing compression,
gathering, treatment and NGLs extraction services to natural gas producers and
pipeline companies. Additionally, MarkWest fractionates NGLs into marketable
products and purchases and markets natural gas and NGLs. MarkWest provides
natural gas processing and related services through its modern, efficient plant
and pipeline systems. Increased drilling for natural gas to meet expanding
demand is driving growth for MarkWest's specialized services. Natural gas
producers are increasingly outsourcing the complex task of converting raw
natural gas produced at the wellhead to marketable natural gas and natural gas
liquids. MarkWest is the largest processor of natural gas in Appalachia and is
growing rapidly, and the Company owns the only sour gas gathering and processing
facilities in western Michigan. The Company also conducts strategic exploration
for new natural gas sources for its processing services, primarily in the Rocky
Mountains and Michigan.
The Company was founded as a partnership in 1988 and incorporated in Delaware in
1996. The Company's principal executive office is located at 155 Inverness Drive
West, Suite 200, Englewood, Colorado, 80112-5000, and its telephone number is
(303) 290-8700. MarkWest maintains an NGL marketing office in Columbus, Ohio and
a gas marketing and Appalachia producer relations office in Pittsburgh,
Pennsylvania.
STRATEGY
MarkWest's strategy is to provide trend-line profit growth exceeding 15%
annually by increasing volumes of natural gas processed and volumes of NGLs
produced and marketed. The Company focuses on geographic core areas where
natural gas production is expected to increase, providing opportunities for
reinvestment. This focus allows MarkWest to capitalize on its infrastructure for
the benefit of its customers and its shareholders. Innovative engineering,
cost-efficient operations and effective NGL marketing are core competencies of
the Company. MarkWest also uses exploration to enhance its gas processing
business.
The Company aims to reduce earnings volatility through emphasis on fee-based
services not susceptible to changes in commodity prices and through increasing
hedging activities in 2000 and beyond. Fee-based services have increased to
account for approximately 50% of gross margins in 2000 from less than 10% six
years ago.
SIGNIFICANT 1999 DEVELOPMENTS
During 1999, MarkWest signed two significant long-term agreements that will
nearly double the Company's Appalachian production over the next two years. In
order to accommodate the expected production increase, MarkWest launched a
two-phase expansion of its Appalachian infrastructure.
Phase I expansion was completed in February 2000, and, together with higher
production from increased regional drilling, MarkWest expects to see NGL volumes
increase from 310,000 gallons per day in 1999 to 460,000 gallons in 2000. This
expansion added a new 75 MMcfd, mechanical refrigeration, NGL extraction plant
("Maytown") in southern Kentucky and nearly doubled the capacity, from 350,000
gallons per day to 600,000 gallons per day, of the Company's fractionator
("Siloam") in northern Kentucky. Revenues to be derived from the expansion are
primarily fee and percent-of-proceeds based, which differ from MarkWest's
historical commodity-based contracts. Finally, MarkWest acquired a 40-mile NGL
pipeline in West Virginia. This pipeline, together with MarkWest's existing
pipeline and a pipeline leased in 1999, forms a continuous 180-mile pipeline
network through the southern portion of the Appalachia Basin. The pipeline
connects MarkWest's new Maytown gas plant to MarkWest's Siloam fractionator and
significantly reduces feedstock transportation costs from another of MarkWest's
gas plants--Boldman. MarkWest's Kenova gas plant is already connected to the
pipeline. Boldman and Kenova are located in Kentucky and West Virginia,
respectively.
Volumes to the Siloam fractionator will continue to grow as Phase II expansion
proceeds. Phase II involves expanding MarkWest's Kenova NGL extraction plant,
increasing MarkWest's total production to 550,000 gallons per day. Phase II
construction is expected to commence mid-2000 for startup in mid-2001. Capital
spending for the Phase I and II expansions is estimated at $26 million.
In October 1999, all outstanding arbitration and litigation with Columbia Gas
Transmission Corporation ("Columbia") was settled. As part of the settlement,
MarkWest assumed operations of its Boldman plant--previously leased to and
operated by Columbia--on February 1, 2000, and purchased the Cobb plant from
Columbia on March 1, 2000, for $0.9 million. Both plants continue to provide
unfractionated NGLs to the Company's Siloam fractionator.
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The Company sold its propane terminal in West Memphis, Arkansas, for $5.5
million in May 1999 because the propane terminal was too remote from
MarkWest's other Appalachian assets. In November 1999, the Company acquired a
propane terminal in Lynchburg, Virginia, for $2.1 million. In February 2000,
MarkWest sold its corporate office building for $5.0 million in net proceeds.
In Arenac County in eastern Michigan, MarkWest announced in January 2000 the
new Au Gres gas production and processing project. In the first phase of the
project, MarkWest expects to bring an existing well into production by
mid-second quarter 2000. The second phase of the project is expected to begin
in late 2000 or early 2001 and will involve bringing another four wells into
production. MarkWest also has a 25% working interest in the field.
SEGMENTS
The Company's business activities are segregated into two segments: processing
and related services, and exploration and production. However, processing and
related services are the Company's primary focus. The two segments are located
in three core geographic areas: Appalachia, Michigan, and the Rocky Mountains.
Processing and related services are concentrated in two core areas: the
significant gas-producing basin in the southern Appalachian region of eastern
Kentucky, southern West Virginia, and southern Ohio (the "Appalachian Core Area"
or "Appalachia"); and the developing basins in eastern and western Michigan (the
"Michigan Core Area" or "Michigan"). Exploration and production activities are
concentrated in the Rocky Mountains and Michigan. These segments are analyzed
independently by management and derive revenue from different sources. For
financial information related to each segment, see RESULTS OF OPERATIONS, in
Item 7 - Management's Discussion and Analysis of Financial Condition and Results
of Operations, as well as Note 11, SEGMENT REPORTING, in the Notes to the
Consolidated Financial Statements in Item 8 of this Form 10-K.
PROCESSING AND RELATED SERVICES
APPALACHIAN CORE AREA
The Company owns and operates in Appalachia four gas processing facilities, one
fractionation plant, a NGL pipeline and two propane terminals. Certain
information concerning the Appalachian assets is summarized in the following
tables:
For the Year Ended
Year December 31, 1999
Acquired ----------------------------------------
or Placed Gas NGL Production
into Throughput Throughput Throughput
Plant Facilities Location Service Capacity (Mcfd) (Gal/Year)
- -------------------------------- ---------------------- ---------- ----------------- ----------------- ------------------
Boldman Extraction Plant (1) Pike County, KY 1991 70,000 Mcfd 50,000 10,462,000
Cobb Extraction Plant (2) Kanawha County,WV 2000 35,000 Mcfd 27,000 20,384,000
Kenova Extraction Plant Wayne County, WV 1996 120,000 Mcfd 120,000 74,897,000
Maytown Extraction Plant (4) Floyd County, KY 2000 55,000 Mcfd -- --
Siloam Fractionation Plant South Shore, KY 1988 600,000 Gal/d N/A 112,983,000 (3)
Year Sales for the
Acquired Year Ended
or Placed Throughput Storage December 31,
Storage and into Length Capacity Capacity 1999
Transmission Facilities Location Service in Miles (Gal/d) (Gal) (Gal) (3)
- -------------------------------- --------------------- ----------- ---------- ------------- ------------ ---------------
Siloam Fractionation Storage South Shore, KY 1988 N/A N/A 14,000,000 115,843,000
Terminal and Storage (5) Lynchburg, VA 1999 N/A N/A 270,000 3,352,000
Terminal and Storage Church Hill, TN 1995 N/A N/A 240,000 4,816,000
Kenova to Siloam pipeline Wayne County, WV to 1988 38.5 831,000 N/A N/A
South Shore, KY
Maytown to Kenova pipeline (6) Lincoln County to 2000 140.0 160,000 N/A N/A
Wayne County, WV
(1) MarkWest assumed operations effective February 1, 2000. Previously,
Boldman was leased to and operated by a third party.
(2) Cobb was acquired March 1, 2000. Cobb was originally placed in service in
1968 and its extracted NGLs have historically been fractionated at Siloam.
(3) Includes fractionation of NGLs extracted at Kenova, Boldman and Cobb
listed above.
4
(4) Maytown was placed into service in February 2000. Maytown can be expanded
to 75,000 Mcfd for a modest amount of capital.
(5) Lynchburg was acquired on November 1, 1999. Sales volumes are for the
November 1, 1999, through December 31, 1999, time period.
(6) A portion of the pipeline is leased from a third party.
The Company's Appalachian operations are in the midst of a sizable expansion,
growing production from 310,000 gallons per day in 1999 to 550,000 gallons per
day by mid-2001. See SIGNIFICANT 1999 DEVELOPMENTS earlier in this section for
further information.
The Company believes this region has favorable supply and demand
characteristics. The Appalachian Core Area is geographically situated between
the TET pipeline to the north and the Dixie pipeline to the south. The
historical demand for NGL products in Appalachia has exceeded local production
and the capacity of these two lines during peak winter periods. This factor has
enabled NGL suppliers in Appalachia (principally MarkWest, Marathon Ashland
Petroleum LLC and CNG Transmission Corporation) to price their products
(particularly propane) at a premium to Gulf Coast spot prices, especially during
winter high demand periods.
There are approximately 10,000 wells behind the Company's NGL extraction plants
in Appalachia. This producing basin is one of the country's oldest, but is still
one of the most prolific. In fact, gas volumes continue to grow to new records
each year, as producers increase the number of new wells drilled each year.
Growing production drilling can be attributed to higher gas prices in an area
close to the high-demand northeast U.S., improved drilling technologies, and
cost reductions, all of which add up to improved economic returns for producers.
There are tens of thousands of proved but undrilled locations in Appalachia,
which bodes well for future expansion of MarkWest's strategically-located,
cost-effective processing and marketing assets.
The Kenova, Boldman, Cobb and Maytown plants extract liquids from natural gas
for further separation at the Company's Siloam fractionator. All of the NGLs
recovered at the Kenova, Maytown and Boldman plants--beginning February 2000,
Boldman NGLs are transported to Maytown via tanker trucks--are sent to Siloam
via pipeline. Cobb liquids are transported to Siloam via tanker trucks. At the
Company's Siloam fractionation plant, extracted NGLs are separated into NGL
products, including propane, isobutane, normal butane and natural gasoline. In
addition to processing and NGL marketing, the Company engages in terminaling and
storage of NGLs in a number of NGL storage complexes in the central and eastern
United States and owns and operates propane terminals in Virginia, Tennessee,
and, beginning March 2000, Ohio.
MarkWest has contracted with producers for the exclusive right to process the
producers' hydrocarbon-rich gas currently delivered into producer-owned and
Columbia-owned transmission pipelines upstream of the Company's plants under
long term contracts. MarkWest also has long term operating agreements with
Columbia.
The Company currently processes natural gas under contracts containing both
keep-whole and fee components. In keep-whole arrangements, the Company's
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 Btus. While the Company maintains programs to minimize the
cost to deliver the replacement Btus to the natural gas supplier, the Company's
margins under keep-whole contracts can be negatively affected by either
decreases in NGL prices or increases in prices of replacement natural gas.
Processing contracts with producers also contain a fee component under which the
producers pay MarkWest a fee to process their gas and provide a portion of their
gas for fuel. The fee may be a per unit of throughput charge or a percentage of
the resulting NGL sales ("percent-of-proceeds") or some combination of both.
Until 2000, substantially all of the Company's fractionation services in its
Appalachian Core Area are provided under keep-whole contracts. The contract for
processing services at the new Maytown plant contains fee and
percent-of-proceeds components.
The Company attempts to maximize the value of its NGL output by marketing
directly to distributors, resellers, blenders, refiners and petrochemical
companies. The Company minimizes the use of third-party brokers and instead
supports a direct marketing staff focused on multistate and independent dealers.
Additionally, the Company uses its own trailer and railcar fleet, as well as its
own terminals and storage facilities, to enhance supply reliability to its
customers. All of these efforts have allowed the Company to maintain premium
pricing for the majority of its NGL products compared to Gulf Coast spot prices.
The majority of the Company's sales of NGLs are based on spot prices at the time
the NGLs are sold. Spot market prices are based upon prices and volumes
negotiated for short terms, typically 30 days. The Company is increasing its
hedging activities as described in Note 7, COMMODITY PRICE RISK MANAGEMENT, in
the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.
Historically, the majority of the Company's operating income has been derived
from processing and related services in its Appalachian Core Area. Revenues from
the sale of Appalachian NGLs represented 52%, 68%, and 85% of gathering,
processing and marketing revenues for the years ended December 31, 1999, 1998,
and 1997, respectively. In 1998, the Company started a natural gas marketing
group to provide, primarily in Appalachia, more services to natural gas
producers, source new gas for the Company's facilities, minimize its replacement
Btu cost, and assist with its business development efforts. The Company's
natural gas marketing
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activities are fundamentally high volume, low margin transactions executed in
support of MarkWest's processing business. Consequently, an increasing
percentage of the Company's overall revenues stem from gas marketing. For the
years ended December 31, 1999, 1998 and 1997, 33%, 9%, and 0%, respectively, of
gathering, processing and marketing revenue stemmed from gas marketing.
MICHIGAN CORE AREA
For the Year Ended
Year December 31, 1999
Acquired -----------------------------------
or Placed Throughput Gas NGL Production
into Capacity Throughput Throughput
Facilities Location Service (Mcfd) (Mcfd) (Gal/Year)
- ------------------------------- ---------------------- ----------- --------------- --------------- ----------------
90-mile sour gas gathering Manistee, Mason and 1996 (1) 35,000 17,800 N/A
pipeline Oceana Counties, MI
Fisk Gas Plant Manistee County, MI 1998 35,000 17,800 13,500,000
(1) Extended from 31 miles in 1996 to 63 miles in 1997 and 90 miles in 1998.
The Company's operations in western Michigan consist of a pipeline and
processing plant. The Company's gas gathering pipeline gathers and transports
sour gas to a treatment plant, used to remove sulphur, owned and operated by a
third party. MarkWest's Fisk processing plant is located adjacent to the third
party's treating plant. The Fisk plant processes all of the natural gas gathered
by the pipeline and treated by the third party's treating plant, producing
propane and other liquid products. The plant also conditions the residue gas
such that it can be sold directly into the Michigan Consolidated Gas Company dry
distribution system serving western Michigan.
The Company currently processes natural gas in western Michigan under contracts
containing both fee and percent-of-proceeds components. The processing contracts
with producers contain a fee component under which the producers pay MarkWest a
fee to transport and treat their gas. Under the percent-of-proceeds component,
the Company retains a portion of the NGLs as compensation for the processing
services provided. Operating revenues earned by the Company under
percent-of-proceeds contracts increase proportionately with the price of NGLs
sold. The Company generally sells its propane production as soon as it is
produced. The Company's butane-natural gasoline production is transported across
the state via tanker trucks to the Marysville Fractionator, where it is
separated into NGL products, including isobutane, normal butane and natural
gasoline.
Since commencing operations in 1996, throughput volumes have steadily risen.
Throughput volumes in 1999 were 17.8 MMcfd, up 11% over 1998 volumes. Year 2000
throughput volumes are expected to be about the same as 1999's throughput
volumes, without considering year 2000 drilling programs. Low commodity prices
in 1998 and the first half of 1999 have curtailed producer capital programs.
Consequently, little drilling took place in western Michigan in 1999. New
drilling is critical to maintaining and increasing volumes. Drilling activity in
the next few years will determine the sustainable production level for the
project. While drilling activity and drilling success have been slow to develop,
MarkWest's own exploration efforts, along with third-party partners, continue to
identify good prospects along the 90-mile pipeline corridor. MarkWest expects to
drill and evaluate a minimum of three additional reefs by the end of second
quarter 2000.
MarkWest has exclusive gathering, treatment and processing agreements with
certain producers. Expected natural gas streams dedicated under these agreements
will primarily be produced from an extension of the Northern Niagaran Reef trend
in western Michigan. To date, over 2.5 trillion cubic feet equivalent of natural
gas has been produced from the Northern Niagaran Reef trend. Substantially all
of the natural gas produced from the western region of this trend, however, is
sour. In the past, while several successful large wells were developed in the
region, the natural gas producers lacked adequate gathering and treatment
facilities for sour gas, and development of the trend stopped in northern
Manistee County. However, with the Company's recently expanded infrastructure of
the sour gas pipeline, treatment and processing facilities and increased
capacity, the Company has seen and believes there could continue to be increased
development in the region. In addition, the Company believes that improvements
in seismic technology may increase exploration and production efforts, as well
as drilling success rates.
In eastern Michigan, the Company contracted with a producer to provide gas
processing services for a long-dormant sour gas formation. MarkWest also has a
25% working interest in the field. In the first phase of the project, MarkWest
is obtaining required permits, constructing a well facility, modifying an
existing gas plant and constructing a pipeline to bring an existing well into
production from this formation. It is anticipated that the first phase will be
completed by mid-second quarter 2000 at a cost to
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MarkWest of $1.4 million. The second phase of the project is expected to begin
in late 2000 or early 2001 and will involve bringing another four wells into
production and constructing additional processing facilities. These wells have
never produced from this formation due to the lack of infrastructure. Management
believes the project has the potential to grow into a significant contributor to
MarkWest.
EXPLORATION AND PRODUCTION
ROCKY MOUNTAIN CORE AREA
MarkWest has focused its exploration and production business in Rocky Mountain
coal seam natural gas development--primarily in the San Juan Basin. During the
fourth quarter of 1998 and first quarter of 1999, MarkWest sold its interest in
three non-core properties for $1.2 million, and reinvested $1.4 million for a
49% interest in properties and gathering systems that overlap its existing San
Juan Basin properties. In 1999, nearly $1.3 million was spent, primarily in the
second and third quarters, on high-return workover activities on the purchased
wells to improve production. Net natural gas sold in the fourth quarter of 1999
averaged 2.7 MMcfd, representing a 69 percent increase from the same period last
year, and for the year averaged 2.5 MMcfd, up 32 percent. This increase reflects
production acquired in the first quarter of 1999 (net of disposed production)
and the benefit realized from the 1999 capital program.
During the fourth quarter, MarkWest received approval for additional down-spaced
coal wells in the San Juan Basin resulting in approximately twenty additional
development locations. As these wells are completed over the next two years,
MarkWest expects an additional 1.5-2.0 MMcfd net to its 49 percent interest. It
is anticipated that future spacing requests for other producing horizons in
MarkWest's San Juan Basin properties could yield another twenty development
locations.
MICHIGAN CORE AREA
For discussion on drilling programs, see PROCESSING AND RELATED SERVICES -
MICHIGAN CORE AREA appearing earlier in Items 1 and 2 of this Form 10-K.
SEASONALITY
A substantial portion of the Company's revenues and, as a result, its gross
margins, remains dependent upon the sales price of NGLs, particularly propane,
which fluctuates with the winter weather conditions, and other supply and demand
determinants. The strongest demand for propane and the highest propane sales
margins generally occur during the winter heating season. As a result, the
Company recognizes a substantial portion of its annual income during the first
and fourth quarters of the year.
COMPETITION
The Company faces competition in obtaining natural gas supplies for its
processing and related services operations, in obtaining unprocessed NGLs for
fractionation, and in marketing its products and services. Competition for
natural gas supplies is based primarily on location of gas gathering facilities
and gas processing plants, operating efficiency and reliability, and ability to
obtain a satisfactory price for products recovered. Competitive factors
affecting the Company's fractionation services include availability of capacity,
proximity to supply and to industry marketing centers, and cost efficiency and
reliability of service. Competition for customers is based primarily on price,
delivery capabilities, flexibility, and maintenance of quality customer
relationships.
The Company's principal competitors include major integrated oil and gas
companies, major interstate pipeline companies, national and local gas
gatherers, NGL processing companies, brokers, marketers and distributors of
varying sizes, financial resources and experience. Many of the Company's
competitors, such as major oil and gas and pipeline companies, have capital
resources and control supplies of natural gas substantially greater than that of
the Company. Smaller local distributors may enjoy a marketing advantage in their
immediate service areas. Drilling activity behind the Company's systems varies
with industry conditions, commodity prices, and effectively competes for capital
with producers' other drilling opportunities.
OPERATIONAL RISKS AND INSURANCE
The Company's operations are subject to the usual hazards incident to the
exploration for and production, gathering, transmission, processing and storage
of natural gas and NGLs, such as explosions, product spills, leaks, emissions
and fires. These hazards can cause personal injury and loss of life, severe
damage to and destruction of property and equipment, and pollution or other
environmental damage, and may result in curtailment or suspension of operations
at the affected facility.
The Company maintains general public liability, property and business
interruption insurance in amounts that it considers to be adequate for such
risks. Such insurance is subject to deductibles that the Company considers
reasonable and not excessive.
7
Consistent with insurance coverage generally available to the industry, the
Company's insurance policies provide coverage for losses or liabilities related
to sudden occurrences of pollution or other environmental damage.
The occurrence of a significant event not fully insured or indemnified against,
and/or the failure of a party to meet its indemnification obligations, could
materially and adversely affect the Company's operations and financial
condition. Moreover, no assurance can be given that the Company will be able to
maintain adequate insurance in the future at rates it considers reasonable. To
date, however, the Company has experienced no material uninsured losses or any
difficulty in acquiring insurance coverage in amounts it believes to be
adequate.
GOVERNMENT REGULATION
In the Michigan Core Area, the Company owns and operates a gathering pipeline in
conjunction with its processing plant. Under the Natural Gas Act of 1938,
facilities that have as their "primary function" the performance of gathering
activities and are not owned by interstate gas pipeline companies are wholly
exempt from Federal Energy Regulatory Commission jurisdiction. State and local
regulatory authorities oversee intrastate gathering and other natural gas
pipeline operations. The Michigan Public Service Commission ("MPSC") regulates
the construction, operation, rates and safety of certain natural gas gathering
and transmission pipelines pursuant to state regulatory statutes. The Company
conducts gas pipeline operations in Michigan through an affiliate, which is
subject to this regulation by the MPSC. The design, construction, operation and
maintenance of the Company's pipeline is also subject to safety regulations.
Natural gas exploration and production operations are subject to various types
of regulation at the federal, state and local levels. The effect of these
regulations may limit the amount of gas available to the Company's systems 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.
ENVIRONMENTAL MATTERS
The Company is subject to environmental risks normally incident to its
operations and construction activities 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 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 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, which
can increase the costs of designing, installing and operating its 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.
Laws and regulations may require a permit or other authorization before certain
activities may be conducted by the Company and include fines and penalties for
non-compliance. Further, these rules may limit or prohibit activities within
wilderness areas, wetlands, and areas providing habitat for certain species or
other protected areas. The Company is also subject to other federal, state and
local laws covering the handling, storage or discharge of materials used by the
Company. The Company believes that it is in material compliance with all
applicable laws and regulations.
EMPLOYEES
As of December 31, 1999, the Company had 105 employees. Eleven employees at the
Company's Siloam fractionation facility in South Shore, Kentucky, are
represented by the Oil, Chemical and Atomic Workers International Union, Local
3-372 (Siloam Sub-Local). The Company's collective bargaining agreement with
this Union expires on April 30, 2000. The agreement covers only hourly,
non-supervisory employees. The Company considers labor relations to be
satisfactory at this time.
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RISK FACTORS
This Annual Report on Form 10-K contains statements which, to the extent that
they are not recitations of historical fact, constitute "forward-looking
statements" within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities and Exchange Act of 1934. All forward-looking
statements involve risks and uncertainties. The forward-looking statements in
this document are intended to be subject to the safe harbor protection provided
by Sections 27A and 21E. Factors that most typically impact the Company's
operating results and financial condition include: (i) changes in general
economic conditions in regions in which the Company's products are located; (ii)
the availability and prices of NGLs and competing commodities; (iii) the
availability and prices of raw natural gas supply; (iv) the ability of the
Company to negotiate favorable marketing agreements; (v) the risks that third
party or company natural gas exploration and production activities will not
occur or be successful; (vi) the Company's dependence on certain significant
customers, producers, gatherers, treaters, and transporters of natural gas;
(vii) competition from other NGL processors, including major energy companies;
(viii) the Company's ability to identify and consummate grassroots projects or
acquisitions complementary to its business; and (ix) winter weather conditions.
For discussions identifying other important factors that could cause actual
results to differ materially from those anticipated in the forward-looking
statements, see Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations included in this Form 10-K. Forward-looking
statements involve many uncertainties that are beyond the Company's ability to
control and in many cases the Company cannot predict what factors would cause
actual results to differ materially from those indicated by the forward-looking
statements.
ITEM 3. LEGAL PROCEEDINGS
The Company is currently involved in litigation arising in the ordinary course
of business. Management believes that costs of settlements or judgements, if
any, arising from such suits will not have a material adverse effect on the
Company's consolidated financial position or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the quarter
ended December 31, 1999.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The American Stock Exchange began trading shares of MarkWest Hydrocarbon, Inc.
under the ticker symbol NRG on Monday, February 22, 1999. The Company's stock
formerly traded on the Nasdaq National Market under the ticker symbol MWHX.
MarkWest's ticker symbol NRG was chosen to represent "energy."
As of December 31, 1999, there were 8,461,702 shares of common stock outstanding
held by 506 holders of record. The following table sets forth quarterly high and
low sales prices as reported by the American Stock Exchange (and previously the
Nasdaq National Market) for the periods indicated.
1998 1999
------------------------ -----------------------
HIGH LOW HIGH LOW
---- --- ---- ---
First Quarter........................... 22 1/2 19 9 1/4 5 3/4
Second Quarter.......................... 22 1/2 14 3/4 11 3/8 7
Third Quarter........................... 15 3/4 8 3/4 8 7/8 5
Fourth Quarter.......................... 11 1/2 7 7 7/8 4 3/4
The Company has paid no dividends on the common stock and anticipates that, for
the foreseeable future, it will continue to retain earnings for use in the
operation of its business. Payment of cash dividends in the future will depend
upon the Company's earnings; financial condition; contractual restrictions, if
any; restrictions imposed by law and other factors deemed relevant by the
Company's Board of Directors.
9
ITEM 6. SELECTED FINANCIAL DATA
The selected consolidated statement of operations and balance sheet data for the
years ended December 31, 1999, 1998 and 1997, and as of December 31, 1999 and
1998, are derived from, and are qualified by reference to, audited consolidated
financial statements of the Company included elsewhere in this Form 10-K. The
selected consolidated statement of operations and balance sheet data set forth
below for the years ended December 31, 1996 and 1995, and as of December 31,
1997, 1996 and 1995, have been derived from audited financial statements not
included in this Form 10-K. The selected consolidated financial information set
forth below should be read in conjunction with Item 7 - Management's Discussions
and Analysis of Financial Condition and Results of Operations and the Company's
Consolidated Financial Statements and related notes thereto included in this
Form 10-K.
Year Ended December 31,
--------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
-------------- --------------- ---------------- ---------------- ----------------
(in thousands, except per share amounts and operating data)
STATEMENT OF OPERATIONS:
Revenues (1),(2)......................... $ 108,634 $ 63,698 $ 79,683 $ 71,952 $ 48,226
Gross margin (3)......................... 29,696 20,739 33,169 29,855 18,825
Operating expenses....................... 12,657 10,785 11,286 7,597 4,706
Cash operating margin (4) ............... 17,039 9,954 21,883 22,258 14,119
General and administrative expenses...... 6,986 5,319 6,651 5,302 4,189
Net income (loss) (1), (10).............. 2,823 (1,211) 7,847 7,769 6,074
Basic earnings per share (1), (5) ....... 0.33 (0.14) 0.92 1.21 1.06
Earnings per share assuming dilution
(1), (5)............................. $ 0.33 $ (0.14) $ 0.91 $ 1.20 $ 1.06
Weighted average shares outstanding (6).. 8,475 8,490 8,485 6,415 5,725
CASH FLOW DATA:
Cash flows from operating
activities, before working
capital changes..................... $ 6,393 $ 4,795 $ 12,650 $ 14,702 $ 8,878
Capital and acquisition expenditures..... 17,898 15,890 30,329 17,516 12,426
OTHER FINANCIAL DATA:
EBITDA (7)............................... $ 9,777 $ 4,511 $ 15,808 $ 18,568 $ 9,930
BALANCE SHEET DATA
(AS OF DECEMBER 31):
Working capital (8)...................... $ 11,511 $ 11,463 $ 14,603 $ 11,896 $ 10,369
Property and equipment, gross............ 115,100 102,931 81,269 60,456 41,515
Property and equipment, net.............. 92,311 83,322 65,830 48,140 31,947
Total assets ............................ 119,243 103,631 98,657 78,254 46,896
Long-term debt........................... 44,035 38,597 33,931 11,257 17,500
Partners' capital........................ -- -- -- -- 25,161
Stockholders' equity .................... 52,719 50,035 51,548 43,664 --
10
Year Ended December 31,
-------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
--------------- --------------- ---------------- ---------------- ----------------
OPERATING DATA:
Appalachia:
NGL production--Siloam plant
(Gal)......................... 113,000,000 102,900,000 102,500,000 94,900,000 92,200,000
NGLs marketed--Siloam plant
(Gal)......................... 115,800,000 100,900,000 103,400,000 94,600,000 95,500,000
Processing margin per gallon:
Average NGL sales price........... $ 0.379 $ 0.304 $ 0.482 $ 0.448 $ 0.354
Average natural gas cost....... 0.266 0.236 0.255 0.235 0.181
--------------- --------------- ---------------- ---------------- ----------------
Average margin................. $ 0.113 $ 0.068 $ 0.227 $ 0.213 $ 0.173
Michigan:(9)
Pipeline throughput (Mcfd)........ 17,800 16,000 8,900 4,800 --
NGLs marketed (Gal)............... 13,500,000 10,600,000 -- -- --
Rocky Mountains:
Natural gas sold (Mcfd)........... 2,500 1,900 1,400 700 N/M
- -----------------------
N/M--Not meaningful.
(1) In 1999, includes $2,509 gain ($1,566, or $0.18 per share, after-tax)
from the sale of the Company's West Memphis terminal.
(2) Includes gas marketing revenues of $34,100 and $5,600 for the years ended
December 31, 1999 and 1998, respectively. The Company's gas marketing
business originated in 1998. Gas marketing activities are low margin;
these activities are done in support of MarkWest's processing business.
(3) Includes gathering, processing, and marketing revenue; oil and gas
revenue; and cost of sales.
(4) Includes gathering, processing, and marketing revenue; oil and gas
revenue; cost of sales; and operating expenses.
(5) Prior to October 7, 1996, the Company was organized as a
partnership--MarkWest Hydrocarbon Partners, Ltd. ("MarkWest
Partnership")--and consequently, was not subject to income tax. Effective
October 7, 1996, the Company reorganized (the "Reorganization"), and the
existing general and limited partners exchanged 100% of their interests in
MarkWest Partnership for 5,725,000 common shares of the Company. Pro forma
information has been presented for purposes of comparability as if the
Company had been a taxable entity for all periods presented:
Year Ended December 31,
----------------------------------
1996 1995
-------------- --------------
Historical income before income taxes.............. $ 14,760 $ 7,824
Pro forma provision for income taxes............... 5,609 2,937
Pro forma net income............................... 9,151 4,887
Pro forma basic earnings per share................. 1.16 0.85
Pro forma earnings per share assuming dilution..... $ 1.15 $ 0.85
Pro forma weighted average shares outstanding (a).. 7,908 5,725
(a) Pro forma weighted average shares outstanding for the year ended
December 31, 1996, represents the weighted average of, for the
period prior to the initial public offering (the "Offering"), the
number of common shares issued in the Reorganization plus the number
of shares issued in the Offering for which the net proceeds were
used to repay outstanding indebtedness and, for the period
subsequent to the Offering, the total number of common shares
outstanding. Pro forma weighted average shares outstanding for the
year ended December 31, 1995, represent the weighted average number
of common shares issued in the Reorganization.
(6) Weighted average shares outstanding for the year ended December 31, 1996,
represents the weighted average of, for the period prior to the Company's
initial public offering, the number of common shares issued in the
Reorganization and, for the period subsequent to the Offering, the total
number of common shares outstanding. Weighted average shares outstanding
for the year ended December 31, 1995, represent the weighted average
number of common shares issued in the Reorganization.
(7) Earnings (loss) before interest income; interest expense; income taxes;
depreciation, depletion, and amortization; and gain on sale of West
Memphis terminal.
(8) Includes cash of $1,356; $2,055; $1,364; $4,401; and $761, respectively.
(9) 1999, 1998 and 1997 results reflect the Company's acquisition of the
remaining percent interest of the Michigan operations in November 1997.
Prior to November 1997, MarkWest owned 60 percent of the Michigan
operations. Pipeline operations commenced in 1996; the Fisk processing
plant commenced operations in 1998.
(10) 1995 net income includes a $1,750 extraordinary loss on extinguishment of
debt.
11
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following analysis should be read in conjunction with Item 6 - Selected
Financial Data and the Company's Consolidated Financial Statements included in
this Form 10-K.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1999, COMPARED TO YEAR ENDED DECEMBER 31, 1998
OVERVIEW. For the year ended December 31, 1999, MarkWest reported net income of
$2.8 million, or $0.33 per share, on revenues of $108.6 million, a $4.0 million
increase in net income over 1998's net loss of $1.2 million, or $0.14 per share,
on revenues of $63.7 million. Aside from the Company's $1.5 million, or $0.18
per share, after-tax gain on the sale of the Company's West Memphis terminal,
record NGL production and sales in Appalachia, contributing an incremental $0.6
million after-tax in 1999, coupled with improving Appalachian processing
margins, contributing an incremental $3.2 million after-tax in 1999, were the
primary reasons behind the Company's return to profitability in 1999. MarkWest
sold 115.8 million gallons of NGLs in 1999, a 15% increase over 1998 levels, as
gas production increased behind the Company's facilities. Appalachian processing
margins averaged $0.113 per gallon in 1999, up 66% over 1998, but still
significantly below the Company's $0.165 per gallon ten-year historical average.
Increased NGL prices contributed to improving margins. Increased profitability
from MarkWest's terminals, due to increased NGL sales prices, and Michigan
operations, due to increased throughput and NGL sales prices, contributed an
incremental $1.6 million after-tax in 1999. Expected increases in operating,
general and administrative, interest and depreciation, depletion and
amortization expenses reduced after-tax results an incremental $2.9 million in
1999.
GATHERING, PROCESSING AND MARKETING REVENUE. Gathering, processing and marketing
revenue increased $42.4 million, or 68%, for the year ended December 31, 1999,
compared to the year ended December 31, 1998. The revenue increase was
principally attributable to a $28.5 million increase in the Company's gas
marketing operations. At the Company's Siloam fractionation facility, higher NGL
sales prices and larger volumes of NGLs marketed contributed an incremental $8.7
million and $4.5 million, respectively, to 1999 revenues.
OIL AND GAS REVENUE. Oil and gas revenue increased $0.4 million for the year
ended December 31, 1999, compared to the year ended December 31, 1998. This
increase was primarily attributable to an increase in gas production from the
prior year.
COST OF SALES. Cost of sales increased $33.8 million, or 79%, for the year ended
December 31, 1999, compared to the year ended December 31, 1998. This increase
was primarily caused by a $28.5 million increase in gas marketing purchases. At
the Company's Siloam fractionation facility, both higher natural gas costs and
larger volumes of natural gas purchased contributed an incremental $3.4 million
and $3.5 million, respectively, to 1999 cost of sales.
OPERATING EXPENSES. Operating expenses increased $1.9 million, or 17%, for the
year ended December 31, 1999, compared to the year ended December 31, 1998. The
increase in operating expenses was principally attributable to four factors.
First, certain expenses increased with volumes in Appalachia, Michigan and the
Rocky Mountains. Second, MarkWest sold and leased back three compressors at its
Kenova processing plant beginning in the third quarter of 1998. Consequently,
1999 operating expenses include twelve full months of lease expense whereas the
results from the comparable time period in 1998 do not. Further, these
compressors were overhauled in 1999. Third, 1998 operating expenses were lower
due to a sales and use tax refund during that period. Last, performance-based
incentive compensation increased in 1999; MarkWest did not pay bonuses in 1998
due to the Company's overall net loss.
GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses
increased $1.7 million, or 31%, for the year ended December 31, 1999, compared
to the year ended December 31, 1998. This increase is attributable to increased
performance-based incentive compensation (MarkWest did not pay bonuses in 1998
due to the Company's overall net loss); professional service fees also increased
in 1999 due to the Company's arbitration with Columbia, now since settled; and
to increased business development expenditures.
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization increased $0.5 million, or 10%, for the year ended December 31,
1999, compared to the year ended December 31, 1998. This increase was
principally due to the Company's pipeline extension in Michigan placed in
service during mid-1998.
INTEREST EXPENSE. Interest expense increased $0.7 million for the year ended
December 31, 1999, compared to the year ended December 31, 1998, due to
increased average outstanding debt and higher interest rates.
12
YEAR ENDED DECEMBER 31, 1998, COMPARED TO YEAR ENDED DECEMBER 31, 1997
OVERVIEW. For the year ended December 31, 1998, MarkWest reported a net loss of
$1.2 million, or $0.14 per share, on revenues of $63.7 million. These results
compare to net income of $7.8 million, or $0.92 per share, on revenues of $79.7
million for the same period in 1997. The net loss in 1998, compared to net
income in 1997, largely resulted from a reduction of $9.9 million, or $1.16 per
share, in after-tax gas processing margins. Appalachia's full-year 1998 gas
processing margin of $0.068 per gallon was approximately 60% below its ten-year
average and down by 70% compared to 1997's average of $0.227 per gallon. The
decrease in margin was due to a combination of weak NGL prices, which resulted
from 35% lower crude oil prices, and relatively strong natural gas costs that
negatively impacted the entire natural gas processing industry. Michigan's
after-tax operating income totaled $1.6 million for 1998, or $0.19 per share, up
from break-even in 1997. Increases in depreciation, depletion and amortization,
and net interest expense were largely offset by savings in operating costs and
general and administrative costs.
GATHERING, PROCESSING AND MARKETING REVENUE. Gathering, processing and marketing
revenue decreased $15.5 million, or 20%, for the year ended December 31, 1998,
compared to the year ended December 31, 1997. The Company's Appalachian
operations accounted for the majority of the overall revenue decrease, primarily
as a result of weak NGL prices in 1998 compared to 1997. In addition, fee gas
processed in 1998 only includes volumes processed at the Company's Kenova plant
beginning March 1, 1998. In 1997 and early 1998, fee gas processed included
volumes at the Boldman and Cobb plants in addition to the Kenova plant. The loss
of fee revenue is partly offset by cost savings realized from not operating
Boldman and Cobb.
The above factors were partially offset by an 80% increase in the volume of gas
processed in the Company's Michigan operations during the year ended December
31, 1998, compared to the year ended December 31, 1997. Gas processed in the
Company's Michigan operations contributed both fee-based processing income and
revenues from the sale of propane and other liquids extracted at the Company's
new NGL extraction plant, which began operations in January 1998.
OIL AND GAS REVENUE. Oil and gas revenue increased $0.3 million for the year
ended December 31, 1998, compared to the year ended December 31, 1997. This
increase was primarily attributable to an increase in gas production from the
prior year.
INTEREST INCOME. Interest income decreased $0.5 million for the year ended
December 31, 1998, compared to the year ended December 31, 1997. During 1997,
interest income was primarily derived from a note receivable for the costs
incurred by the Company for the construction of the 32-mile extension to the gas
pipeline in Michigan, which was completed in 1997. During 1998, the note was
forgiven in exchange for the title to the pipeline extension.
COST OF SALES. Cost of sales decreased $2.8 million, or 6%, for the year ended
December 31, 1998, compared to the year ended December 31, 1997. The Company's
Appalachian operations accounted for the majority of the decrease, primarily as
a result of a decrease in the unit cost of propane at the Company's terminals.
OPERATING EXPENSES. Operating expenses decreased $0.5 million, or 4%, for the
year ended December 31, 1998, compared to the year ended December 31, 1997. In
response to low processing margins, the Company implemented cost-controlling
measures and consequently reduced operating costs during 1998, compared to 1997.
Additionally, the Company had lower performance-based incentive compensation
expense in 1998 due to the Company's overall net loss. These decreases were
partially offset by the introduction of operational costs from the Company's new
NGL extraction plant in Michigan for a full year during 1998.
GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses
decreased $1.3 million, or 20%, for the year ended December 31, 1998, compared
to the year ended December 31, 1997. General and administrative expenses
incurred during 1997 included a continuation of many initial costs, including
significant professional service fees, incurred in connection with the Company's
reorganization into a public company following the initial public offering in
October 1996. In addition, in response to low processing margins throughout
1998, the Company implemented cost-controlling measures and consequently reduced
general and administrative expenses. Finally, the Company had lower
performance-based incentive compensation expense in 1998 due to the Company's
overall net loss.
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization increased $1.3 million, or 42%, for the year ended December 31,
1998, compared to the year ended December 31, 1997. This increase was
principally due to increased depreciation attributable to the Company's new NGL
extraction plant and pipeline extension in Michigan.
INTEREST EXPENSE. Interest expense increased $1.3 million, or 154%, for the year
ended December 31, 1998, compared to the year ended December 31, 1997. This
increase was principally due to an increase in average outstanding long-term
debt in 1998 compared to 1997.
13
LIQUIDITY AND CAPITAL RESOURCES
For the past three years, the Company's sources of liquidity and capital
resources have been internal cash flow; its revolving line of credit; and, in
1999, proceeds from the sale of the Company's West Memphis terminal. MarkWest
believes its ability to generate cash from operations to reinvest in its
business is one of its fundamental financial strengths. The Company anticipates
that its operating activities in 2000, coupled with selective asset sales and
existing bank credit arrangements, will continue to provide adequate cash flows
for its business expansion and to meet its financial commitments.
The consolidated statements of our cash flows, detailed in the Consolidated
Financial Statements in Item 8 of this Form 10-K, are summarized as follows (in
000s):
For the Year Ended December 31,
------------------------------------------------------
1999 1998 1997
--------------- --------------- ---------------
Net cash provided by operating activities before change
in working capital.............................. $ 6,393 $ 4,795 $ 12,650
Net cash provided by operating activities from change
in working capital ............................. (253) 3,638 (7,894)
Net cash used in investing activities.............. (11,884) (11,559) (30,329)
Net cash provided by financing activities.......... $ 5,045 $ 3,817 $ 22,536
Cash provided by operating activities before change in working capital in 1999
amounted to $6.4 million, a 33% increase from 1998, primarily due to increased
gas processing margins and volumes at the Company's Appalachian facilities. In
1998, cash provided by operating activities before change in working capital
amounted to $4.8 million, a 62% decrease from 1997. This increase resulted from
a decrease in gas processing margins at MarkWest's Appalachian plants in 1998.
CAPITAL INVESTMENT PROGRAM
Investing activities consist primarily of capital and acquisition expenditures
and sales of assets. 1999 and 1998 programs were of similar size.
The Company's capital expenditures are summarized as follows (in 000s):
For the Year Ended December 31,
-----------------------------------------------------
1999 1998 1997
-------------- --------------- ---------------
Appalachia:
Phase I expansion................................... $ 9.3 $ -- $ --
Terminal and storage facilities..................... 2.1 -- --
Rocky Mountains:
Exploration and production.......................... 3.6 2.9 3.6
Western Michigan:
Pipeline expansion.................................. 0.1 10.7 1.9
Fisk extraction plant............................... -- -- 7.2
Exploration and production.......................... 0.8 0.1 --
Eastern Michigan:
Au Gres project..................................... 0.2 -- --
Purchase of office building............................... -- -- 4.6
Maintenance capital and other............................. 1.8 2.2 2.0
-------------- --------------- ---------------
Total capital expenditures.......................... $ 17.9 $ 15.9 $ 19.3
============== =============== ===============
Looking ahead, MarkWest is anticipating a baseline capital budget of $16 million
in 2000 and $12 million in 2001. This budget will fund the completion of Phase I
and Phase II expansion in Appalachia and other requirements, including Michigan
drilling and maintenance capital. In addition, MarkWest is targeting another $20
million in other new projects and acquisitions. Management believes that funds
generated from operations, the February 2000 sale of the Company's office
building for $5.0 million in net cash proceeds, and unused borrowing capacity
will enable the Company to fund its 2000-2001 capital expenditure programs.
14
FINANCING FACILITIES
Financing activities consist primarily of net borrowings under the Company's
credit facility, which is described in Note 3 to the Company's Consolidated
Financial Statements in Item 8 of this Form 10-K. At December 31, 1999, the
Company had approximately $46.9 million of available credit, of which net debt
of $42.8 million had been utilized as of December 31, 1999, and working capital
of $11.5 million. As 2000 progressed, the Company's credit availability
increased as the trailing cash flow calculation, the determinant of the
Company's available credit, rose because of improvements in Appalachia
processing margins. In addition, the Company sold its corporate office building
in February 2000 for $5.0 million in net proceeds to further increase its
financial flexibility. As of February 29, 2000, unutilized credit had increased
to approximately $18 million. Depending on the timing and amount of the
Company's future projects beyond the level described above, it may be required
to seek additional sources of capital. While the Company believes that it will
be able to secure additional financing on terms acceptable to the Company, if
required, no assurance can be given that it will be able to do so.
2000 OUTLOOK
Overall, Company earnings volatility will be diminished in 2000, compared to
1999, as additional fee-based revenues, a result of long-term agreements signed
with a large Appalachian producer in mid-1999 for new facilities coming on-line
in early 2000, become a part of MarkWest's revenue mix. Assuming normal
processing margins in Appalachia, the Company anticipates fee-based activity
will generate approximately 50% of total gross margins in 2000.
It is anticipated that facility expansion, coupled with increased producer
drilling behind Company-owned facilities, should push Appalachian production and
sales volumes to record levels in 2000. NGL prices in the fourth quarter of 1999
were above historical levels and are expected to remain so during the first
quarter of 2000. These prices are often correlated with and driven by the price
of crude oil, which appears to have recovered from its decline in 1998 through
mid-1999. MarkWest has implemented as of February 29, 2000, hedges to lock in
approximately 60% of its year 2000 Appalachian liquid volumes subject to
keep-whole contracts at a $0.20 per gallon margin. For further risk management
information, see Note 7, COMMODITY PRICE RISK MANAGEMENT, in the Notes to the
Company's Consolidated Financial Statements in Item 8 of this Form 10-K.
Throughput volumes in Michigan for 2000 are expected to remain near 1999 levels.
Drilling by the Company and third parties is scheduled for the first half of
2000.
Rocky Mountain production is expected to increase 20% in 2000 compared to 1999
as a result of the Company's capital investment program.
COMMODITY PRICE RISK MANAGEMENT ACTIVITIES
Reference is made to Note 7 of the Company's Consolidated Financial Statements
in Item 8 of this Form 10-K.
IMPACT OF THE YEAR 2000 ISSUE
The Year 2000 Issue was the result of computer programs being written using two
digits rather than four to define the applicable year. Unless computer programs
were Year 2000 compliant, any computer programs that had date-sensitive software
could have recognized a date using "00" as the year 1900 rather than the year
2000. This could have resulted in a system failure or miscalculations causing
disruptions of operations, including, among other things, a temporary inability
to process transactions, send invoices, or engage in similar normal business
activities.
The Company experienced no Year 2000 related problems in any of the Company's
systems. MarkWest conducted a thorough evaluation of all systems well in advance
of December 31, 1999, and met Company objectives with total expenditures of
approximately $0.1 million.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company faces market risk from commodity price variations, primarily in the
NGLs it sells and in the natural gas it purchases. It also incurs, to a lesser
extent, credit risks and risks related to interest rate variations.
15
COMMODITY PRICE RISK. In the past, NGL prices and natural gas costs have
fluctuated widely in response to changing market forces. The impacts of these
price fluctuations on earnings from natural gas processing and marketing
activities have been significant and have varied from year to year. Currently
MarkWest's Appalachian operations have an annual sensitivity to NGL prices equal
to $1.2 million in pretax income for every $0.01 per gallon change in NGL prices
and an annual sensitivity to natural gas prices equal to $1.2 million in pretax
income for every $0.10/MMBtu change in natural gas prices. For 2000, the Company
has hedged approximately 60% of its Appalachian keep-whole volumes as of
February 29, 2000, reducing the annual sensitivity accordingly.
The Company typically hedges a portion of its commodity price risk. Gains and
losses experienced on hedging transactions are generally offset by the related
gains or losses on the sale of the underlying product in the physical market.
See related discussion in Note 7 to the Company's Consolidated Financial
Statements.
CREDIT RISK. The Company is exposed to potential losses as a result of
nonperformance by counterparties pursuant to the terms of their contractual
obligations. The Company maintains credit policies with regard to its
counterparties that management believes minimize overall credit risk. Such
policies include the evaluation of a prospective counterparty's financial
condition, collateral requirements where deemed necessary, and the use of
standardized agreements which facilitate the netting of cash flows associated
with a single counterparty. The Company also monitors the financial condition of
existing counterparties on an ongoing basis.
INTEREST RATE RISK. The Company is exposed to changes in interest rates,
primarily as a result of its long-term debt with floating interest rates. The
Company may make use of interest rate swap agreements to adjust the ratio of
fixed and floating rates in the debt portfolio, although no such agreements are
currently in place. The impact of a 100 basis point increase in interest rates
on the Company's debt would result in an increase in interest expense and a
decrease in income before taxes of approximately $0.4 million. This amount has
been determined by considering the impact of the hypothetical interest rates on
the Company's variable-rate debt balances as of December 31, 1999.
16
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
Report of Independent Accountants............................................................. 17
Consolidated Balance Sheet at December 31, 1999 and 1998...................................... 18
Consolidated Statement of Operations for each of the three years in the period
ended December 31, 1999............................................................ 19
Consolidated Statement of Cash Flows for each of the three years in the period
ended December 31, 1999............................................................ 20
Consolidated Statement of Changes in Stockholders' Equity for each of the three years in the
period ended December 31, 1999..................................................... 21
Notes to Consolidated Financial Statements.................................................... 22
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of MarkWest Hydrocarbon, Inc.
In our opinion, the accompanying consolidated balance sheets and related
consolidated statements of operations, of cash flows and of changes in
stockholders' equity present fairly, in all material respects, the financial
position of MarkWest Hydrocarbon, Inc., a Delaware corporation, and its
subsidiaries at December 31, 1999 and 1998, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1999, in conformity with accounting principles generally accepted in the
United States. These financial statements are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our audits of these
statements in accordance with auditing standards generally accepted in the
United States which require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Denver, Colorado
February 9, 2000
17
MARKWEST HYDROCARBON, INC.
CONSOLIDATED BALANCE SHEET
(000S, EXCEPT PER SHARE DATA)
December 31,
------------------------------
ASSETS 1999 1998
--------------- -------------
Current assets:
Cash and cash equivalents.............................. $ 1,356 $ 2,055
Receivables, net of allowance for doubtful accounts of
$0 and $120, respectively............................ 16,360 7,738
Inventories ........................................... 6,043 4,583
Prepaid feedstock ..................................... 1,895 1,957
Receivable from income taxes paid...................... -- 2,763
Other assets........................................... 327 289
--------------- -------------
Total current assets........................... 25,981 19,385
Property and equipment:
Gas processing, gathering, storage and marketing
equipment............................................ 78,476 76,659
Oil and gas properties and equipment................... 14,518 10,566
Land, buildings and other equipment.................... 11,409 11,240
Construction in progress............................... 10,697 4,466
-------------- -------------
115,100 102,931
Less: accumulated depreciation, depletion and
amortization......................................... (22,789) (19,609)
--------------- -------------
Total property and equipment, net.............. 92,311 83,322
Intangible assets, net of accumulated amortization of $438
and $169, respectively.................................. 951 924
--------------- -------------
Total assets................................... $119,243 $103,631
=============== =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Trade accounts payable................................. $ 4,997 $ 2,765
Accrued liabilities.................................... 9,369 5,094
Current portion of long-term debt...................... 104 63
--------------- -------------
Total current liabilities...................... 14,470 7,922
Deferred income taxes...................................... 8,019 7,077
Long-term debt............................................. 44,035 38,597
Commitments and contingencies.............................. -- --
Stockholders' equity:
Preferred stock, par value $0.01; 5,000,000 shares
authorized, 0 shares outstanding.................... -- --
Common stock, par value $0.01; 20,000,000 shares
authorized, 8,531,206 and 8,531,206 shares issued,
respectively........................................ 85 85
Additional paid-in capital............................. 42,222 42,693
Retained earnings...................................... 10,801 7,978
Treasury stock; 69,504 and 60,300 shares,
respectively......................................... (389) (721)
--------------- -------------
Total stockholders' equity..................... 52,719 50,035
--------------- -------------
Total liabilities and stockholders' equity..... $119,243 $ 103,631
=============== =============
The accompanying notes are an integral part of
these financial statements.
18
MARKWEST HYDROCARBON, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(000S, EXCEPT PER SHARE DATA)
For the Year Ended December 31,
-----------------------------------------------------------
1999 1998 1997
---------------- ----------------- -----------------
Revenue:
Gathering, processing and marketing revenue.................. $ 104,810 $ 62,438 $ 77,938
Oil and gas revenue, net of transportation and taxes......... 1,538 1,184 888
Interest income.............................................. 53 200 661
Gain on sale of West Memphis terminal........................ 2,509 -- --
Other income (expense)....................................... (276) (124) 196
---------------- ----------------- -----------------
Total revenue........................................... 108,634 63,698 79,683
---------------- ----------------- -----------------
Costs and expenses:
Cost of sales ............................................... 76,652 42,883 45,657
Operating expenses........................................... 12,657 10,785 11,286
General and administrative expenses.......................... 6,986 5,319 6,651
Depreciation, depletion and amortization..................... 5,070 4,594 3,246
Interest expense............................................. 2,745 2,095 826
---------------- ----------------- -----------------
Total costs and expenses................................ 104,110 65,676 67,666
---------------- ----------------- -----------------
Income (loss) before minority interest and income taxes.......... 4,524 (1,978) 12,017
Minority interest in net loss of subsidiary...................... -- -- 380
---------------- ----------------- -----------------
Income (loss) before income taxes................................ 4,524 (1,978) 12,397
Provision (benefit) for income taxes:
Current...................................................... 759 (2,235) 2,918
Deferred..................................................... 942 1,468 1,632
---------------- ----------------- -----------------
Net income (loss)................................................ $ 2,823 $ (1,211) $ 7,847
================ ================= =================
Basic earnings (loss) per share ................................. $ 0.33 $ (0.14) $ 0.92
================ ================= =================
Earnings (loss) per share assuming dilution ..................... $ 0.33 $ (0.14) $ 0.91
================ ================= =================
Weighted average number of outstanding shares of common stock:
Basic........................................................ 8,475 8,490 8,485
================ ================= =================
Assuming dilution............................................ 8,481 8,490 8,614
================ ================= =================
The accompanying notes are an integral part of
these financial statements.
19
MARKWEST HYDROCARBON, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(000S)
For the Year Ended December 31,
------------------------------------------------
1999 1998 1997
------------- ------------- -------------
Cash flows from operating activities:
Net income (loss)..................................................... $ 2,823 $ (1,211) $ 7,847
Add income items that do not affect working capital:
Depreciation, depletion and amortization.......................... 5,070 4,594 3,246
Deferred income taxes............................................. 942 1,468 1,632
(Gain) loss on disposition of assets.............................. 67 (56) (75)
Gain on sale of West Memphis terminal............................. (2,509) -- --
------------- ------------- -------------
6,393 4,795 12,650
Adjustments to working capital:
(Increase) decrease in receivables................................ (8,622) 2,541 (1,614)
(Increase) decrease in inventories................................ (1,460) 558 491
(Increase) decrease in prepaid expenses and other assets.......... 2,787 379 (3,099)
Increase (decrease) in accounts payable and accrued liabilities... 7,042 160 (3,672)
------------- ------------- -------------
(253) 3,638 (7,894)
Net cash flow provided by operating activities................. 6,140 8,433 4,756
Cash flows from investing activities:
Capital expenditures.............................................. (17,898) (15,890) (19,323)
Proceeds from sale/leaseback transaction.......................... -- 4,281 --
Proceeds from sale of assets...................................... 6,014 -- --
Acquisition of interest in Michigan project....................... -- -- (8,563)
Change in note receivable and other............................... -- 50 (2,443)
------------- ------------- -------------
Net cash used in investing activities.......................... (11,884) (11,559) (30,329)
Cash flows from financing activities:
Proceeds from issuance of long-term debt.......................... 48,056 39,200 39,920
Repayments of long-term debt...................................... (42,577) (34,627) (17,246)
Debt issuance costs............................................... (295) (454) (175)
Net acquisition of treasury stock................................. (139) (394) (455)
Proceeds from exercise of options and payment on share
purchase notes................................................. -- 92 492
------------- ------------- -------------
Net cash provided by financing activities...................... 5,045 3,817 22,536
------------- ------------- -------------
Net increase (decrease) in cash and cash equivalents........... (699) 691 (3,037)
Cash and cash equivalents at beginning of year............................ 2,055 1,364 4,401
------------- ------------- -------------
Cash and cash equivalents at end of year.................................. $ 1,356 $ 2,055 $ 1,364
============= ============= =============
The accompanying notes are an integral part of
these financial statements.
20
MARKWEST HYDROCARBON, INC.
CONSOLIDATED STATEMENT OF CHANGES IN
STOCKHOLDERS' EQUITY
(000S)
SHARES OF SHARES OF ADDITIONAL TOTAL
COMMON TREASURY COMMON PAID-IN RETAINED TREASURY STOCKHOLDERS'
STOCK STOCK STOCK CAPITAL EARNINGS STOCK EQUITY
-------------------------------------------------------------------------------------------------
Balance, December 31, 1996....... 8,485 -- $ 85 $ 42,237 $ 1,342 $ -- $ 43,664
Net income....................... -- -- -- -- 7,847 -- 7,847
Payments received on notes
receivable..................... -- -- -- 192 -- -- 192
Exercise of options.............. 35 -- -- 300 -- -- 300
Acquisition of treasury stock.... -- (28) -- -- -- (455) (455)
-------------------------------------------------------------------------------------------------
Balance, December 31, 1997....... 8,520 (28) $ 85 $ 42,729 $ 9,189 $ (455) $ 51,548
Net loss......................... -- -- -- -- (1,211) -- (1,211)
Exercise of options.............. 11 -- -- 89 -- -- 89
Acquisition of treasury stock.... -- (63) -- -- -- (690) (690)
Reissuance of treasury stock..... -- 31 -- (79) -- 375 296
Other............................ -- -- -- (46) -- 49 3
-------------------------------------------------------------------------------------------------
Balance, December 31, 1998....... 8,531 (60) $ 85 $ 42,693 $ 7,978 $ (721) $ 50,035
Net income....................... -- -- -- -- 2,823 -- 2,823
Acquisition of treasury stock.... -- (156) -- -- -- (1,035) (1,035)
Reissuance of treasury stock..... -- 147 -- (471) -- 1,367 896
-------------------------------------------------------------------------------------------------
Balance, December 31, 1999....... 8,531 (69) $ 85 $ 42,222 $ 10,801 $ (389) $ 52,719
==================================================================================================
The accompanying notes are an integral part of
these financial statements.
21
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. NATURE OF OPERATIONS
MarkWest Hydrocarbon, Inc. ("MarkWest" or the "Company"), provides natural gas
processing and related services. The Company's activities include compression,
gathering, treatment and natural gas liquids ("NGLs") extraction services for
natural gas producers and pipeline companies and fractionation of NGLs into
marketable products. The Company also purchases, stores and markets natural gas
and NGLs and conducts strategic exploration for new natural gas sources for its
processing services. The Company's operations are concentrated in three core
areas: the southern Appalachian region of eastern Kentucky, southern West
Virginia, and southern Ohio; western Michigan; and the Rocky Mountains.
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company and
its wholly owned subsidiaries: MarkWest Resources, Inc.; MarkWest Michigan,
Inc.; and 155 Inverness, Inc. All significant intercompany accounts and
transactions have been eliminated in consolidation.
CASH AND CASH EQUIVALENTS
The Company considers all highly liquid investments purchased with an original
maturity of three months or less to be cash equivalents. Excess cash is used to
pay down the credit facility. Accordingly, investments are limited to overnight
investments of end-of-day cash balances.
INVENTORIES
Inventories comprise the following (in 000s):
At December 31,
-----------------------
1999 1998
--------- ---------
Product inventory.................................... $5,629 $4,064
Materials and supplies inventory..................... 414 519
--------- ---------
$6,043 $4,583
========= =========
Product inventory consists primarily of finished goods (propane, butane,
isobutane, natural gasoline and, in 1999, natural gas) and is valued at the
lower of cost, using the first-in, first-out method, or market. Inventory
write-downs at December 31, 1999 and 1998, were $20,000 and $525,000,
respectively. Materials and supplies are valued at the lower of average cost or
estimated net realizable value.
PREPAID FEEDSTOCK
Prepaid feedstock consists of natural gas purchased in advance of its actual
use. It is valued using the first-in/first-out method.
PROPERTY AND EQUIPMENT
Property and equipment is recorded at cost. Expenditures that extend the useful
lives of assets are capitalized. Repairs, maintenance and renewals that do not
extend the useful lives of the assets are expensed as incurred. Interest costs
for the construction or development of significant long-term assets are
capitalized and amortized over the related asset's estimated useful life.
Depreciation is provided principally on the straight-line method over the
following estimated useful lives: plant facilities and pipelines, 20 years;
buildings, 40 years; furniture, leasehold improvements and other, 3 to 10 years.
Depletion for oil and gas properties is provided for using the
units-of-production method.
Oil and gas properties consist of leasehold costs, producing and non-producing
properties, oil and gas wells, equipment and pipelines. The Company uses the
full cost method of accounting for oil and gas properties. Accordingly, all
costs associated with acquisition, exploration and development of oil and gas
reserves are capitalized to the full cost pool.
These capitalized costs, including estimated future costs to develop the
reserves and estimated abandonment costs, net of salvage value, are amortized on
a units-of-production basis using estimates of proved reserves. Investments in
unproved properties and major development projects are not amortized until
proved reserves associated with the projects can be determined or until
22
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 1999 and 1998,
approximately $1.2 million and $0.5 million of investments in unproved
properties were excluded from amortization.
The capitalized costs included in the full cost pool are subject to a "ceiling
test," which limits such costs to the aggregate of the estimated present value,
using a 10 percent discount rate, of the future net revenues from proved
reserves, based on current economics and operating conditions. No impairment
existed during the three years ended December 31, 1999.
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
Intangible assets consist primarily of deferred financing costs that are
amortized using the straight-line method over the term of the associated
agreement.
HEDGING ACTIVITIES
The Company limits its exposure to natural gas and propane price fluctuations
related to future purchases and production with futures contracts. These
contracts are accounted for as hedges in accordance with the provisions of
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 revenues or cost of sales when the hedged production
is sold.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company's financial instruments consist of cash and cash equivalents,
receivables, accounts payable and other current liabilities, and long-term debt.
Except for long-term debt, the carrying amounts of financial instruments
approximate fair value due to their short maturities. At December 31, 1999 and
1998, based on rates available for similar types of debt, the fair value of
long-term debt was not materially different from its carrying amount.
REVENUE RECOGNITION
Revenue for sales or services is recognized at the time the product is shipped
or at the time the service is performed.
INCOME TAXES
Deferred income taxes reflect the impact of "temporary differences" between
amounts of assets and liabilities for financial reporting purposes and such
amounts as measured by tax laws. These temporary differences are determined in
accordance with the liability method of accounting for income taxes as
prescribed by SFAS No. 109, ACCOUNTING FOR INCOME TAXES.
CONCENTRATION OF CREDIT RISK
Financial instruments that potentially subject the Company to concentrations of
credit risk consist principally of trade accounts receivable. The trade accounts
receivable risk is limited due to the large number of entities comprising the
Company's customer base and their dispersion across industries and geographic
locations. At December 31, 1999 and 1998, the Company had no significant
concentrations of credit risk.
STOCK COMPENSATION
As permitted under SFAS No. 123, ACCOUNTING FOR STOCK-BASED COMPENSATION, the
Company has elected to continue to measure compensation costs for stock-based
employee compensation plans as prescribed by Accounting Principles Board Opinion
No. 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES. See Note 8 for the applicable
disclosures required by SFAS No. 123.
EARNINGS PER SHARE (EPS)
Basic earnings per share are determined by dividing net income by the
weighted-average number of common shares outstanding during the year. Earnings
per share assuming dilution are determined by dividing net income by the
weighted-average number of common shares and common stock equivalents
outstanding.
23
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEGMENT REPORTING
In accordance with SFAS No. 131, DISCLOSURES ABOUT SEGMENTS OF AN ENTERPRISE AND
RELATED INFORMATION, the internal organization that is used by management for
making operating decisions and assessing performance is the source of the
Company's reportable segments (see Note 11, SEGMENT REPORTING).
SUPPLEMENTAL CASH FLOW INFORMATION
Year Ended December 31,
----------------------------------------------------------
1999 1998 1997
----------------- ----------------- -----------------
Interest paid.......................................... $ 2.7 million $ 2.4 million $ 1.0 million
Interest expense capitalized to various
construction projects................................ $ 0.2 million $ 0.3 million --
Income taxes paid...................................... $ 0.6 million $ 0.6 million $ 7.0 million
Non-cash investing activities in 1998 included the forgiveness of a note and
related interest receivable valued at $10.1 million in exchange for the title to
a 32-mile pipeline in Michigan.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement No. 133,
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES. This statement, as
amended by SFAS No. 137, is effective for fiscal years beginning after June 15,
2000. Earlier application is encouraged; however, the Company does not
anticipate adopting SFAS No. 133 until the fiscal year beginning January 1,
2001. SFAS No. 133 requires an entity to recognize all derivatives as assets or
liabilities in the balance sheet and measure those instruments at fair value.
Although the Company is currently evaluating SFAS No. 133, it is not expected to
have a material impact on the financial condition or results of operations of
the Company.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
RECLASSIFICATIONS
Certain prior year amounts have been reclassified to conform to the 1999
presentation.
NOTE 3. DEBT
CREDIT FACILITY
Effective September 29, 1999, the Company amended and restated its existing
credit agreement. The amended and restated agreement with two commercial banks
extends through the year 2005 and provides for a maximum borrowing amount of $50
million pursuant to a revolving loan commitment. Actual borrowing limits may be
a lesser amount, depending on trailing cash flow, as defined in the agreement.
The credit facility permits the Company to borrow money using either a base rate
loan or a London Interbank Offered Rate loan option, plus an applicable margin
of between 0% and 2.75%, based on a certain Company debt to earnings ratio. At
December 31, 1999, the Company had $40.5 million outstanding under the credit
facility bearing interest at an average rate of 9.25%. At December 31, 1998, the
Company had $35 million outstanding under the credit facility bearing interest
at an average rate of 7.8%. The Company pays a fee at a rate between 0.25% and
0.50% per annum on the unused commitment, based on a certain Company debt to
earnings ratio. The credit facility is secured by a first mortgage on the
Company's major assets. The loan agreement restricts certain activities and
requires the maintenance of certain financial ratios and other conditions.
155 INVERNESS BUILDING LOAN
Effective January 14, 1998, the Company's wholly owned subsidiary, 155
Inverness, Inc., obtained a $3.7 million loan from an insurance company to
refinance an office building. As of December 31, 1999, approximately $3.6
million was outstanding under the note. The Company sold the office building in
February 2000 for net cash proceeds of $5.0 million, resulting in a loss of
24
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
approximately $0.1 million. In accordance with SFAS No. 121, ACCOUNTING FOR THE
IMPAIRMENT OF LONG-LIVED ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED OF, the
Company recognized this loss in 1999.
SCHEDULED DEBT MATURITIES
Scheduled debt maturities, excluding the Company's building loan paid off in
February 2000, as of December 31, 1999, are as follows (in 000s):
2000 .................... $ 42
2001 .................... --
2002 .................... 3,000
2003..................... 12,500
2004 and thereafter...... 25,000
----------
Total.................... $40,542
==========
NOTE 4. RELATED PARTY TRANSACTIONS
The Company, through its wholly owned subsidiary, MarkWest Resources, Inc.
("Resources"), holds varied undivided interests in several exploration and
production assets owned jointly with MAK-J Energy Partners Ltd. ("MAK-J"), which
owns a 51% undivided interest in such properties. The general partner of MAK-J
is a corporation owned and controlled by the President and Chief Executive
Officer of the Company. The properties are held pursuant to operating agreements
entered into between Resources and MAK-J. Resources is the operator under such
agreements. As the operator, Resources is obligated to provide certain
engineering, administrative and accounting services to the joint ventures. The
joint venture agreements provide for a monthly fee payable to Resources for all
such expenses. As of December 31, 1999 and 1998, the Company has receivables due
from MAK-J for approximately $426,000 and $0, and payables to MAK-J for
approximately $400,000 and $488,000, respectively.
The Company made contributions of $328,000, $164,000 and $271,000 to a
profit-sharing plan for the years ended December 31, 1999, 1998 and 1997,
respectively. The plan is discretionary, with annual contributions determined by
the Company's Board of Directors.
NOTE 5. LEASE OBLIGATIONS
The Company has various non-cancelable operating lease agreements for equipment
and office space expiring at various times though fiscal 2010. Rent expense
under these operating leases was approximately $615,000 and $222,000 for the
years ended December 31, 1999 and 1998, respectively. The Company's minimum
future lease payments under these operating leases as of December 31, 1999, are
as follows (in 000s):
2000 .................... $1,119
2001 .................... 1,210
2002 .................... 1,210
2003..................... 1,220
2004 and thereafter...... 5,517
----------
Total.................... $10,276
==========
NOTE 6. SIGNIFICANT CUSTOMERS
For the years ended December 31, 1998 and 1997, sales to one customer accounted
for approximately 9% and 19% of total revenues. There were no significant
customers for the year ended December 31, 1999.
NOTE 7. COMMODITY PRICE RISK MANAGEMENT
The Company's primary risk management objectives are to meet or exceed budgeted
gross margins by locking in budgeted or above-budgeted prices in the financial
derivatives and physical markets and to protect margins from precipitous
declines. Hedging levels increase with capital commitments and debt levels and
when above-average margins exist. The Company maintains a committee, including
members of senior management, which oversees all hedging activity.
MarkWest achieves its goals utilizing a combination of fixed-price forward
contracts, New York Mercantile Exchange- ("NYMEX") traded futures, and
fixed/floating price swaps on the over-the-counter ("OTC") market. Futures and
swaps allow the Company to
25
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
protect margins, because gains or losses in the physical market are generally
offset by corresponding losses or gains in the value of financial instruments.
The Company enters into futures transactions on NYMEX and through OTC swaps with
various counterparties, consisting primarily of other energy companies. The
Company conducts its standard credit review of OTC counterparties and has
agreements with such parties that contain collateral requirements. The Company
generally uses standardized swap agreements that allow for offset of positive
and negative exposures. OTC exposure is marked to market daily for the credit
review process. The Company's OTC credit risk exposure is partially limited by
its ability to require a margin deposit from its major counterparties based upon
the mark-to-market value of their net exposure. The Company is subject to margin
deposit requirements under NYMEX and OTC agreements.
The use of financial instruments may expose the Company to the risk of financial
loss in certain circumstances, including instances when (a) equity volumes are
less than expected, or (b) the Company's OTC counterparties fail to purchase or
deliver the contracted quantities of natural gas, NGLs, or crude oil or
otherwise fail to perform. To the extent that the Company engages in hedging
activities, it may be prevented from realizing the benefits of favorable price
changes in the physical market. However, it is similarly insulated against
decreases in such prices.
MarkWest seeks to reduce its basis risk for natural gas but is generally unable
to do so for NGLs. Basis is the difference in price between the physical
commodity being hedged and the price of the futures or physical contract used
for hedging. Basis risk is the risk that an adverse change in the futures or
physical market will not be completely offset by an equal and opposite change in
the cash price of the commodity being hedged. The Company's basis risk primarily
stems from the geographic price differentials between MarkWest's sales locations
and futures or OTC contract delivery locations.
The Company protects Appalachia processing margins using a combination of three
different methods. MarkWest protects margins by purchasing natural gas priced on
predetermined Btu differentials to propane or crude prices. As of December 31,
1999, the Company had no open positions of this transaction type. MarkWest also
protects margins by purchasing natural gas while simultaneously selling propane
of approximately the same Btu value. As of December 31, 1999, the Company had
locked in an approximate margin of $0.23 per gallon on 7.6 million gallons of
the Company's expected production through February 2000. Finally, MarkWest
protects its margins by selling crude and purchasing natural gas. As of December
31, 1999, the Company had locked in an approximate margin of $0.15 per gallon on
26.9 million gallons of the Company's expected production through December 2000.
Crude oil is highly correlated with certain NGL products. All projected margins
on open positions at December 31, 1999, assume the basis differentials between
the Company's sales location and the hedging contract's specified location and
between crude oil and NGLs are consistent with historical averages. No basis
risk was hedged except for a portion of the natural gas.
Given the size of the Company's capital expenditure program, the Company's
primary hedging strategy in 1999 was designed to protect a portion of its
Appalachian margins against a further decline in product prices from those
experienced in the first quarter of that year. This strategy limited the benefit
to MarkWest of the increase in margins seen in the second half of 1999.
Consequently, net income would have been higher by approximately $0.9 million
for 1999 had the hedge positions not been in place.
The Company hedges exposure to changes in spot market prices on certain levels
of natural gas production. As of December 31, 1999, the Company locked in an
average sales price of $1.97/Mcf on 4,000 Mcfd of production through October
2000, an average sales price of $2.29/Mcf on 3,000 Mcfd of November 2000 to
October 2001 production, and an average sales price of $2.39/Mcf on 1,000 Mcfd
of November 2001 to October 2002 production.
The Company enters into speculative futures transactions on an infrequent basis.
Specific approval by the Board of Directors is necessary prior to executing such
transactions. Speculative futures are marked to market at the end of each
accounting period, and any gain or loss is recognized in income for that period.
Results from such speculative activities for the years ended December 31, 1999
and 1998, were not material.
In addition to these risk management tools, MarkWest utilizes its NGL storage
facilities and contracts for third-party storage to build product inventories
during historically lower-priced periods for resale during higher-priced
periods. Also, MarkWest has contractual arrangements to purchase certain
quantities of its natural gas feedstock in advance of physical needs.
26
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 8. INCOME TAXES
The provision (benefit) for income taxes is comprised of (in 000s):
Year Ended December 31,
----------------------------------------
1999 1998 1997
------------ ------------ ------------
Current:
Federal...................... $ 788 $(1,921) $ 2,510
State........................ (29) (314) 408
------------ ------------ ------------
Total current................ 759 (2,235) 2,918
------------ ------------ ------------
Deferred:
Federal...................... 664 1,413 1,419
State........................ 278 55 213
------------ ------------ ------------
Total deferred............... 942 1,468 1,632
------------ ------------ ------------
Total tax provision.......... $ 1,701 $ (767) $ 4,550
============ ============ ============
The deferred tax liabilities (assets) are comprised of the tax effect of the
following (in 000s):
1999 1998
----------- ----------
Property and equipment........................ $ 9,840 $6,934
Other assets.................................. 224 300
----------- ----------
Total deferred income tax liabilities.... 10,064 7,234
----------- ----------
Alternative minimum tax ("AMT") credit
carryforward................................ (1,888) --
State net operating loss ("NOL") carryforwards (151) (151)
Intangible assets............................. (6) (6)
----------- ----------
Total deferred income tax assets......... (2,045) (157)
----------- ----------
Net deferred tax liability............... $ 8,019 $7,077
=========== ==========
The differences between the provision for income taxes at the statutory rate and
the actual provision for income taxes for the years ended December 31, 1999,
1998 and 1997, are as follows (in 000s):
1999 % 1998 % 1997 %
---------- ---------- ----------- --------- ------------ ----------
Income tax at statutory rate...... $1,583 35.0% $(672) (34.0%) $4,339 35.0%
State income taxes, net of federal
benefit....................... 168 3.7% (102) (5.1%) 403 3.3%
Credits........................... (75) (1.7%) -- -- (204) (1.6%)
Other............................. 25 0.6% 7 0.3% 12 0.1%
---------- ---------- ----------- --------- ------------ ----------
Total......................... $1,701 37.6% $(767) 38.8% $4,550 36.8%
========== ========== =========== ========= ============ ==========
27
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
At December 31, 1999, the Company had NOL carryforwards for state income tax
purposes and AMT credit carryforwards for federal income tax purposes of
approximately $2.2 million and $1.9 million, respectively. These carryforwards
expire as follows (000s):
Expiration
Dates NOL AMT
------------- ---------- -----------
2004............ $ 565 $ --
2014............ 1,645 --
No expiration... -- 1,888
---------- -----------
Total $ 2,210 $ 1,888
========== ===========
The Company believes that the carryforwards will be utilized prior to their
expiration. They are expected to be realized by achieving future profitable
operations based on the Company's dedicated and owned reserves, dedicated
reserves behind its processing plants, past earnings history, and projections of
future earnings.
NOTE 9. STOCK COMPENSATION PLANS
At December 31, 1999, the Company has two stock-based compensation plans, which
are described below. The Company applies APB Opinion No. 25, ACCOUNTING FOR
STOCK ISSUED TO EMPLOYEES, and related Interpretations in accounting for its
plans. Accordingly, no compensation cost has been recognized for its fixed stock
option plans. Had compensation cost for the Company's two stock-based
compensation plans been determined based on the fair value at the grant dates
under those plans consistent with the method prescribed by SFAS No. 123,
ACCOUNTING FOR STOCK-BASED COMPENSATION, the Company's pro forma net income and
earnings per share would have been reduced to the pro forma amounts listed below
(in 000s, except per share data):
1999 1998 1997
------------- ------------- -------------
Net income (loss) As reported.......... $ 2,823 $ (1,211) $ 7,847
Pro forma............ 2,428 (1,483) 7,732
Basic earnings (loss) per share As reported.......... $ 0.33 $ (0.14) $ 0.92
Pro forma............ 0.29 (0.17) 0.91
Earnings (loss) per share As reported.......... $ 0.33 $ (0.14) $ 0.91
assuming dilution Pro forma............ 0.29 $ (0.17) $ 0.89
Under the 1996 Stock Incentive Plan, the Company may grant options to its
employees for up to 850,000 shares of common stock in the aggregate. Under this
plan, the exercise price of each option equals the market price of the Company's
stock on the date of the grant, and an option's maximum term is ten years.
Options are granted periodically throughout the year and vest at the rate of 25%
per year for 1999 option grants and 20% per year for options granted prior to
1999.
Under the 1996 Non-employee Director Stock Option Plan, the Company may grant
options to its non-employee directors for up to 20,000 shares of common stock in
the aggregate. Under this plan, the exercise price of each option equals the
market price of the Company's stock on the date of the grant, and an option's
maximum term is three years. Options are granted upon the date the director
first becomes a director and biannually thereafter. Options granted upon the
date the director first becomes a director vest at the rate of 33.33% per year.
Biannual options vest 100% on the first anniversary of the option grant date.
Effective October 1, 1998, the Company repriced all stock options granted in
1997 and mid-1998. The stock options were repriced at $10.75 per share, the fair
market value on October 1, 1998.
The fair value of each option is estimated on the date of grant using the
Black-Scholes Option Pricing model with the following weighted-average
assumptions: dividend yield of $0/share for options granted in 1999, 1998 and
1997; expected volatility of 40% for the 1999 option grants, 34% for 1998 option
grants and 30% for 1997 option grants; risk-free interest rate of 6.22% for 1999
option grants, 4.35% for 1998 option grants, 5.83% for 1997 option grants;
expected lives of 6 years for 1999, 1998 and 1997 option grants.
28
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A summary of the status of the Company's two fixed stock option plans as of
December 31, 1999, 1998 and 1997, and changes during the years ended on those
dates are presented below:
1999 1998 1997
---------------------------- ----------------------------- -----------------------------
Weighted- Weighted- Weighted
Average Average -Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
---------- ---------------- ------------ ---------------- ----------- ---------------
FIXED OPTIONS
Outstanding at beginning of year....... 514,503 $ 9.78 383,490 $ 12.50 276,749 $ 8.30
Granted................................ 141,672 7.03 374,162 11.53 159,374 18.21
Exercised.............................. -- -- (11,482) 7.73 (34,724) 7.24
Canceled............................... (35,058) 9.86 (231,667) 17.21 (17,909) 8.55
------------ ------------ ------------ ------------- ------------- ---------
Outstanding at end of year............. 621,117 $ 9.15 514,503 $ 9.78 383,490 $ 12.50
============ ============ ============ ============= ============= =========
Options exercisable at December 31,
1999, 1998 and 1997, respectively.... 230,808 148,840 88,926
Weighted-average fair value of
options granted during the year...... $ 3.42 $ 4.72 $ 7.52
The following table summarizes information about fixed stock options outstanding
at December 31, 1999:
Options Outstanding Options Exercisable
------------------------------------------------- -----------------------------
Weighted-
Average Weighted- Weighted-
Number Remaining Average Number Average
Outstanding Contractual Exercise Exercisable Exercise
Range of Exercise Prices at 12/31/99 Life Price At 12/31/99 Price
- ----------------------------- -------------- -------------- ------------- -------------- ------------
$5.38 to $8.63.............. 243,870 7.0 $ 7.05 88,882 $ 7.09
$9.13 to $10.50............. 170,660 6.7 $10.20 69,244 $ 10.10
$10.75 ..................... 206,587 7.7 $10.75 72,682 $ 10.75
-------------- --------------
621,117 7.2 230,808
============== ==============
NOTE 10. EARNINGS PER SHARE
The following table shows the amounts used in computing earnings per share and
weighted average number of shares of dilutive potential common stock for the
years ended December 31, 1999, 1998 and 1997 (in 000s, except per share data):
For the Year Ended December 31,
------------------------------------------
1999 1998 1997
------------- ------------- ------------
Net income (loss)................ $2,823 $(1,211) $7,847
============= ============= ============
Weighted average number of
outstanding shares of common
stock used in earnings per
share......................... 8,475 8,490 8,485
Effect of dilutive securities:
Stock options................. 6 -- 129
------------- ------------- ------------
Weighted average number of
outstanding shares of common
stock used in earnings per
share assuming dilution....... 8,481 8,490 8,614
============= ============= ============
29
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11. SEGMENT REPORTING
The Company's operations are classified into two principal reportable segments,
as follows:
(1) Processing and Related Services--provides compression, gathering,
treatment and NGL extraction, and fractionation services; also purchases
and markets natural gas and NGLs;
(2) Exploration and Production--explores for and produces natural gas.
The accounting policies of the segments are the same as those described in the
"Summary of Significant Accounting Policies." There are no intersegment
revenues. MarkWest evaluates the performance of its segments and allocates
resources to them based on gross operating income. MarkWest's business is
conducted solely in the United States.
The table below presents information about gross operating income for the
reported segments for the three years ended December 31, 1999. Asset information
by reportable segment is not reported, since MarkWest does not produce such
information internally.
Processing and Exploration and
Related Services Production Total
----------------- ----------------- --------------
1999 (in 000s):
Revenues.................. $ 104,810 $1,538 $106,348
Gross operating income.... $ 16,419 $ 620 $17,039
1998 (in 000s):
Revenues.................. $ 62,438 $1,184 $63,622
Gross operating income.... $ 9,593 $ 361 $ 9,954
1997 (in 000s):
Revenues.................. $ 77,938 $ 888 $78,826
Gross operating income.... $ 21,792 $ 91 $21,883
A reconciliation of total segment revenues to total consolidated revenues and of
total segment gross operating income to total consolidated income, for the years
ended December 31, 1999, 1998 and 1997, is as follows:
1999 1998 1997
------------ ------------- ------------
Revenues:
Total segment revenues............. $106,348 $ 63,622 $78,826
Interest income.................... 53 200 661
Other income (expense)............. 2,233 (124) 196
------------ ------------- ------------
Total consolidated revenues.. $108,634 $ 63,698 $79,683
============ ============= ============
Gross operating income:
Total segment gross operating income $17,039 $ 9,954 $21,883
General and administrative expenses (6,986) (5,319) (6,651)
Depreciation and amortization...... (5,070) (4,594) (3,246)
Interest expense................... (2,745) (2,095) (826)
Interest income.................... 53 200 661
Other income (expense)............. 2,233 (124) 196
Minority interest in net loss of
subsidiary....................... -- -- 380
------------ ------------- ------------
Consolidated income (loss)
before taxes............... $ 4,524 $ (1,978) $12,397
============ ============= ============
30
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 12. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The following summarizes certain quarterly results of operations (in 000s):
First Second Third Fourth
----- ------ ----- ------
1999 (1)
- ----
Revenue (2)................... $ 22,077 $ 20,458 $ 30,436 $ 35,610
Gross profit (loss) (3)....... 2,524 3,254 2,129 6,295
Net income (loss)............. 111 577 59 2,076
Basic earnings (loss) per
share ...................... $ 0.01 $ 0.07 $ 0.01 $ 0.24
Earnings (loss) per share
assuming dilution .......... $ 0.01 $ 0.07 $ 0.01 $ 0.24
1998
- ----
Revenue (2)................... $ 20,231 $ 11,010 $ 14,092 $ 18,165
Gross profit (loss) (3)....... 3,308 (53) 359 1,622
Net income (loss)............. 917 (1,140) (876) (112)
Basic earnings (loss) per
share ...................... $ 0.11 $ (0.13) $ (0.10) $ (0.01)
Earnings (loss) per share
assuming dilution ............ $ 0.11 $ (0.13) $ (0.10) $ (0.01)
- --------------------------
(1) Includes $2.5 million gain ($1.5 million, or $0.18 per share, after tax)
on the sale of the Company's West Memphis terminal in the second quarter
of 1999.
(2) Excludes interest income.
(3) Excludes interest income, general and administrative expenses, and
interest expense.
NOTE 13. SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
COSTS
The following tables set forth capitalized costs at December 31, 1999, 1998 and
1997, and costs incurred for oil and gas producing activities for the years
ended December 31, 1999, 1998 and 1997 (in 000s):
1999 1998 1997
--------- --------- ---------
Capitalized costs:
Proved properties...................... $11,167 $ 8,001 $5,308
Unproved properties.................... 1,972 1,206 1,462
Equipment and facilities............... 1,379 1,349 1,145
--------- --------- ---------
Total..................................... 14,518 10,556 7,915
Less accumulated depreciation,
depletion and amortization......... (1,362) (801) (406)
========= ========= =========
Net capitalized costs..................... $13,156 $ 9,755 $7,509
========= ========= =========
Costs incurred:
Acquisition of properties
Proved................................. $ 1,503 $ 2,632 $ 180
Unproved............................... 728 12 1,016
Development costs......................... 1,776 559 2,170
Exploration costs......................... 435 284 250
--------- --------- ---------
Total costs incurred...................... $ 4,442 $ 3,487 $3,616
========= ========= =========
31
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
RESULTS OF OPERATIONS
The results of operations for oil and gas producing activities, excluding
corporate overhead and interest costs, for the years ended December 31, 1999,
1998 and 1997, are as follows (in 000s):
1999 1998 1997
--------- --------- ---------
Revenues from sale of oil and gas:
Sales.................................. $1,804 $1,552 $ 918
Other.................................. 182 40 208
--------- --------- ---------
Total............................ 1,986 1,592 1,126
Production costs:
Transportation and taxes............... (448) (408) (238)
Lease operating expense and other...... (918) (823) (797)
--------- --------- ---------
Total............................... (1,366) (1,231) (1,035)
Gross operating income.................... 620 361 91
Depreciation, depletion and amortization.. (561) (431) (204)
Income tax benefit........................ 53 27 323
--------- --------- ---------
Results of operations..................... $ 112 $ (43) $ 210
========= ========= =========
RESERVE QUANTITY INFORMATION
Reserve estimates are subject to numerous uncertainties inherent in the
estimation of quantities of proved reserves and in the projection of future
rates of production and the timing of development expenditures. The accuracy of
such estimates is a function of the quality of available data and of engineering
and geological interpretation and judgment. Estimates of economically
recoverable reserves and of future net cash flows expected therefrom prepared by
different engineers or by the same engineers at different times may vary
substantially. Results of subsequent drilling, testing and production may cause
either upward or downward revisions of previous estimates. Further, the volumes
considered to be commercially recoverable fluctuate with changes in commodity
prices and operating costs. Any significant revision of reserve estimates could
materially adversely affect the Company's financial condition and results of
operations.
The following table sets forth information for the years ended December 31,
1999, 1998 and 1997, with respect to changes in the Company's proved reserves,
all of which are in the United States.
1999 1998 1997
--------------------------- ---------------------------- ----------------------------
Natural Gas Oil Natural Gas Oil Natural Gas Oil
(Mcf) (bbls) (Mcf) (bbls) (Mcf) (bbls)
-------------- --------- -------------- --------- ------------- -----------
Proved developed and
undeveloped
reserves:
Beginning of year........ 26,048,300 -- 23,155,910 6,736 6,231,005 21,748
Revisions of previous
estimates............. 1,031,719 -- 1,164,111 (1,289) (548,185) (15,026)
Purchase of minerals
in place.............. 2,252,853 -- 3,029,036 -- -- --
Extensions and
discoveries........... 4,355,359 -- 129,029 14 17,965,809 14
Production............... (968,671) -- (850,041) -- (492,719) --
Sale of minerals in
place................. -- -- (579,745) (5,461) -- --
-------------- --------- -------------- --------- ------------- -----------
End of year.............. 32,719,560 -- 26,048,300 -- 23,155,910 6,736
============== ========= ============== ========= ============= ===========
32
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1999 1998 1997
--------------------------- ---------------------------- ----------------------------
Natural Gas Oil Natural Gas Oil Natural Gas Oil
(Mcf) (bbls) (Mcf) (bbls) (Mcf) (bbls)
-------------- --------- -------------- --------- ------------- -----------
Proved developed
reserves:
Beginning of year........ 13,664,760 -- 11,025,140 6,736 6,156,645 21,748
============== ========= ============== ========= ============= ===========
End of year.............. 22,113,900 -- 13,664,760 -- 11,025,140 6,736
============== ========= ============== ========= ============= ===========
STANDARDIZED MEASURES OF DISCOUNTED FUTURE NET CASH FLOWS
Estimated discounted future net cash flows and changes therein were determined
in accordance with SFAS No. 69, DISCLOSURES ABOUT OIL AND GAS PRODUCING
ACTIVITIES. Certain information concerning the assumptions used in computing the
valuation of proved reserves and their inherent limitations are discussed below.
The Company believes such information is essential for a proper understanding
and assessment of the data presented.
Future cash inflows are computed by applying year-end prices of oil and gas
relating to the Company's proved reserves to the year-end quantities of those
reserves. Future price changes are considered only to the extent provided by
contractual arrangements, including futures contracts in existence at year end.
The assumptions used to compute estimated future net revenues do not necessarily
reflect the Company's expectations of actual revenues or costs, or their present
worth. In addition, variations from the expected production rate also could
result directly or indirectly from factors outside of the Company's control,
such as unintentional delays in development, changes in prices or regulatory
controls. The reserve valuation further assumes that all reserves will be
disposed of by production. However, if reserves are sold in place, additional
economic considerations could also affect the amount of cash eventually
realized.
Future development and production costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and gas
reserves at the end of the year, based on year-end costs and assuming
continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate year-end
statutory tax rates, with consideration of future tax rates already legislated,
to the future pretax net cash flows relating to the Company's proved oil and gas
reserves. Permanent differences in oil and gas-related tax credits and
allowances are recognized.
An annual discount rate of 10% was used to reflect the timing of the future net
cash flows relating to proved oil and gas reserves.
Information with respect to the Company's estimated discounted future net cash
flows from its oil and gas properties for the years ended December 31, 1999,
1998 and 1997, is as follows (in 000s):
1999 1998 1997
------------ ------------ ------------
Future cash inflows....................... $ 75,290 $ 51,055 $ 54,757
Future production costs................... (32,541) (26,886) (26,235)
Future development costs.................. (2,970) (3,623) (3,650)
Future income tax expense................. (12,982) (7,302) (7,464)
------------ ------------ ------------
Future net cash flows..................... 26,797 13,244 17,408
10% annual discount for estimated timing
of cash flows........................... (15,332) (8,271) (9,348)
------------ ------------ ------------
Standardized measure of discounted future
net cash flows relating to proved
oil and gas reserves................... $ 11,465 $ 4,973 $ 8,060
============ ============ ============
33
MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Principal changes in the Company's estimated discounted future net cash flows
for the years ended December 31, 1999, 1998 and 1997, are as follows (in 000s):
1999 1998 1997
---------- ---------- ----------
January 1....................................... $4,973 $8,060 $2,016
Sales and transfers of oil and gas produced,
net of production costs................... (620) (361) (91)
Net changes in prices and production costs
related to future production.............. 3,332 (3,158) 871
Previously estimated development costs
incurred during the period................ 654 355 1,608
Changes in estimated future development costs -- (339) (1,471)
Extensions and discoveries................... 3,260 81 6,936
Revisions of previous quantity estimates..... 492 316 (428)
Purchases of reserves in place............... 1,432 1,471 --
Sales of reserves in place .................. -- (673) --
Changes in production rates and other ....... (708) (2,116) 2
Accretion of discount........................ 753 1,086 313
Net change in income taxes................... (2,103) 251 (1,696)
---------- ---------- ----------
December 31..................................... $11,465 $4,973 $8,060
========== ========== ==========
34
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12 and 13 are omitted
because the Company will file a definitive proxy statement pursuant to
Regulation 14A under the Exchange Act of 1934 not later than 120 days after the
close of the fiscal year. The information required by such Items will be
included in the definitive proxy statement to be so filed for the Company's
annual meeting of stockholders scheduled for May 18, 2000, and is hereby
incorporated by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
(1) Financial Statements:
Reference is made to the Index to Consolidated Financial Statements
included in this Form 10-K for a list of all financial statements
filed as a part of this report.
(2) Financial Statement Schedules:
None required.
(3) Exhibits: See (c) below.
(b) Reports on Form 8-K:
A report on Form 8-K was filed on October 25, 1999, announcing the
settlement of all outstanding arbitration and litigation between MarkWest
and Columbia Gas Transmission Corporation, and announcing the expected
expansion of its Kenova NGL extraction plant.
(c) Exhibits required by Item 601 of Regulation S-K. See (a) (3) above.
2.1 Purchase and Sale Agreement between MarkWest Hydrocarbon, Inc.,
and Michigan Energy Company, L.L.C., dated November 21, 1997 (filed
as Exhibit 2.1 to MarkWest Hydrocarbon, Inc.'s Form 8-K filed on
January 29, 1998, and incorporated herein by reference).
3.1 Certificate of Incorporation of MarkWest Hydrocarbon, Inc. (filed
as Exhibit 3.1). (1)
3.2 Bylaws of MarkWest Hydrocarbon, Inc. (1)
10.1 Amended and Restated Reorganization Agreement made as of August 1,
1996, by and among MarkWest Hydrocarbon, Inc.; MarkWest Hydrocarbon
Partners, Ltd.; MWHC Holding, Inc.; RIMCO Associates, Inc.; and each
of the limited partners of MarkWest Hydrocarbon Partners, Ltd. (1)
10.2 1996 Incentive Compensation Plan (filed as Exhibit 10.25). (1)
10.3 1996 Stock Incentive Plan (filed as Exhibit 10.26). (1)
10.4 1996 Non-employee Director Stock Option Plan (filed as Exhibit
10.27). (1)
10.5 Form of Non-Compete Agreement between John M. Fox and MarkWest
Hydrocarbon, Inc. (filed as Exhibit 10.28). (1)
10.6 MarkWest Hydrocarbon, Inc., 1997 Severance and Non-Compete Plan
(filed as Exhibit 10.1 to MarkWest Hydrocarbon, Inc.'s Form 10-Q for
the three months ended September 30, 1997, and incorporated herein
by reference).
10.7 Second Amended and Restated Credit Agreement, dated as of September
29, 1999, among MarkWest Hydrocarbon, Inc., as the Borrower; and
Certain Commercial Lending Institutions as the Lenders; and Bank of
America, N.A., as the Administrative Agent and the Syndication Agent
for the Lenders (filed as Exhibit 10 to MarkWest Hydrocarbon, Inc.'s
Form 10-Q for the three months ended September 30, 1999, and
incorporated herein by reference).
11. Statement regarding computation of earnings per share.
21. List of Subsidiaries of MarkWest Hydrocarbon, Inc.
23. Consent of PricewaterhouseCoopers LLP.
27. Financial Data Schedule.
- ------------------------
(1) Incorporated by reference to MarkWest Hydrocarbon, Inc.'s Registration
Statement on Form S-1, Registration No. 333-09513.
35
SIGNATURES
Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this Report to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Englewood,
State of Colorado, on March 20, 2000.
MarkWest Hydrocarbon, Inc.
(Registrant)
BY: /s/ John M. Fox
-------------------------
John M. Fox
President and Chief
Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
/s/ John M. Fox March 20, 2000
--------------------------------
John M. Fox
President, Chief Executive
Officer and Director
/s/ Brian T. O'neill March 20, 2000
--------------------------------
Brian T. O'Neill
Senior Vice President, Chief
Operating Officer and Director
/s/ Gerald A. Tywoniuk March 20, 2000
--------------------------------
Gerald A. Tywoniuk
Chief Financial Officer and
Vice President of Finance
(Principal Financial and
Accounting Officer)
/s/ Arthur J. Denney March 20, 2000
--------------------------------
Arthur J. Denney
Director
/s/ Barry W. Spector March 20, 2000
--------------------------------
Barry W. Spector
Director
/s/ Donald D. Wolf March 20, 2000
--------------------------------
Donald D. Wolf
Director
36