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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
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
- ----- EXCHANGE ACT OF 1934
Commission file number 1-12295
GENESIS ENERGY, L.P.
(Exact name of registrant as specified in its charter)
Delaware 76-0513049
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
500 Dallas, Suite 2500, Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 860-2500
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
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Common Units New York 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
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
X
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Aggregate market value of the Common Units held by non-affiliates of the
Registrant, based on closing prices in the daily composite list for transactions
on the New York Stock Exchange on March 1, 2000, was approximately $68 million.
At March 31, 2000, 8,624,910 Common Units were outstanding.
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GENESIS ENERGY, L.P.
1999 FORM 10-K ANNUAL REPORT
Table of Contents
Page
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Part I
Item 1. Business 3
Item 2. Properties 9
Item 3. Legal Proceedings 10
Item 4. Submission of Matters to a Vote of Security Holders 10
Part II
Item 5. Market for Registrant's Common Units and Related Security
Holder Matters 11
Item 6. Selected Financial Data 12
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 13
Item 7a.Quantitative and Qualitative Disclosures about Market Risk 19
Item 8. Financial Statements and Supplementary Data 19
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 20
Part III
Item 10.Directors and Executive Officers of the Registrant 20
Item 11.Executive Compensation 22
Item 12.Security Ownership of Certain Beneficial Owners and
Management 25
Item 13.Certain Relationships and Related Transactions 26
Part IV
Item 14.Exhibits, Financial Statement Schedules and Reports on
Form 8-K 26
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PART I
Item 1. Business
General
Genesis Energy, L.P., a Delaware limited partnership, was formed in
December 1996. With the proceeds of an offering of common limited partnership
units ("Common Units") to the public, Genesis Energy, L.P., through its
affiliated limited partnership, Genesis Crude Oil, L.P., and its subsidiary
partnerships (collectively the "Partnership" or "Genesis") acquired the crude
oil gathering and marketing operations of Basis Petroleum, Inc. ("Basis") and
the crude oil gathering, marketing and pipeline operations of Howell Corporation
and its subsidiaries ("Howell"). The Partnership is one of the largest
independent gatherers and marketers of crude oil in North America. Genesis'
operations are concentrated in Texas, Louisiana, Alabama, Florida, Mississippi,
New Mexico, Kansas and Oklahoma. In its gathering and marketing business,
Genesis is principally engaged in the purchase and aggregation of crude oil at
the wellhead and the bulk purchase of crude oil at pipeline and terminal
facilities for resale at various points along the crude oil distribution chain,
which extends from the wellhead to aggregation and terminal facilities,
refineries and other end markets (the "Distribution Chain"). The Partnership's
gathering and marketing margins are generated by buying crude oil at competitive
prices, efficiently transporting or exchanging the crude oil along the
Distribution Chain and marketing the crude oil to refineries or other customers
at favorable prices. In addition to its gathering and marketing business,
Genesis' operations include transportation of crude oil at regulated published
tariffs on its three common carrier pipeline systems.
Genesis utilizes its trucking fleet of approximately 76 tractor-trailers
and its gathering lines to transport crude oil purchased at the wellhead to
pipeline injection points, terminals and refineries for sale to its customers.
It also transports purchased crude oil on trucks, barges and pipelines owned and
operated by third parties. In addition, as part of its gathering and marketing
business, Genesis makes purchases of crude oil in bulk at pipeline and terminal
facilities for resale to refineries or other customers. When opportunities
arise to increase margin or to acquire a grade of crude oil that more nearly
matches the specifications for crude oil the Partnership is obligated to
deliver, Genesis exchanges crude oil with third parties through exchange or
buy/sell agreements. In the fourth quarter of 1999, Genesis purchased an
average of approximately 99,000 barrels per day of crude oil at the wellhead
from approximately 9,600 leases.
Genesis currently transports a total of approximately 91,000 barrels per
day on its three common carrier crude oil pipeline systems and related gathering
lines. These systems are the Texas System, the Jay System extending between
Florida and Alabama, and the Mississippi System extending between Mississippi
and Louisiana. In October 1998, Genesis acquired 200 additional miles of
pipelines and gathering lines that have become part of its Texas System. This
additional pipeline mileage extends from the West Columbia area in Texas to
Webster, Texas. Approximately 2.0 million barrels of associated storage
capacity is owned by Genesis.
Genesis Energy, L.L.C. (the "General Partner"), a Delaware limited
liability company, serves as the sole general partner of Genesis Energy, L.P.,
and as the operating general partner of its affiliated limited partnership,
Genesis Crude Oil, L.P. (GCOLP) and GCOLP's subsidiary partnerships, Genesis
Pipeline Texas, L.P. and Genesis Pipeline USA, L.P. The General Partner was
owned 54% by Salomon Smith Barney Holdings Inc. ("Salomon") and 46% by Howell.
Effective February 28, 2000, Salomon acquired Howell's 46% interest in the
General Partner. Salomon also owns 1,163,700 subordinated limited partner units
in GCOLP, representing 10.58% of GCOLP. Howell owns 991,300 subordinated
limited partner units in GCOLP, representing 9.01% of GCOLP. These subordinated
limited partner interests are hereinafter referred to as Subordinated OLP Units.
Business Overview
In its gathering and marketing business, the Partnership seeks to purchase
and sell crude oil at points along the Distribution Chain where gross margins
can be achieved. Genesis generally purchases crude oil at prevailing prices
from producers at the wellhead under short-term contracts or in bulk from major
oil companies, intermediaries and other third parties. Genesis then transports
the crude oil along the Distribution Chain for sale to or exchange with
customers. The Partnership's margins from its gathering and marketing
operations are generated by the difference between the price of crude oil at the
point of purchase and the price of crude oil at the point of sale, minus the
associated costs of aggregation and transportation. Genesis generally enters
into an exchange transaction only when the cost of the exchange is less than the
alternative costs that it would otherwise incur in transporting or storing the
crude oil. In addition, Genesis often exchanges one grade of crude oil for
another to maximize margins or meet contract delivery requirements.
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Generally, as Genesis purchases crude oil, it simultaneously establishes a
margin by selling crude oil for physical delivery to third party users, such as
independent refiners or major oil companies, or by entering into a future
delivery obligation with respect to futures contracts on the New York Mercantile
Exchange ("NYMEX"). Through these transactions, the Partnership seeks to
maintain a position that is substantially balanced between crude oil purchases,
on the one hand, and sales or future delivery obligations, on the other hand.
It is the Partnership's policy not to acquire and hold crude oil, futures
contracts or other derivative products for the purpose of speculating on crude
oil price changes.
Gross margin from gathering, marketing and pipeline operations varies from
period to period, depending to a significant extent upon changes in the supply
and demand of crude oil and the resulting changes in U.S. crude oil inventory
levels.
Through the pipeline systems it owns and operates, the Partnership
transports crude oil for itself and others pursuant to tariff rates regulated by
the Federal Energy Regulatory Commission ("FERC") or the Texas Railroad
Commission. Accordingly, the Partnership offers transportation services to any
shipper of crude oil, provided that the products tendered for transportation
satisfy the conditions and specifications contained in the applicable tariff.
Pipeline revenues and gross margins are primarily a function of the level of
throughput and storage activity. The margins from the Partnership's pipeline
operations are generated by the difference between the regulated published
tariff and the fixed and variable costs of operating the pipeline.
Management Information and Risk Management Systems
Genesis' computerized management information and risk management systems
are integral to each stage of the gathering, transportation and marketing
operations. Hand-held computer terminals combined with modems and satellite
equipment are used by field personnel to provide data to Genesis' marketing
personnel about crude oil purchases on a daily basis. Using this information
from the field, management is able to monitor crude oil volumes, grades,
locations and timing of delivery on a daily basis and to transmit instructions
to field personnel regarding crude oil pick-up schedules and truck routing to
crude oil injection stations and end markets. Using information transmitted
from field personnel and representatives to its computers, Genesis has developed
a database that includes volumes of crude oil purchases, volumes and prices
under contracts with producers and customers, transportation costs and
alternatives, and marketing and exchange opportunities. Genesis uses this
database to support its management information and risk management systems.
Risk management strategies, including those involving price hedges using
NYMEX futures contracts, are important in creating and maintaining margins.
Such hedging techniques require significant resources dedicated to managing
forward positions and analyzing crude oil markets by grade and location so as to
manage these differentials. By analyzing information in its database with
internally developed software programs, Genesis is able to monitor crude oil
volumes, grades, locations and delivery schedules and to coordinate marketing
and exchange opportunities, as well as NYMEX hedging positions. This
coordination enables the Partnership to net positions internally, thereby
reducing NYMEX commissions, and further ensures that Genesis' NYMEX hedging
activities are consistent with its business objectives.
Producer Services
Crude oil purchasers who buy from producers compete on the basis of
competitive prices and highly responsive services. Through its team of crude
oil purchasing representatives, Genesis maintains ongoing relationships with
more than 580 producers. The Partnership believes that its ability to offer
high-quality field and administrative services to producers is a key factor in
its ability to maintain volumes of purchased crude oil and to obtain new
volumes. High-quality field services include efficient gathering capabilities,
availability of trucks, willingness to construct gathering pipelines where
economically justified, timely pickup of crude oil from tank batteries at the
lease or production point, accurate measurement of crude oil volumes received,
avoidance of spills and effective management of pipeline deliveries. Accounting
and other administrative services include securing division orders (statements
from interest owners affirming the division of ownership in crude oil purchased
by the Partnership), providing statements of the crude oil purchased each month,
disbursing production proceeds to interest owners and calculation and payment of
production taxes on behalf of interest owners. In order to compete effectively,
the Partnership must maintain records of title and division order interests in
an accurate and timely manner for purposes of making prompt and correct payment
of crude oil production proceeds on a monthly basis, together with the correct
payment of all severance and production taxes associated with such proceeds. In
1999, with its staff of division order specialists, Genesis distributed payments
to approximately 24,000 interest owners.
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Credit
Genesis' credit standing is a major consideration for parties with whom
Genesis does business. At times, in connection with its crude oil purchases or
exchanges, Genesis is required to furnish guarantees or letters of credit. In
most purchases from producers and most exchanges, an open line of credit is
extended by the seller up to a dollar limit, with credit support required for
amounts in excess of the limit.
In connection with the purchase, sale or exchange of crude oil, subject to
Genesis' compliance with specified terms and conditions, Salomon entered into a
Master Credit Support Agreement to provide credit support until December 31,
2000, in the form of guarantees issued from time to time at the Partnership's
request. In addition, the Partnership has a relationship with a bank to provide
a working capital facility. See Note 9 of Notes to Consolidated Financial
Statements.
When Genesis markets crude oil, it must determine the amount, if any, of
the line of credit to be extended to any given customer. Since typical sales
transactions can involve tens of thousands of barrels of crude oil, the risk of
nonpayment and nonperformance by customers is a major consideration in Genesis'
business. Management believes that Genesis' sales are made to creditworthy
entities or entities with adequate credit support.
Credit review and analysis are also integral to Genesis' leasehold
purchases. Payment for all or substantially all of the monthly leasehold
production is sometimes made to the operator of the lease, who is responsible
for the correct payment and distribution of such production proceeds to the
proper parties. In these situations, Genesis must determine whether the
operator has sufficient financial resources to make such payments and
distributions and to indemnify and defend Genesis in the event any third party
should bring a protest, action or complaint in connection with the ultimate
distribution of production proceeds by the operator.
Competition
In the various business activities described above, the Partnership is in
competition with a number of major oil companies and smaller entities. There is
intense competition among all participants in the business for leasehold
purchases of crude oil. The number and location of the Partnership's pipeline
systems and trucking facilities give the Partnership access to domestic crude
oil production throughout its area of operations. The Partnership purchases
leasehold barrels from more than 580 producers. In 1999, approximately 38% of
the leasehold barrels were purchased from ten producers.
The Partnership has considerable flexibility in marketing the volumes of
crude oil that it purchases, without dependence on any single customer or
transportation or storage facility. The Partnership's largest competitors in
the purchase of leasehold crude oil production are EOTT Energy Partners, L.P.,
Equiva Trading Company, GulfMark Energy, Inc., Plains All American Pipeline,
L.P. and TEPPCO Partners, L.P. Additionally, Genesis competes with many
regional or local gatherers who may have significant market share in the areas
in which they operate. Competitive factors include price, personal
relationships, range and quality of services, knowledge of products and markets
and capabilities of risk management systems.
Genesis' most significant competitors in its pipeline operations are
primarily common carrier and proprietary pipelines owned and operated by major
oil companies, large independent pipeline companies and other companies in the
areas where the Mississippi and Texas Systems deliver crude oil. The Jay System
operates in an area not currently served by pipeline competitors. Competition
among common carrier pipelines is based primarily on posted tariffs, quality of
customer service and proximity to refineries and connecting pipelines. The
Partnership believes that high capital costs, tariff regulation and problems in
acquiring rights-of-way make it unlikely that other competing crude oil pipeline
systems comparable in size and scope to Genesis' pipelines will be built in the
same geographic areas in the near future, provided that Genesis' pipelines
continue to have available capacity to satisfy demands of shippers and that its
tariffs remain at competitive levels.
Employees
To carry out various purchasing, gathering, transporting and marketing
activities, the General Partner employed, at December 31, 1999, approximately
260 employees, including management, truck drivers and other operating
personnel, division order analysts, accountants, tax specialists, contract
administrators, traders, schedulers, marketing and credit specialists and
employees involved in Genesis' pipeline operations. None of the employees is
represented by labor unions, and the General Partner believes that the
relationships with the employees are good.
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Environmental Matters
The Partnership is subject to federal and state laws and regulations
relating to the protection of the environment. At the federal level such laws
include, among others, the Clean Air Act, 42 U.S.C. Section 7401 et seq., as
amended; the Clean Water Act, 33 U.S.C. Section 1251 et seq., as amended; the
Resource Conservation and Recovery Act, 42 U.S.C. Section 6901 et seq., as
amended; the Comprehensive Environmental Response, Compensation, and Liability
Act, 42 U.S.C. Section 9601 et seq., as amended; and the National Environmental
Policy Act, 42 U.S.C. Section 4321 et seq., as amended. Although compliance
with such laws has not had a significant effect on Genesis' business, such
compliance in the future could prove to be costly, and there can be no assurance
that the Partnership will not incur such costs in material amounts.
The Clean Air Act regulates, among other things, the emission of volatile
organic compounds in order to minimize the creation of ozone. Such emissions
may occur from the handling or storage of crude oil. The required levels of
emission control are established in state air quality control implementation
plans. Both federal and state laws impose substantial penalties for violation
of these applicable requirements.
The Clean Water Act controls, among other things, the discharge of oil and
derivatives into certain surface waters. The Clean Water Act provides penalties
for any discharges of crude oil in harmful quantities and imposes liability for
the costs of removing an oil spill. State laws for the control of water
pollution also provide varying civil and criminal penalties and liabilities in
the case of a release of crude oil in surface waters or into the ground.
Federal and state permits for water discharges may be required. The Oil
Pollution Act of 1990 ("OPA"), as amended by the Coast Guard Authorization Act
of 1996, requires operators of offshore facilities to provide financial
assurance in the amount of $35 million to cover potential environmental cleanup
and restoration costs. This amount is subject to upward regulatory adjustment.
The Resource Conservation and Recovery Act regulates, among other things,
the generation, transportation, treatment, storage and disposal of hazardous
wastes. Transportation of petroleum, petroleum derivatives or other commodities
and maintenance activities may invoke the requirements of the federal statute,
or state counterparts, which impose substantial penalties for violation of
applicable standards.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
that are considered to have contributed to the release of a "hazardous
substance" into the environment. Such persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. Persons who are or were responsible for releases of hazardous substances
under CERCLA may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources, and it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances released
into the environment. In the ordinary course of the Partnership's operations,
substances may be generated or handled which fall within the definition of
"hazardous substances."
Under the National Environmental Policy Act ("NEPA"), a federal agency, in
conjunction with a permittee, may be required to prepare an environmental
assessment or a detailed environmental impact study before issuing a permit for
a pipeline extension or addition that would significantly affect the quality of
the environment. Should an environmental impact study or assessment be required
for any proposed pipeline extensions or additions, the effect of NEPA may be to
delay or prevent construction or to alter the proposed location, design or
method of construction.
The Partnership is subject to similar state and local environmental laws
and regulations that may also address additional environmental considerations of
particular concern to a state.
As part of the partnership formation, Salomon and Howell are responsible
for certain environmental conditions related to their ownership and operation of
their respective assets transferred to the Partnership and for any environmental
liabilities which Salomon or Howell may have assumed from prior owners of these
assets. Neither Salomon nor Howell, however, will be required to indemnify the
Partnership for any liabilities resulting from an invasive environmental site
investigation unless such investigation was undertaken as a result of (i)
certain requirements imposed by a lending institution, (ii) any governmental or
judicial proceeding, (iii) any disposition of assets, (iv) a discovery in the
ordinary course of business of materials, or a discovery in prudent and
customary business practice of the possible presence of such materials, that
require regulatory disclosure or (v) any complaints
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by property owners or public groups. In addition, the Partnership has assumed
responsibility for the first $25,000 per occurrence as to any environmental
liability, up to an annual aggregate of $200,000 and a total maximum liability
of $600,000.
On December 20, 1999, the Partnership had a spill of crude oil from its
Mississippi System. Approximately 8,000 barrels of oil spilled from the
pipeline near Summerland, Mississippi, and entered a creek nearby. The oil then
flowed into the Leaf River.
The Partnership responded to this incident immediately, deploying crews to
evaluate, clean up and monitor the spilled oil. At February 1, 2000, the spill
had been substantially cleaned up, with ongoing monitoring and reduced clean-up
activity expected to continue for several more months. The Partnership believes
that the oil spill is covered by insurance and the financial impact on the
Partnership for the cost of the clean-up will not be material.
As a result of this crude oil spill, certain federal and state regulatory
agencies may impose fines and penalties that would not be covered by insurance.
At this time, it is not possible to predict whether the Partnership will be
fined, the amount of such fines or whether such governmental agencies will
prevail in imposing such fines. See Note 18 of Notes to Consolidated Financial
Statement.
The segment of the Mississippi System where the spill occurred has been
shut down and will not be restarted until regulators give their approval.
Regulatory authorities may require specific testing or changes to the pipeline
before allowing the Partnership to restart the system. At this time, it is
unknown whether there will be any required testing or changes and the related
cost of that testing or changes.
Regulation
Pipeline regulation
Interstate Regulation Generally. The interstate common carrier pipeline
operations of the Jay and Mississippi systems are subject to rate regulation by
FERC under the Interstate Commerce Act ("ICA"). The ICA requires, among other
things, that to be lawful, petroleum pipeline rates be just and reasonable and
not unduly discriminatory. The ICA permits challenges to proposed new or
changed rates by protest and to rates that are already final and in effect by
complaint, and provides that upon an appropriate showing a complainant may
obtain reparations for damages sustained for a period of up to two years prior
to the filing of a complaint. Howell is responsible for any ICA liabilities
with respect to activities or conduct during periods prior to the closing of the
Partnership's initial public offering of Common Units, and the Partnership is
responsible for ICA liabilities with respect to activities or conduct
thereafter. The Partnership adopted all of Howell's tariffs in effect on the
date of the transfer of the assets to Genesis. None of the tariffs have been
subjected to a protest or complaint by any shipper or other interested party.
In general, the ICA requires that petroleum pipeline rates be cost based
and permits them to generate operating revenues on the basis of projected
volumes sufficient to cover, among other things, the following: (i) operating
expenses, (ii) depreciation and amortization, (iii) federal and state income
taxes determined on a separate company basis and adjusted or "normalized" to
reflect the impact of timing differences between book and tax accounting for
certain expenses, primarily depreciation and (iv) an overall allowed rate of
return on the pipeline's "rate base." Generally, rate base is a measure of
investment in or value of the common carrier assets which are used and useful in
providing the regulated services.
Effective January 1, 1995, FERC promulgated rules simplifying and
streamlining the ratemaking process. Previously established rates were
"grandfathered", limited the challenges that could be made to existing tariff
rates. Under the new regulations, petroleum pipelines are able to change their
rates within prescribed ceiling levels that are tied to the Producer Price Index
for Finished Goods, minus one percent. Rate increases made pursuant to the
index will be subject to protest, but such protests must show that the portion
of the rate increase resulting from application of the index is substantially in
excess of the pipeline's increase in costs. FERC's regulations provide, and a
recent FERC order in a contested pipeline rate proceeding affirms, that shippers
may not challenge that portion of the pipeline's rates which was grandfathered
whenever the pipeline files for its annual indexed rate increase; such
challenges are limited to the amount of the increase only unless, in a separate
showing, the complainant satisfies the threshold requirement to show that a
"substantial change" has occurred in the economic circumstances or the nature of
the pipeline's services. Rate decreases are mandated under the new regulations
if the index decreases and the carrier has been collecting rates equal to the
rate ceiling. The new indexing methodology can be applied to any existing rate,
including in particular all "grandfathered" rates, but also applies to rates
under
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investigation. If such rate is subsequently adjusted, the ceiling level
established under the index must be likewise adjusted.
The new indexation methodology is expected to cover all normal cost
increases. Cost-of-service ratemaking, while still available to the pipeline
for certain rate increases and to establish initial rates for new service, is
generally disfavored except in specified circumstances, primarily a substantial
divergence between the actual cost experienced by the carrier and the rate
resulting from the index such that the rate at the ceiling level would preclude
the carrier from being able to charge a just and reasonable rate. FERC
regulations also allow rate changes to occur through market- based rates (for
pipeline services which have been found to be eligible for such rates) and
through settlement rates, which are rates unanimously agreed by the carrier and
all shippers as appropriate. In respect of new facilities and new services
requiring the establishment of new, initial rates, the carrier may rely on
either cost-of-service ratemaking or may initiate service under rates which have
been contractually agreed with at least one nonaffiliated shipper; however,
other shippers may protest any new rates established in this manner, in which
event a cost-of-service showing is required.
Because of the novelty and uncertainty surrounding the indexing
methodology as well as numerous untested associated issues, the General Partner
is unable to predict with certainty whether, how or the extent to which FERC may
apply the methodologies to the Jay and Mississippi systems, which FERC
regulates. The General Partner adopted Howell's preexisting tariffs and rates
pertaining to the Jay and Mississippi Systems and intends to rely on the
indexation procedures available under FERC regulations. Nevertheless, by
protest, complaint or shipper challenge to the Partnership's grandfathered or
indexed rates, the Partnership could become involved in a cost-of-service
proceeding before FERC and be required to defend and support its rates based on
costs. In any such cost-of-service rate proceeding involving rates of the FERC-
regulated Jay and Mississippi Systems, FERC would be permitted to inquire into
and determine all relevant matters including such issues as (i) the appropriate
capital structure to be utilized in calculating rates, (ii) the appropriate rate
of return, (iii) the rate base, including the proper starting rate base, (iv)
the rate design and (v) the proper allowance for federal and state income taxes.
In addition to the regulatory considerations noted above, it is expected that
the interstate common carrier pipeline tariff rates will continue to be
constrained by competitive and other market factors.
Texas Intrastate Regulation
The intrastate common carrier pipeline operations of the Partnership in
Texas are subject to regulation by the Texas Railroad Commission. The
applicable Texas statutes require that pipeline rates be non-discriminatory and
provide a fair return on the aggregate value of the property of a common carrier
used and useful in the services performed after providing reasonable allowance
for depreciation and other factors and for reasonable operating expenses. There
is no case law interpreting these standards as used in the applicable Texas
statutes. This is because historically, as well as currently, the Texas
Railroad Commission has not been aggressive in regulating common carrier
pipelines such as those of the Partnership and has not investigated the rates or
practices of such carriers in the absence of shipper complaints, which have been
few and almost invariably settled informally. Given this history, although no
assurance can be given that the tariffs to be charged by the Partnership would
ultimately be upheld if challenged, the General Partner believes that the
tariffs now in effect can be sustained. Howell is responsible for any
liabilities under the applicable Texas statutes with respect to activities or
conduct during periods prior to the closing, and the Partnership is responsible
for such liabilities with respect to activities or conduct thereafter. The
Partnership adopted the tariffs in effect on the date of the closing of the
Partnership's initial public offering of Common Units.
Pipeline Safety Regulation
The Partnership's crude oil pipelines are subject to construction,
installation, operating and safety regulation by the Department of
Transportation ("DOT") and various other federal, state and local agencies. The
Pipeline Safety Act of 1992, among other things, amends the Hazardous Liquid
Pipeline Safety Act of 1979 ("HLPSA") in several important respects. It
requires the Research and Special Programs Administration ("RSPA") of DOT to
consider environmental impacts, as well as its traditional public safety
mandate, when developing pipeline safety regulations. In addition, the Pipeline
Safety Act mandates the establishment by DOT of pipeline operator qualification
rules requiring minimum training requirements for operators, and requires that
pipeline operators provide maps and records to RSPA. It also authorizes RSPA to
require that pipelines be modified to accommodate internal inspection devices,
to mandate the installation of emergency flow restricting devices for pipelines
in populated or sensitive areas, and to order other changes to the operation and
maintenance of petroleum pipelines. The Partnership has conducted hydrostatic
testing of most segments. Significant expenses could be
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incurred in the future if additional safety measures are required or if safety
standards are raised and exceed the current pipeline control system
capabilities.
States are largely preempted from regulating pipeline safety by federal
law but may assume responsibility for enforcing federal intrastate pipeline
regulations and inspection of intrastate pipelines. In practice, states vary
considerably in their authority and capacity to address pipeline safety. The
Partnership does not anticipate any significant problems in complying with
applicable state laws and regulations in those states in which it operates.
The Partnership's crude oil pipelines are also subject to the
requirements of the Federal Occupational Safety and Health Act ("OSHA") and
comparable state statutes. The General Partner believes that the Partnership's
crude oil pipelines have been operated in substantial compliance with OSHA
requirements, including general industry standards, record keeping requirements
and monitoring of occupational exposure to regulated substances.
In general, the General Partner expects to increase the Partnership's
expenditures in the future to comply with higher industry and regulatory safety
standards such as those described above. Such expenditures cannot be accurately
estimated at this time, although the General Partner does not expect that such
expenditures will have a material adverse impact on the Partnership, except to
the extent additional testing requirements or safety measures are imposed.
Trucking regulation
The Partnership operates its fleet of trucks as a private carrier.
Although a private carrier that transports property in interstate commerce is
not required to obtain operating authority from the ICC, the carrier is subject
to certain motor carrier safety regulations issued by the DOT. The trucking
regulations cover, among other things, driver operations, keeping of log books,
truck manifest preparations, the placement of safety placards on the trucks and
trailer vehicles, drug testing, safety of operation and equipment, and many
other aspects of truck operations. The Partnership is also subject to OSHA with
respect to its trucking operations.
Commodities regulation
The Partnership's price risk management operations are subject to
constraints imposed under the Commodity Exchange Act and the rules of the NYMEX.
The futures and options contracts that are traded on the NYMEX are subject to
strict regulation by the Commodity Futures Trading Commission.
Information Regarding Forward-Looking Information
The statements in this Annual Report on Form 10-K that are not historical
information are forward looking statements within the meaning of Section 27a of
the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934. Although the Partnership believes that its expectations regarding future
events are based on reasonable assumptions, it can give no assurance that its
goals will be achieved or that its expectations regarding future developments
will prove to be correct. Important factors that could cause actual results to
differ materially from those in the forward looking statements herein include
changes in regulations, the Partnership's success in obtaining additional lease
barrels, changes in crude oil production volumes (both world-wide as well as in
areas in which the Partnership has operations), developments relating to
possible acquisitions or business combination opportunities, volatility of crude
oil prices and grade differentials, the success of the Partnership's risk
management activities, credit requirements by counterparties of the Partnership,
the Partnership's ability to replace its Guaranty Facility from Salomon with a
bank facility and to replace its Working Capital Facility from Bank One with
another facility, any requirements for testing or changes to the Mississippi
System as a result of the December spill, the final determination of the
causation of the December spill and the effects of that determination on
insurance coverage, and conditions of the capital markets and equity markets
during the periods covered by the forward looking statements.
Item 2. Properties
The Partnership owns and operates three common carrier crude oil pipeline
systems. The pipelines and related gathering systems consist of the 750-mile
Texas system, the 117-mile Jay System extending between Florida and Alabama, and
the 281-mile Mississippi System extending between Mississippi and Louisiana.
The Partnership also owns approximately 2.0 million barrels of storage capacity
associated with the pipelines. These storage capacities include approximately
200,000 barrels each on the Mississippi and Jay Systems and 1.4 million barrels
on the Texas System, primarily at the Satsuma terminal in Houston, Texas.
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In addition to transporting crude oil by pipeline, the Partnership transports
crude oil through a fleet of owned and leased tractors and trailers. At
December 31, 1999, the trucking fleet consisted of approximately 76 tractor-
trailers. The trucking fleet generally hauls the crude oil to one of the
approximately 127 pipeline injection stations owned or leased by the
Partnership.
Item 3. Legal Proceedings
The Partnership is involved from time to time in various claims, lawsuits and
administrative proceedings incidental to its business. In the opinion of
management of the General Partner, the ultimate outcome, if any, will not have a
material adverse effect on the financial condition or results of operations of
the Partnership. See Note 18 of Notes to Consolidated Financial Statements.
Item 4. Submission of Matters to a Vote of Security Holders
There were no matters submitted to a vote of security holders during the year
ended December 31, 1999.
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PART II
Item 5. Market for Registrant's Common Units and Related Security Holder
Matters
The following table sets forth, for the periods indicated, the high and low
sale prices per Common Unit, as reported on the New York Stock Exchange
Composite Tape, and the amount of cash distributions paid per Common Unit.
Price Range
-------------------- Cash
High Low Distributions
-------- -------- ----------------
1999
- ----
First Quarter $16.3125 $13.2500 $0.50
Second Quarter $15.2500 $13.7500 $0.50
Third Quarter $15.5000 $11.9375 $0.50
Fourth Quarter $12.8125 $ 6.6250 $0.50
1998
- ----
First Quarter $20.3750 $16.6250 $0.50
Second Quarter $19.8750 $17.2500 $0.50
Third Quarter $18.0000 $13.6875 $0.50
Fourth Quarter $19.1250 $13.6250 $0.50
_____________________
Cash distributions are shown in the quarter paid and are based on the
prior quarter's activities.
At December 31, 1999, there were 8,620,062 Common Units and 2,155,000
Subordinated OLP Units outstanding. As of December 31, 1999, there were
approximately 12,000 record holders and beneficial owners (held in street name)
of the Partnership's Common Units. There is no established public trading
market for the Partnership's Subordinated OLP Units. The Partnership will
distribute 100% of its Available Cash as defined in the Partnership Agreement
within 45 days after the end of each quarter to Unitholders of record and to the
General Partner. Available Cash consists generally of all of the cash receipts
less cash disbursements of the Partnership adjusted for net changes to reserves.
The full definition of Available Cash is set forth in the Partnership Agreement
and amendments thereto, which is filed as an exhibit hereto. Distributions of
Available Cash to the Subordinated Unitholders will be subject to the prior
rights of the Common Unitholders to receive the Minimum Quarterly Distribution
("MQD") for each quarter during the subordination period, which will not end
earlier than December 31, 2001, and to receive any arrearages in the
distribution of the MQD on the Common Units for prior quarters during the
subordination period.
In connection with the Partnership's initial public offering of Common Units
in December 1996, Salomon and the Partnership entered into a Distribution
Support Agreement pursuant to which, among other things, Salomon agreed that it
would contribute up to $17.6 million to the Partnership in exchange for
Additional Partnership Interests ("APIs"), if necessary, to support the
Partnership's ability to pay the MQD on Common Units. Salomon's obligation to
purchase APIs will end no later than December 31, 2001, with the actual
termination subject to the levels of distributions that have been made prior to
the termination date. At December 31, 1999, Salomon had provided $3.9 million
of distribution support and provided $2.2 million additional distribution
support in February 2000. After February 2000, $11.5 million remains of
Salomon's distribution support commitment.
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Item 6. Selected Financial Data
(in thousands, except per unit and volume data)
The table below includes selected financial data for the Partnership for the
years ended December 31, 1999, 1998 and 1997 and one month ended December 31,
1996 and includes the results of operations acquired from Basis and Howell.
Since Basis had the largest ownership interest in the Partnership, the net
assets acquired from Basis were recorded at their historical carrying amounts
and the crude oil gathering and marketing division of Basis was treated as the
Predecessor and the acquirer of Howell's operations. The acquisition of
Howell's operations was treated as a purchase for accounting purposes.
Eleven
One Month Months
Ended Ended Year Ended
Year Ended December 31, November 30, December 31, December 31,
-------------------------------------------
1999 1998 1997 1996 1996 1996 1995
---------- ---------- ---------- ---------- -------- ---------- ----------
(Pro forma) (Predecessor)(Predecessor)
(Unaudited)
Income Statement Data:
Revenues:
Gathering & marketing
revenues $2,144,646 $2,216,942 $3,354,939 $4,565,834 $370,559 $3,598,107 $3,440,065
Pipeline revenues 16,366 16,533 17,989 16,780 1,426 - -
---------- ---------- ---------- ---------- -------- ---------- ----------
Total revenues 2,161,012 2,233,475 3,372,928 4,582,614 371,985 3,598,107 3,440,065
Cost of sales:
Crude cost 2,118,318 2,184,529 3,331,184 4,526,363 366,723 3,573,086 3,409,759
Field operating costs 11,669 12,778 12,107 15,092 1,290 6,744 7,152
Pipeline operating
costs 8,161 7,971 6,016 4,978 463 - -
---------- ---------- ---------- ---------- -------- ---------- ----------
Total cost of sales 2,138,148 2,205,278 3,349,307 4,546,433 368,476 3,579,830 3,416,911
---------- ---------- ---------- ---------- -------- ---------- ----------
Gross margin 22,864 28,197 23,621 36,181 3,509 18,277 23,154
General and
administrative expenses 11,649 11,468 8,557 9,470 1,363 3,316 3,658
Depreciation and
amortization 8,220 7,719 6,300 6,834 518 1,396 4,815
Nonrecurring charge - 373 - - - - -
---------- ---------- ---------- ---------- -------- ---------- ----------
Operating income 2,995 8,637 8,764 19,877 1,628 13,565 14,681
Interest income
(expense), net (929) 154 1,063 56 56 294 173
Other income (expense) 849 28 21 (74) - (83) (197)
---------- ---------- ---------- ---------- -------- ---------- ----------
Net income before
minority interests 2,915 8,819 9,848 19,859 1,684 13,776 14,657
Minority interests 583 1,763 1,968 3,970 337 - -
---------- ---------- ---------- ---------- -------- ---------- ----------
Net income $ 2,332 $ 7,056 $ 7,880 $ 15,889 $ 1,347 $ 13,776 $ 14,657
========== ========== ========== ========== ======== ========== ==========
Net income per common
unit-basic and
diluted $ 0.27 $ 0.80 $ 0.90 $ 1.81 $ 0.15 N/A N/A
========== ========== ========== ========== ======== ========== ==========
Balance Sheet Data
(at end of period):
Current assets $ 274,717 $ 185,216 $ 232,202 $ 410,371 $410,371 N/A $ 279,285
Total assets 380,592 297,173 331,114 509,900 509,900 N/A 283,036
Long-term liabilities 3,900 15,800 - - - N/A -
Equity of parent - - - - - N/A (8,437)
Minority interest 30,571 29,988 28,225 26,257 26,257 N/A -
Partners' capital 53,585 67,871 78,351 85,080 85,080 N/A -
Other Data:
Maintenance capital
expenditures $ 1,682 $ 1,509 $ 3,785 $ 2,535 $ 106 $ 1,100 $ 17
EBITDA $ 12,064 $ 16,384 $ 15,085 $ 26,637 $ 2,146 $ 14,878 $ 19,299
Volumes (bpd):
Gathering and
marketing:
Wellhead 93,397 114,400 104,506 116,263 120,553 83,239 83,551
Bulk and exchange 242,992 325,468 346,760 463,054 380,354 417,939 439,060
Pipeline 94,048 85,594 89,117 86,557 85,874 - -
- -------------------------
The unaudited pro forma selected financial data of the Partnership includes (a)
the historical operating results of the crude oil gathering and marketing
operations of Basis, (b) the historical crude gathering, marketing and pipeline
transportation operations of Howell and (c) certain pro forma adjustments to the
historical results of operations of Basis and Howell as if the Partnership had
been formed on January 1, 1996.
Net income excludes the effect of income taxes for the Predecessor.
The General Partner estimates that capital expenditures necessary to maintain
the existing asset base at current operating levels will be $2 million each
year.
EBITDA (earnings before interest expense, income taxes, depreciation and
amortization and minority interests) should not be considered as an alternative
to net income (as an indicator of operating performance) or as an alternative to
cash flow (as a measure of liquidity or ability to service debt obligations).
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The table below summarizes the Partnership's quarterly financial data for
1999 and 1998 (in thousands, except per unit data).
1999 Quarters
--------------------------------------
First Second Third Fourth
-------- -------- -------- --------
Revenues $383,723 $513,388 $593,817 $670,084
Gross margin $ 5,769 $ 6,321 $ 5,461 $ 5,313
Operating income $ 698 $ 1,241 $ 667 $ 389
Net income $ 1,109 $ 804 $ 254 $ 165
Net income per Common
Unit-basic and diluted $ 0.13 $ 0.09 $ 0.03 $ 0.02
1998 Quarters
--------------------------------------
First Second Third Fourth
-------- -------- -------- --------
Revenues $650,257 $561,813 $526,442 $494,963
Gross margin $ 6,336 $ 6,047 $ 8,432 $ 7,382
Operating income $ 1,962 $ 889 $ 3,365 $ 2,421
Net income $ 1,728 $ 811 $ 2,662 $ 1,855
Net income per Common
Unit-basic and diluted $ 0.20 $ 0.09 $ 0.30 $ 0.21
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following review of the results of operations and financial condition
should be read in conjunction with the Consolidated Financial Statements and
Notes thereto.
Results of Operations
Selected financial data for this discussion of the results of operations
follows, in thousands.
Years Ended December 31,
------------------------------------
1999 1998 1997
---------- ---------- ----------
Revenues
Gathering & marketing $2,144,646 $2,216,942 $3,354,939
Pipeline $ 16,366 $ 16,533 $ 17,989
Gross margin
Gathering & marketing $ 14,659 $ 19,635 $ 11,648
Pipeline $ 8,205 $ 8,562 $ 11,973
General and administrative
expenses $ 11,649 $ 11,468 $ 8,557
Depreciation and
amortization $ 8,220 $ 7,719 $ 6,300
Operating income $ 2,995 $ 8,637 $ 8,764
Interest income
(expense), net $ (929) $ 154 $ 1,063
Other income (expense) $ 849 $ 28 $ 21
The profitability of Genesis depends to a significant extent upon its
ability to maximize gross margin. The gross margin from gathering and marketing
operations is generated by the difference between the price of crude oil at the
point of purchase and the price of crude oil at the point of sale, minus the
associated costs of aggregation and transportation. In addition to purchasing
crude oil at the wellhead, Genesis purchases crude oil in bulk at major pipeline
terminal points and enters into exchange transactions with third parties. These
bulk and exchange transactions are characterized by large volumes and narrow
profit margins on purchase and sales transactions, and the absolute price levels
for crude oil do not necessarily bear a relationship to gross margin, although
such price levels significantly impact revenues and cost of sales. Because
period-to-period variations in revenues and cost of sales are not generally
meaningful in analyzing the variation in gross margin for gathering and
marketing operations, such changes are not addressed in the following
discussion. Pipeline revenues and gross margins are
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primarily a function of the level of throughput and storage activity and are
generated by the difference between the regulated published tariff and the fixed
and variable costs of operating the pipeline. Changes in revenues, volumes and
pipeline operating costs, therefore, are relevant to the analysis of financial
results of Genesis' pipeline operations and are addressed in the following
discussion of pipeline operations of Genesis.
Gross margin from gathering, marketing and pipeline operations varies from
period to period, depending to a significant extent upon changes in the supply
and demand of crude oil and the resulting changes in U.S. crude oil inventory
levels. In general, gathering and marketing gross margin increases when crude
oil inventories decline, resulting in crude oil for prompt (generally the next
month) delivery being priced at an increased premium over crude oil for future
delivery.
Year Ended December 31, 1999 Compared with Year Ended December 31, 1998
Gross Margin. Gathering and marketing gross margins decreased $4.9
million or 25% to $14.7 million for the year ended December 31, 1999, as
compared to $19.6 million for the year ended December 31, 1998. The decline in
gross margin is primarily attributed to lower volumes purchased at the wellhead
and in bulk at major trade locations.
In 1999, the Partnership's average wellhead volumes declined
approximately 21,000 barrels per day. Wellhead purchases fell from an average
of 114,000 barrels per day in 1998 to 93,000 barrels per day in 1999.
The decline in wellhead volumes began during the second half of 1998 in
response to weakening crude oil prices. Volumes declined from 118,000 barrels
per day during the first half of the year to 111,000 barrels per day during the
second half of the year. A large contract with Pioneer Natural Resources
expired at the end of 1998, reducing volumes at the beginning of 1999 by an
additional 21,000 barrels per day. The loss of the Pioneer volumes and
continued declines associated with low crude oil prices cut wellhead volume
during the first half of 1999 to an average of 89,000 thousand barrels per day.
The Partnership increased wellhead volumes during the second half of 1999 by
competitive marketing efforts. Wellhead purchases increased to 92,000 barrels
per day during the third quarter and to 99,000 thousand barrels per day for the
fourth quarter.
The Partnership's lease business feeds into its marketing and exchange
activities. The decline in wellhead volumes, as well as significant changes in
price relationships for various grades, locations and timing of delivery of
crude oil, resulted in lower bulk and exchange volumes in 1999. Bulk and
exchange volumes declined 82,000 barrels per day, dropping from 325,000 barrels
per day in 1998 to 243,000 barrels per day in 1999.
Gathering and marketing gross margins in 1999 were positively impacted
by a widening spread between the price of crude oil paid at the wellhead and the
price of crude oil at the point of sale, as crude oil inventories declined and
refinery demand for prompt supply improved. The Partnership also implemented
changes in its operations in response to declining wellhead volumes that reduced
field operating costs by $1.1 million.
Pipeline gross margin decreased $0.4 million or 4% to $8.2 million for
the year ended December 31, 1999, as compared to $8.6 million for the year ended
December 31, 1998. Although average daily volumes increased 10%, the average
length of the pipeline movement was shorter, resulting in less tariff income.
Pipeline operating costs increased due to increased expenditures for corrosion
control and the costs associated with the spill the Partnership had from its
Mississippi System in December 1999.
General and administrative expenses. General and administrative
expenses increased $0.2 million in 1999 over the 1998 level. This increase can
be attributed to expenditures related to addressing the Year 2000 issue in 1999,
totaling $0.4 million that were charged to general and administrative expenses.
This increase in costs for the Year 2000 issue was partially offset by small
decreases in a number of areas.
Depreciation and amortization. In April 1998, the Partnership acquired
the gathering and marketing assets of Falco S&D, Inc. ("Falco"). Twelve months
of depreciation and amortization on these assets is included in 1999, while 1998
only included depreciation and amortization from the date of acquisition. The
increase of $0.5 million in depreciation and amortization to $8.2 million for
the year ended December 31, 1999, resulted primarily from this asset
acquisition.
Interest income (expense), net. In 1998, the Partnership had net
interest income of $0.2 million. In 1999, the Partnership had net interest
expense of $0.9 million. This difference of $1.1 million is attributable to
increased borrowings by the Partnership in 1998 to acquire the Falco assets and
to acquire a pipeline near West Columbia, Texas. As these acquisitions
occurred, the Partnership had less available funds and increased its borrowings
under its loan agreement. The borrowings were outstanding throughout 1999.
Additionally, market
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interest rates, as evidenced by the prime rate, rose during 1999 by 0.75%, also
increasing the Partnership's interest costs.
Other income (expense). In 1999, the Partnership recognized a gain of
$0.9 million as a result of the sale of excess tractors and trailers.
Year Ended December 31, 1998 Compared with Year Ended December 31, 1997
Gross Margin. Gathering and marketing gross margins increased $7.9
million or 68% to $19.6 million for the year ended December 31, 1998, as
compared to $11.7 million for the year ended December 31, 1997. The increase in
gross margin can be attributed to the acquisition of the gathering and marketing
assets of Falco in April 1998 and improvements in the relationships between
various market prices during 1998, allowing the Partnership to apply its risk
management techniques to forward purchases and sales opportunities to increase
gross margin.
By the end of 1998, price levels for crude oil had declined
approximately 39% from prices at the beginning of 1998. While the decline in
price levels, as previously stated, does not directly impact the Partnership's
gross margins, the decline generally does reduce the quantities of crude oil
available for purchase at the wellhead due to curtailed production and drilling
activity. Through the acquisition of the gathering and marketing assets of
Falco in April 1998, the Partnership was able to improve its average wellhead
volumes over 1997 levels, although volumes in the fourth quarter had declined to
an average of 107,758 barrels per day.
Pipeline gross margin decreased $3.4 million or 28% to $8.6 million for
the year ended December 31, 1998, as compared to $12.0 million for the year
ended December 31, 1997. The Partnership experienced a decline in its daily
throughput volumes of 8%, decreasing pipeline revenues by $1.5 million. In
October 1998, the Partnership acquired 200 additional miles of pipeline in the
West Columbia area of Texas. This addition resulted in a restoration of
throughput volumes by the end of 1998 to levels at the beginning of the year.
Throughput volumes on the existing pipelines declined in 1998 as oil producers
reduced exploration and production volumes in areas serviced by the
Partnership's pipelines.
Also contributing to the decline in pipeline gross margins were higher
operating costs in 1998. These higher costs can be attributed to lease payments
beginning in the second quarter of 1998 on a new segment of pipeline, repairs on
the Main Pass pipeline prior to its shut-in, and increased routine maintenance
expenditures.
General and administrative expenses. In 1998, general and
administrative expenses increased by $2.9 million or 34% to $11.5 million. This
increase can be attributed primarily to three factors. First, the estimated
total charge for the Restricted Unit Plan is being recognized over the three-
year vesting period beginning in 1998. In 1998, that noncash charge was $1.6
million. Second, in 1998 the Partnership no longer benefited from the sharing
of certain costs with Basis under the terms of a Corporate Services Agreement as
it did in 1997. Third, costs increased due to the addition of marketing and
administrative personnel by the Partnership in April 1998 as a result of the
Falco asset acquisition.
Depreciation and amortization. Depreciation and amortization increased
from $6.3 million in 1997 to $7.7 million in 1998, primarily attributable to
depreciation and amortization on the assets acquired from Falco.
Nonrecurring charge. In 1998, the Partnership recorded a non-recurring
charge of $0.4 million as a result of the shut-in of its Main Pass pipeline
located offshore. The charge consisted of $0.1 million of costs related to the
shut-in and a $0.3 million write-down of the asset.
Interest income (expense), net. Net interest income declined $0.8
million or 89% to $0.2 million for the year ended December 31, 1998 as compared
to $1.0 million for the year ended December 31, 1997. As a result of the
acquisition of the assets of Falco and the pipeline near West Columbia, Texas,
in 1998, the Partnership had less cash available to temporarily invest.
Interest expense increased as the Partnership borrowed funds under its loan
agreement during the year.
Liquidity and Capital Resources
Cash Flows
Net cash provided by operations was $10.1 million for the year ended
December 31, 1999 as compared to $16.4 million for the year ended December 31,
1998. The decrease in cash flow in 1999 was due primarily to the reduction in
the Partnership's gross margin.
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Net cash used in investing activities was $1.3 million and $17.5 million
for the years ended December 31, 1999 and 1998, respectively. In 1999, the
Partnership expended $2.7 million on property additions and received $1.0
million from the sale of excess trucking equipment. In 1998, the Partnership
acquired the gathering and marketing assets of Falco, a pipeline near West
Columbia, Texas, and other pipeline property additions.
Net cash used in financing activities was $9.8 million and $3.0 million
for the years ended December 31, 1999 and 1998, respectively. In 1999 and 1998,
the Partnership paid distributions to the Common Unitholders and the General
Partner totaling $17.6 million. In 1999, the Partnership received $3.9 million
of Distribution Support from Salomon. The Partnership also paid $0.3 million
and $1.2 million in 1999 and 1998, respectively, to acquire Common Units in the
open market for treasury, some of which were subsequently reissued under the
Restricted Unit Plan. Cash flows from financing activities were provided by
borrowings in the amount of $4.1 million and $15.8 million under the loan
agreement in 1999 and 1998, respectively.
Capital Expenditures
In 1999, the Partnership expended $2.7 million for capital expenditures,
with $1.7 million of that amount for maintenance capital expenditures. Business
expansion project expenditures totaled $1 million for various small projects.
In 1998, the Partnership expended $16.2 million for capital expenditures
for projects related to the expansion of its business activities and $1.5
million for maintenance capital expenditures. The expansion projects included
the acquisition of the gathering and marketing assets of Falco, located
primarily in Louisiana and East Texas and the acquisition of 200 miles of
pipeline in the West Columbia area of Texas. This pipeline begins in Jackson
County, Texas, and ends at Genesis' Webster Station in Harris County.
In 1997, the Partnership made a one-time expenditure of $1.5 million for
furnishings for new offices. Additionally, the Partnership expended $2.3
million for capital expenditures relating to its existing operations and $2.2
million for project additions. The principal project addition related to
expenditures that enabled the Partnership to transport crude from a new area in
Texas in its pipeline.
Working Capital and Credit Resources
Pursuant to the Master Credit Support Agreement, Salomon is providing
credit support in the form of a Guaranty Facility in connection with the
purchase, sale or exchange of crude oil in the ordinary course of the
Partnership's business with third parties. The aggregate amount of the Guaranty
Facility will be limited to $300 million for the year ending December 31, 2000
(to be reduced in each case by the amount of any obligation to a third party to
the extent that such party has a prior security interest in the collateral under
the Master Credit Support Agreement). The Partnership is required to pay a
guaranty fee to Salomon which will increase over the remaining year, thereby
increasing the cost of the credit support provided to the Partnership under the
Guaranty Facility.
At December 31, 1999, the aggregate amount of obligations covered by
guarantees was $164 million, including $72 million in payable obligations and
$92 million in estimated crude oil purchase obligations for January 2000.
Salomon received a security interest in all the Partnership's
receivables, inventories, general intangibles and cash to secure obligations
under the Master Credit Support Agreement. Salomon provided a Working Capital
Facility to the Partnership until August 1998. At that time, the Working Capital
Facility was replaced with a revolving credit/loan agreement ("Loan Agreement")
with Bank One, Texas, N.A. ("Bank One"). The Loan Agreement provides for loans
or letters of credit in the aggregate not to exceed the greater of $35 million
or the Borrowing Base (as defined in the Loan Agreement). Loans will bear
interest at a rate chosen by GCOLP which would be one or more of the following:
(a) a Floating Base Rate (as defined in the Loan Agreement) that is generally
the prevailing prime rate less one percent; (b) a rate based on the Federal
Funds Rate plus one and one-half percent or (c) a rate based on LIBOR plus one
and one-quarter percent. The Loan Agreement provides for a revolving period
until August 14, 2000, during which time interest will be paid monthly. All
loans outstanding on August 14, 2000, are due at that time.
The Loan Agreement is collateralized by the accounts receivable and
inventory of GCOLP, subject to the terms of an Intercreditor Agreement between
Bank One and Salomon. There is no compensating balance requirement under the
Loan Agreement. A commitment fee of 0.35% on the available portion of the
commitment is provided for in the agreement. Material covenants and
restrictions include requirements to maintain a ratio of
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current assets (as defined in the Loan Agreement) to current liabilities of at
least 1:1 and to maintain tangible net worth in GCOLP, as defined in the Loan
Agreement, of $65 million.
At December 31, 1999, the Partnership had $19.9 million of loans
outstanding under the Loan Agreement. The Partnership had no letters of credit
outstanding at December 31, 1999. At December 31, 1999, $15.1 million was
available to be borrowed under the Loan Agreement.
Management of the Partnership has entered into discussions with a bank
regarding replacement of the Bank One Loan Agreement with a long-term facility.
Based upon these discussions, management expects that it will be able to
replace the Loan Agreement with a long-term facility subject to similar terms.
If the Partnership is unable to complete the replacement agreement noted above,
then other options will be pursued, some of which may have terms not as
favorable to the Partnership, including increasing costs and pledging
additional collateral. While management believes that it will be able to
replace the Loan Agreement on a long-term basis prior to its maturity, there
can be no assurance that it will be able to do so.
There can be no assurance of the availability or the terms of credit for
the Partnership. At this time, Salomon does not intend to provide guarantees or
other credit support after the credit support period expires in December 2000.
In addition, if the General Partner is removed without its consent, Salomon's
credit support obligations will terminate. Further, Salomon's obligations under
the Master Credit Support Agreement may be transferred or terminated early
subject to certain conditions. Management of the Partnership intends to replace
the Guaranty Facility with a letter of credit facility with one or more third
party lenders prior to December 2000 and has had preliminary discussions with
banks about a replacement letter of credit facility. The General Partner may be
required to reduce or restrict the Partnership's gathering and marketing
activities because of limitations on its ability to obtain credit support and
financing for its working capital needs. The General Partner expects that the
overall cost of a replacement facility may be substantially greater than what
the Partnership is incurring under its existing Master Credit Support Agreement.
Any significant decrease in the Partnership's financial strength, regardless of
the reason for such decrease, may increase the number of transactions requiring
letters of credit or other financial support, make it more difficult for the
Partnership to obtain such letters of credit, and/or may increase the cost of
obtaining them. This situation could in turn adversely affect the Partnership's
ability to maintain or increase the level of its purchasing and marketing
activities or otherwise adversely affect the Partnership's profitability and
Available Cash.
Distributions
Generally, GCOLP will distribute 100% of its Available Cash within 45
days after the end of each quarter to Unitholders of record and to the General
Partner. Available Cash consists generally of all of the cash receipts less
cash disbursements of GCOLP adjusted for net changes to reserves. (A full
definition of Available Cash is set forth in the Partnership Agreement.)
Distributions of Available Cash to the holders of Subordinated OLP Units are
subject to the prior rights of holders of Common Units to receive the minimum
quarterly distribution ("MQD") for each quarter during the subordination period
(which will not end earlier than December 31, 2001) and to receive any
arrearages in the distribution of the MQD on the Common Units for prior quarters
during the subordination period. MQD is $0.50 per unit.
Salomon has committed, subject to certain limitations, to provide total
cash distribution support, with respect to quarters ending on or before December
31, 2001, in an amount up to an aggregate of $17.6 million in exchange for
Additional Partnership Interests ("APIs"). Salomon's obligation to purchase
APIs will end no later than December 31, 2001, with the actual termination
subject to the levels of distributions that have been made prior to the
termination date. In 1999, the Partnership utilized $3.9 million of the
distribution support from Salomon. An additional $2.2 million of distribution
support was utilized in February 2000. After the distribution in February 2000,
$6.1 million of distribution support has been utilized, and $11.5 million
remains available through December 31, 2001 or until such amount is fully
utilized, whichever comes first. Based on current market conditions, management
of the General Partner expects to continue using distribution support at levels
similar to recent support requirements. Management expects that distribution
support will be fully utilized before its expiration at the end of 2001.
Any APIs purchased by Salomon are not entitled to cash distributions or
voting rights. The APIs will be redeemed if and to the extent that Available
Cash for any future quarter exceeds an amount necessary to distribute the MQD on
all Common Units and Subordinated OLP Units and to eliminate any arrearages in
the MQD on Common Units for prior periods.
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In 1999 and 1998, the Partnership paid total distributions of $2.00 per
unit to the Common Unitholders and the General Partner. This amount represented
distributions for the period from October 1, 1997 to September 31, 1999. A
distribution of $0.50 per unit, applicable to the fourth quarter of 1999, was
paid on February 14, 2000 to holders of record on January 30, 2000. In 1997,
the Partnership paid total distributions of $1.66 per unit, representing
distributions for the period from the Partnership's inception in December
1996 through September 30, 1997.
Crude Oil Spill
On December 20, 1999, the Partnership had a spill of crude oil from its
Mississippi System. Approximately 8,000 barrels of oil spilled from the
pipeline near Summerland, Mississippi and entered a creek nearby. The oil then
flowed into the Leaf River.
The Partnership responded to this incident immediately, deploying crews
to evaluate, clean up and monitor the spilled oil. At February 1, 2000, the
spill had been substantially cleaned up, with ongoing maintenance and reduced
clean-up activity expected to occur for several more months.
The estimated cost of the spill clean-up is expected to be $17 million.
A final determination as to the cause of the spill has not been completed. The
incident was reported to insurers, and incurred costs related to the clean-up
efforts have been reimbursed or approved for reimbursement by the insurers.
The insurers, however, have reserved the right to claim the return of the
insurance proceeds should the final determination of cause be a cause not
covered by the insurance policies. Based on its review of the policies
and its understanding of the facts associated with the spill, management of
the General Partner believes that the costs of the spill are covered by
insurance and collection of the receivable is probable.
In its 1999 financial statements, the Partnership charged to expense the
deductible of $50,000, recorded a liability for the $17 million of estimated
clean-up costs and recorded a receivable from the insurance company for the
insurance proceeds. Should the ultimate determination of the cause of the
spill prove not to be covered by insurance, the Partnership will be required
to write off the receivable of $17 million.
As a result of this crude oil spill, certain federal and state
regulatory agencies may impose fines and penalties that would not be reimbursed
by insurance. At this time, it is not possible to predict whether the
Partnership will be fined, the amounts of such fines, or whether such
governmental agencies would prevail in imposing such fines.
The segment of the Mississippi System where the spill occurred has been
temporarily shut down and will not be returned to service until regulators give
their approval. Regulatory authorities may require specific testing or changes
to the pipeline before allowing the Partnership to restart that segment of the
system. At this time, it is unknown whether there will be any required testing
or changes and the related cost of that testing or changes.
If the costs of testing or changes are too high, that segment of the
system may not be restarted. If this part of the Mississippi System is taken
out of service, annual tariff revenues would be reduced by approximately $0.6
million and the net book value of that portion of the pipeline would be
written down to its net realizable value, resulting in a non-cash write-off
of approximately $6.0 million.
Current Business Conditions
Despite significant increases in crude oil prices since the first
quarter of 1999, U.S. onshore crude oil production volumes have not improved.
Further, management of the General Partner has not seen significant improvement
in the drilling and workover rig counts that would indicate that producers are
expending capital to increase production. The first sign of recovery is
normally an increase in the number of workover rigs, the rigs used for jobs that
increase production from existing wells. In 1998, the monthly average number of
workover rigs operating in the Partnership's primary operating areas was 653
rigs. That count dropped to 497 in 1999. Similarly, the average number of
rotary rigs being utilized in the Partnership's primary operating areas to find
or develop oil or natural gas declined from 386 rigs in 1998 to 275 rigs in
1999. Management of the General Partner believes that producers that survived
the price downturn in 1998 and early 1999 by borrowing from banks or utilizing
cash reserves are using the increased cash flow from higher prices to repay debt
and replenish cash. Although there has been some increase in the number of
drilling and workover rigs being utilized in the Partnership's primary operating
areas during the early part of 2000, management of the General Partner expects
that this increased activity is more likely to have the effect of reducing
natural production declines rather than significantly increasing wellhead
volumes in its operating areas.
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The Partnership's improved volumes during 1999 were due primarily to
obtaining existing production through competitive marketing efforts. Increased
competition for existing production generally results in lower margins per
barrel. Therefore, the Partnership expects production obtained through
competitive marketing efforts will result in incrementally lower gross margins
per barrel.
As crude oil prices rise, the Partnership's utilization of, and cost of
credit under, the Guaranty Facility increases with respect to the same volume of
business. The General Partner may be required to reduce or restrict the
Partnership's gathering and marketing activities due to the $300 million limit
of the Guaranty Facility. The cost of operating the Partnership's trucking
fleet also rises as fuel costs rise.
Additionally, as prices rise, the Partnership may have to increase the
amount of its Working Capital Facility in order to have funds available to meet
margin calls on the NYMEX and to fund inventory purchases. No assurances can be
made that the Partnership would be able to increase the size of its Working
Capital Facility or that changes to the terms of such increased Working Capital
Facility would not have a material impact on the results of operations or cash
flows of the Partnership.
Item 7a. Quantitative and Qualitative Disclosures about Market Risk
The Partnership's primary price risk relates to the effect of crude oil price
fluctuations on its inventories and the fluctuations each month in grade and
location differentials and their effects on future contractual commitments. The
Partnership utilizes New York Mercantile Exchange ("NYMEX") commodity based
futures contracts, forward contracts, swap agreements and option contracts to
hedge its exposure to these market price fluctuations. Management believes the
hedging program has been effective in minimizing overall price risk. At
December 31, 1999, the Partnership used futures, forward and options contracts
exclusively in its hedging program with the latest contract being settled in
January 2001. Information about these contracts is contained in the table set
forth below.
Sell (Short) Buy (Long)
Contracts Contracts
----------- ----------
Crude Oil Inventory
Volume (1,000 bbls) 17
Carrying value $ 424
Fair value $ 424
Commodity Futures Contracts:
Contract volumes (1,000 bbls) 12,665 13,132
Weighted average price per bbl $ 23.26 $22.75
Contract value (in thousands) $294,617 $298,715
Fair value (in thousands) $313,937 $316,640
Commodity Forward Contracts:
Contract volumes (1,000 bbls) 4,830 4,090
Weighted average price per bbl $ 25.50 $ 24.81
Contract value (in thousands) $123,173 $101,492
Fair value (in thousands) $122,500 $102,555
Commodity Option Contracts:
Contract volumes (1,000 bbls) 1,960
Weighted average strike price
per bbl $ 3.15
Contract value (in thousands) $ 363
Fair value (in thousands) $ 390
The table above presents notional amounts in barrels, the weighted average
contract price, total contract amount in U.S. dollars and total fair value
amount in U.S. dollars. Fair values were determined by using the notional
amount in barrels multiplied by the December 31, 1999 closing prices of the
applicable NYMEX futures contract adjusted for location and grade
differentials, as necessary.
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Item 8. Financial Statements and Supplementary Data
The information required hereunder is included in this report as set forth
in the "Index to Consolidated Financial Statements" on page 30.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosures
None.
Part III
Item 10. Directors and Executive Officers of the Registrant
The Partnership does not directly employ any persons responsible for
managing or operating the Partnership or for providing services relating to
day-to-day business affairs. The General Partner provides such services
and is reimbursed for its direct and indirect costs and expenses, including
all compensation and benefit costs.
The Board of Directors of the General Partner has established a committee
(the "Audit Committee") consisting of individuals who are neither officers nor
employees of the General Partner or any affiliate of the General Partner. The
committee has the authority to review, at the request of the General Partner,
specific matters as to which the General Partner believes there may be a
conflict of interest in order to determine if the resolution of such conflict is
fair and reasonable to the Partnership. In addition, the committee reviews the
external financial reporting of the Partnership, recommends engagement of the
Partnership's independent accountants, and reviews the Partnership's procedures
for internal auditing and the adequacy of the Partnership's internal accounting
controls.
Directors and Executive Officers of the General Partner
Set forth below is certain information concerning the directors and
executive officers of the General Partner. All directors of the General Partner
are elected annually by the General Partner. All executive officers serve at
the discretion of the General Partner.
Name Age Position
----------------- --- --------------------------------------------
A. Richard Janiak 53 Director and Chairman of the Board
Mark J. Gorman 46 Director, Chief Executive Officer and
President
John P. vonBerg 46 Director, Vice Chairman of the Board,
and Executive Vice President, Trading and
Price Risk Management
Michael A. Peak 46 Director
Robert T. Moffett 48 Director
Herbert I. Goodman 77 Director
J. Conley Stone 68 Director
John M. Fetzer 46 Executive Vice President
Ross A. Benavides 46 Chief Financial Officer, General Counsel
and Secretary
Ben F. Runnels 59 Vice President, Trucking Operations
Kerry W. Mazoch 53 Vice President, Crude Oil Acquisitions
A. Richard Janiak has served as Director and Chairman of the Board of the
General Partner since June 1999. He is a Managing Director of Salomon Smith
Barney Inc., where he has served in various investment banking and management
positions since 1970.
Mark J. Gorman has served as a Director of the General Partner since December
1996 and as President and Chief Executive Officer since October 1999. From
December 1996 to October 1999 he served as Executive Vice President and as Chief
Operating Officer from October 1997 to October 1999. He was President of Howell
Crude Oil Company, a wholly-owned subsidiary of Howell Corporation, from
September 1992 to December 1996. Prior to joining Howell, Mr. Gorman worked for
Marathon Oil Company ("Marathon") for fifteen years in various capacities in
Crude Oil Acquisition and Finance and Administration, including Manager of Crude
Oil Purchases and Sales and Manager of Crude Oil Trading and Risk Management.
John P. vonBerg has served as a Director of the General Partner since
December 1996 and as Vice Chairman of the Board and Executive Vice President,
Trading and Price Risk Management, since October 1999. From December 1996 to
October 1999, he served as President and Chief Executive Officer of the General
Partner. He was Vice President of Crude Oil Gathering, Domestic Supply and
Trading, for Basis and its predecessor, Phibro
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USA, from January 1994 to December 1996. He managed the Gathering and Domestic
Trading and Commercial Support functions for Phibro USA during 1993. Prior
to 1993, Mr. vonBerg worked for Marathon for 13 years in various capacities,
including Product Trading, Risk Management, Crude Oil Purchases and Sales,
Finance, Auditing and Operations.
Michael A. Peak was elected to the Board of Directors of the General Partner
in April 1997. Since 1989, Mr. Peak has been a crude oil trader with Phibro,
Inc., a wholly-owned subsidiary of Salomon Smith Barney Holdings Inc. Prior to
joining Phibro, Inc., Mr. Peak worked for Marathon for thirteen years in various
capacities, including Manager of Crude Oil Trading, Business Development for the
Gulf Coast Pipeline Division, Controller of the Gulf Coast Pipeline Division,
Natural Gas Liquids Trader and several planning positions.
Robert T. Moffett became a Director of the General Partner in February 1999.
He has held the position of Vice President, General Counsel and Secretary of
Howell since December 1996. He was Vice President and General Counsel of Howell
from January 1995 to December 1996. Mr. Moffett joined Howell as General
Counsel in September 1992. From 1987 to 1992, Mr. Moffett was a partner in
Moffett and Brewster, an oil and gas investment firm.
Herbert I. Goodman was elected to the Board of Directors of the General
Partner in January 1997. He is the Chairman of IQ Holdings, Inc., a
manufacturer and marketer of petrochemical-based consumer products. From 1988
until 1996 he was Chairman and Chief Executive Officer of Applied Trading
Systems, Inc., a trading and consulting business. Prior to 1988, Mr. Goodman
was with Gulf Trading and Transportation Company and Gulf Oil Corporation.
Mr. J. Conley Stone was elected to the Board of Directors of the General
Partner in January 1997. From 1987 to his retirement in 1995, he served as
President, Chief Executive Officer, Chief Operating Officer and Director of
Plantation Pipe Line Company, a common carrier liquid petroleum products
pipeline transporter. From 1976 to 1987, Mr. Stone served in a variety of
executive positions with Exxon Pipeline Company.
John M. Fetzer has served as Executive Vice President since October 1999. He
was Senior Vice President, Crude Oil, for the General Partner since December
1996. He served in the same capacity for Howell Crude Oil Company from
September 1994 to December 1996. From 1993 to September 1994, Mr. Fetzer was a
private investor and a consultant and expert witness in oil and gas related
matters. He held the positions of Senior Vice President, Marketing, from 1991
to 1993 and Vice President of Crude Oil Trading from 1986 to 1991 at Enron Oil
Trading and Transportation. From 1981 to 1986, Mr. Fetzer served as Manager,
Crude Oil Trading for UPG Falco and P&O Falco, which later became Enron Oil
Trading and Transportation. Prior to joining P&O Falco he held various
financial and commercial positions with Marathon, which he joined in 1976.
Ross A. Benavides has served as Chief Financial Officer of the General
Partner since October 1998. He has served as General Counsel and Secretary
since December 1999. He served as Tax Counsel for Lyondell Petrochemical
Company ("Lyondell") from May 1997 to October 1998. Prior to joining Lyondell,
he was Vice President of Basis from June 1996 to May 1997 and Tax Director of
Basis from May 1994 to May 1996. From March 1990 to April 1994, he served as
Tax Manager for Lyondell.
Ben F. Runnels has served as Vice President, Trucking Operations of the
General Partner since December 1996. He held the position of General Manager,
Operations with Basis and its predecessor, Phibro USA, for the previous four
years. Prior to that, he was Manager, Operations for JM Petroleum Corporation
for four years. From 1974 until 1988, he was employed by Tesoro Petroleum Corp.
and held the positions of Terminal Manager, Regional Manager, Pipeline Manager,
and Division Manager, respectively. From 1962 until 1974, Mr. Runnels held
various managerial positions at Ryder Tank Lines, Coastal Tank Lines, Robertson
Tank Lines and Gulf Oil Corporation.
Kerry W. Mazoch has served as Vice President, Crude Oil Acquisitions, of the
General Partner since August 1997. From 1991 to 1997 he held the position of
Vice President and General Manager of Crude Oil Acquisitions at Northridge
Energy Marketing Corp., a wholly-owned subsidiary of TransCanada Pipelines
Limited. From 1972 until 1991 he was employed by Mesa Pipe Line Company and
held the positions of Vice President, Crude Oil, and General Manager, Refined
Products Marketing. Prior to 1972, Mr. Mazoch worked for Exxon Company U.S.A.
in various refined products marketing capacities.
Section 16(a) of the Securities Exchange Act of 1934 requires the officers
and directors of the General Partner and persons who own more than ten percent
of a registered class of the equity securities of the Partnership to file
reports of ownership and changes in ownership with the SEC and the New York
Stock Exchange. Based solely on its review of the copies of such reports
received by it, or written representations from certain reporting persons that
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no Forms 5 were required for those persons, the General Partner believes that
during 1999 its officers and directors complied with all applicable filing
requirements in a timely manner.
Representatives of Salomon and Howell and officers of the General Partner do
not receive any additional compensation for serving Genesis Energy, L.L.C., as
members of the Board of Directors or any of its committees. Each of the
independent directors receives an annual fee of $30,000.
Item 11. Executive Compensation
Under the terms of the Partnership Agreement, the Partnership is required to
reimburse the General Partner for expenses relating to the operation of the
Partnership, including salaries and bonuses of employees employed on behalf of
the Partnership, as well as the costs of providing benefits to such persons
under employee benefit plans and for the costs of health and life insurance.
See "Certain Relationships and Related Transactions."
The following table summarizes certain information regarding the compensation
paid or accrued by Genesis during 1999, 1998 and 1997 to the Chief Executive
Officer and each of Genesis' four other most highly compensated executive
officers (the "Named Officers").
Summary Compensation Table
Long-Term
Annual Compensation Compensation
-------------------------------- ------------
Awards
------------
Other Annual Restricted All Other
Salary Bonus Compensation Stock Awards Compensation
Name and Principal Position Year $ $ $ $ $
- --------------------------- ---- ------- ------ --------- ------------ -----------
Mark J. Gorman 1999 236,000 - - - 9,600
Chief Executive Officer 1998 230,000 37,500 - 570,891 9,600
and President 1997 212,500 37,500 - - 9,550
John P. vonBerg 1999 410,000 - - - 9,600
Executive Vice President, 1998 350,000 - - 570,891 9,600
Trading and Price Risk 1997 350,000 50,000 - - 9,550
Management
John M. Fetzer 1999 211,000 - - - 9,600
Executive Vice President 1998 200,000 37,500 - 570,891 9,600
1997 200,000 37,500 - - 9,550
Kerry W. Mazoch 1999 166,000 - - - 9,600
Vice President, Crude 1998 166,000 25,000 - 231,057 4,800
Oil Acquisitions 1997 62,250 15,000 - - 1,743
Ross A. Benavides 1999 150,000 - - - 9,586
Chief Financial Officer, 1998 31,700 10,000 - 185,000 1,904
General Counsel and
Secretary
No Named Officer had "Perquisites and Other Personal Benefits" with a value
greater than the lesser of $50,000 or 10% of reported salary and bonus.
Annual salary for the year 2000 is $270,000.
Includes $4,800 of Company-matching contributions to a defined contribution
plan and $4,800 of profit-sharing contributions to a defined contribution
plan.
Includes $4,793 of Company-matching contributions to a defined contribution
plan and $4,793 of profit-sharing contributions to a defined contribution
plan.
Restricted units were awarded to the Named Officer on January 27, 1998.
Under the terms of the Amended and Restated Restricted Unit Plan, the award
will vest in increments of one-third annually
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beginning on December 8, 1998. The vested units cannot be sold until one
year after vesting. Prior to vesting, distributions will be paid on
restricted units any time distributions are paid on the Subordinated
OLP Units. After vesting, the Named Officer will receive distributions
whenever distributions are paid to the Common Unitholders.
Mr. Gorman received an award of 29,090 restricted units. At December 31,
1999, Mr. Gorman had 19,293 vested restricted units with a value of $155,550
(determined using closing market price of unrestricted units on December 31,
1999). He had 6,842 unvested restricted units with a value of $55,164. Mr.
Gorman relinquished 2,855 of the units that vested in 1999 and 1998,
respectively, so that the value of the units on the vesting date ($6.6875 and
$16.8125 per unit, respectively) could be used to pay federal income taxes
owed on the vested portion of the award.
Mr. vonBerg received an award of 29,090 restricted units. At December 31,
1999, Mr. vonBerg had 12,558 vested restricted units with a value of $101,249
(determined using closing market price of unrestricted units on December 31,
1999). He had 6,842 unvested restricted units with a value of $55,164. Mr.
vonBerg relinquished 3,980 and 2,855 of the units that vested in 1999 and
1998, respectively, so that the value of the units on the vesting date
($6.6875 and $16.8125 per unit, respectively) could be used to pay federal
income taxes owed on the vested portion of the award.
Mr. Fetzer received an award of 29,090 restricted units. At December 31,
1999, Mr. Fetzer had 19,293 vested restricted units with a value of $155,550
(determined using closing market price of unrestricted units on December 31,
1999). He had 6,842 unvested restricted units with a value of $55,164. Mr.
Fetzer relinquished 2,855 of the units that vested in 1999 and 1998 so that
the value of the units on the vesting date ($6.6875 and $16.8125 per unit,
respectively) could be used to pay federal income taxes owed on the vested
portion of the award.
Mr. Mazoch received an award of 12,121 restricted units. At December 31,
1999, Mr. Mazoch had 5,702 vested restricted units with a value of $45,972
(determined using closing market price of unrestricted units on December 31,
1999). He had 4,041 unvested restricted units with a value of $32,581. Mr.
Mazoch relinquished 1,189 of the units that vested in 1999 and 1998 so that
the value of the units on the vesting date ($6.6875 and $16.8125 per unit,
respectively) could be used to pay federal income taxes owed on the vested
portion of the award.
Includes $4,800 of profit-sharing contributions to a defined contribution
plan.
Mr. Benavides received an award of 10,000 restricted units on October 27,
1998. Under the terms of the Amended and Restated Restricted Unit Plan, the
award will vest in increments of one-third annually beginning on December 8,
1999. The vested units cannot be sold until one year after vesting. Prior
to vesting, distributions will be paid on restricted units any time
distributions are paid on the Subordinated OLP Units. After vesting, and
Named Officer will receive distributions whenever distributions are paid to
the Common Unitholders. At December 31, 1999, Mr. Benavides had 1,965 vested
restricted units with a value of $15,843 (determined using closing market
price of unrestricted units on December 31, 1999). He had 6,667 unvested
restricted units with a value of $53,753. Mr. Benavides relinquished 1,368
of the units that vested in 1999 so that the value of the units on the
vesting date ($6.6875 per unit) could be used to pay federal income taxes
owed on the vested portion of the award.
Includes $952 of Company matching contributions to a defined contribution
plan and $952 of profit-sharing contributions to a defined contribution plan.
Includes $4,750 of Company-matching contributions to a defined contribution
plan and $4,800 of profit-sharing contributions to a defined contribution
plan.
Includes $1,743 of profit-sharing contributions to a defined contribution
plan.
Employment and Severance Agreements
At formation, the General Partner entered into employment agreements with
the following executive officers: Mr. vonBerg, Mr. Gorman, Mr. Fetzer and Mr.
Runnels. When Mr. Benavides was employed, the General Partner entered into an
employment agreement with him. The agreements with Mr. Gorman, Mr. vonBerg and
Mr. Fetzer expired December 31, 1999 and were replaced with severance
agreements. The initial agreement with Mr. Runnels expired December 31, 1999;
however, the General Partner exercised its option to extend the agreement for an
additional two years. The agreement with Mr. Benavides expires in October 2000.
The agreement with Mr. Runnels
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has five additional optional extension terms of one year each ("Extension
Terms"). The agreements with Mr. Runnels and Mr. Benavides include the
following additional provisions: (i) an annual base salary, (ii) eligibility
to participate in the Restricted Unit Plan (including the allocation of Initial
Restricted Units) and Incentive Compensation Plan described below, (iii)
confidential information and noncompetition provisions and (iv) an involuntary
termination provision pursuant to which the executive officer will receive
severance compensation under certain circumstances. Severance compensation
applicable under the employment agreements for an involuntary termination during
the Initial Term and Extension Terms (other than a termination for cause, as
defined in the agreements) will include payment of the greater of (i) the base
salary for the balance of the applicable term, or (ii) one year's base salary
then in effect and, in addition, the executive will be entitled to receive
incentive compensation payable to the executive in accordance with the Incentive
Plan. Upon expiration or termination of the agreement, the confidential
information and noncompetition provisions will continue until the earlier of one
year after the date of termination or the remainder of the unexpired term, but
in no event for less than six months following the expiration or termination.
The severance agreements with Mr. Gorman, Mr. vonBerg and Mr. Fetzer
include the following provisions should there be a Change in Control (defined as
a sale of substantially all of the Partnership's assets or a change in the
ownership of fifty percent or more of the General Partner): (i) a lump sum
payment of $270,000 for Mr. Gorman and Mr. Fetzer and $420,000 for Mr. vonBerg,
(ii) immediate vesting of any unvested awards under the Restricted Unit Plan and
(iii) payment of any incentive compensation payable to the executive in
accordance with the Incentive Plan. These provisions also apply to an
involuntary termination of the executive (other than a termination for cause, as
defined in the agreements). The severance agreements terminate on December 31,
2000, provided, however, that the benefits under the severance agreements apply
through July 1, 2001.
Restricted Unit Plan
In January 1997, the General Partner adopted a restricted unit plan for key
employees of the General Partner that provided for the award of rights to
receive Common Units under certain restrictions including meeting thresholds
tied to Available Cash and Adjusted Operating Surplus. In January 1998, the
restricted unit plan was amended and restated, and the thresholds tied to
Available Cash and Adjusted Operating Surplus were eliminated. The discussion
that follows is based on the terms of the Amended and Restated Restricted Unit
Plan (the "Restricted Unit Plan"). Initially, rights to receive 291,000 Common
Units are available under the Restricted Unit Plan. From these Units, rights to
receive 240,000 Common Units (the "Restricted Units") have been allocated to
approximately 32 individuals, subject to the vesting conditions described below
and subject to other customary terms and conditions.
One-third of the Restricted Units allocated to each individual vest
annually beginning in December 1998. The remaining rights to receive 51,000
Common Units initially available under the Restricted Unit Plan may be allocated
or issued in the future to key employees on such terms and conditions (including
vesting conditions) as the Compensation Committee of the General Partner
("Compensation Committee") shall determine.
Upon "vesting" in accordance with the terms and conditions of the
Restricted Unit Plan, Common Units allocated to a plan participant will be
issued to such participant. Units issued to participants may be newly issued
Units acquired by the General Partner from the Partnership at then prevailing
market prices or may be acquired by the General Partner in the open market. In
either case, the associated expense will be borne by the Partnership. Until
Common Units have vested and have been issued to a participant, such participant
shall not be entitled to any distributions or allocations of income or loss and
shall not have any voting or other rights in respect of such Common Units. The
participant shall receive cash awards based on the number of non-vested units
held by such participant to the extent that distributions are paid on
Subordinated OLP Units. To date, no distributions have been paid with respect
to Subordinated OLP Units. No consideration will be payable by the plan
participants upon vesting and issuance of the Common Units. The plan
participant cannot sell the Common Units until one year after the date of
vesting.
Termination without cause in violation of a written employment agreement,
or a Significant Event as defined in the Restricted Unit Plan, will result in
immediate vesting of all non-vested units and conversion to Common Units without
any restrictions.
Incentive Plan
In January 1997, the General Partner adopted the Genesis Incentive
Compensation Plan (the "Incentive Plan") and amended it in January 1998. The
Incentive Plan is designed to enhance the financial performance of the
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Partnership by rewarding the executive officers and other specific key employees
for achieving annual financial performance objectives. The Incentive Plan will
be administered by the Compensation Committee. Individual
participants and payments, if any, for each calendar year will be determined by
and in the discretion of the Compensation Committee. No incentive payments will
be made with respect to any year unless (i) the aggregate MQD in the Incentive
Plan year has been distributed to each holder of Common Units, plus any
arrearage thereon, (ii) the Adjusted Operating Surplus generated during such
year has equaled or exceeded the sum of the MQD on all of the outstanding Common
Units and the related distribution on the General Partner's interest during such
year and (iii) no APIs are outstanding. In addition, incentive payments will
not exceed $375,000 with respect to any year unless (i) each holder of
Subordinated OLP Units has also received the aggregate MQD and (ii) the Adjusted
Operating Surplus generated during such year exceeded the sum of the MQD on all
of the outstanding Common Units and Subordinated OLP Units and the related
distribution on the General Partner's interest during such year. Any incentive
payments will be at the discretion of the Compensation Committee, and the
General Partner will be able to amend or change the Incentive Plan at any time.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The Partnership knows of no one who beneficially owns in excess of five
percent of the Common Units of the Partnership. As set forth below, certain
beneficial owners own interests in the General Partner of the Partnership as of
February 29, 2000.
Amount and Nature
Name and Address of Beneficial Ownership Percent
Title of Class of Beneficial Owner as of January 1, 2000 of Class
------------------------ --------------------------------- --------------------- --------
General Partner Interest Genesis Energy, L.L.C. 1 100.00
500 Dallas, Suite 2500
Houston, TX 77002
General Partner Interest Salomon Smith Barney Holdings Inc. 1 100.00
Seven World Trade Center
New York, NY 10048
_____________________
Salomon owns Genesis Energy, L.L.C. The reporting of the General Partner
interest shall not be deemed to be a concession that such interest
represents a security.
The following table sets forth certain information as of February 29, 2000,
regarding the beneficial ownership of the Common Units by all directors of the
General Partner, each of the named executive officers and all directors and
executive officers as a group.
Amount and Nature of Beneficial Ownership
--------------------------------------------
Sole Voting and Shared Voting and Percent
Title of Class Name Investment Power Investment Power of Class
-------------------- ----------------- ---------------- ---------------- --------
Genesis Energy, L.P. A. Richard Janiak - - -
Common Unit Mark J. Gorman 18,683 - *
John P. vonBerg 18,558 - *
Michael A. Peak 25,420 - *
Robert T. Moffett - - -
Herbert I. Goodman 2,000 - *
J. Conley Stone 1,000 - *
John M. Fetzer 18,683 - *
Kerry W. Mazoch 5,702 - *
Ross A. Benavides 4,965 - *
All directors and
executive officers
as a group (11 in
number) 100,073 - 1
------------------
* Less than 1%
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The above table includes shares owned by certain members of the families of
the directors or executive officers, including shares in which pecuniary
interest may be disclaimed.
Item 13. Certain Relationships and Related Transactions
See Note 12 to the Consolidated Financial Statements for information
regarding certain transactions between Genesis and the General Partner, Salomon,
Howell and their subsidiaries and affiliates.
Salomon and Howell own 1,163,700 and 991,300 Subordinated OLP Units,
respectively, representing a 10.58% and 9.01% limited partner interest in GCOLP.
During 1999, Salomon and Howell owned 54% and 46%, respectively, of the General
Partner. Effective February 28, 2000, Salomon acquired Howell's 46% interest in
the General Partner. Through its control of the General Partner, Salomon has
the ability to control the management of the Partnership and GCOLP.
Redemption and Registration Rights Agreement. Pursuant to the Redemption and
Registration Rights Agreement, the Partnership has agreed, at the end of the
Subordination Period or upon earlier conversion of Subordinated OLP Units into
Common OLP Units, to use reasonable efforts to sell that number of Common Units
equal to the number of Common OLP Units that Salomon or Howell is requesting be
redeemed. The proceeds, net of underwriting discount or placement fees, if any,
from such sale will be used by the Operating Partnership to redeem such Common
OLP Units. The Partnership is obligated to pay the expenses incidental to
redemption requests, other than the underwriting discount or placement fees, if
any. The General Partner will have a proportionate percentage of its general
partner interest in the Operating Partnership redeemed when Common OLP Units are
redeemed in connection with the exercise of the redemption right.
Distribution Support Agreement. To further enhance the Partnership's ability
to distribute the Minimum Quarterly Distribution on the Common Units with
respect to each quarter through the quarter ending December 31, 2001, Salomon
has agreed in the Distribution Support Agreement, subject to certain
limitations, to contribute or cause to be contributed cash, if necessary, to the
Partnership in return for APIs. Salomon's obligation to purchase APIs is
limited to a maximum amount outstanding at any one time equal to $17.6 million.
As of December 31, 1999, $3.9 million of the Distribution Support had been
utilized and an additional $2.2 million was utilized in February 2000. $11.5
million remains available for periods after February 2000. The Unitholders have
no independent right separate and apart from the Partnership to enforce
obligations of Salomon under the Distribution Support Agreement.
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a)(1) and (2) Financial Statements and Financial Statement Schedules
See "Index to Consolidated Financial Statements" set forth on page Error!
Bookmark not defined..
(a)(3) Exhibits
3.1 Certificate of Limited Partnership of Genesis Energy, L.P.
("Genesis") (incorporated by reference to Exhibit 3.1 to
Registration Statement, File No. 333-11545)
** 3.2 Agreement of Limited Partnership of Genesis
** 3.3 Certificate of Limited Partnership of Genesis Crude Oil, L.P.
(the "Operating Partnership")
3.4 Agreement of Limited Partnership of the Operating Partnership
(incorporated by reference to Exhibit 3.4 to Registration
Statement, File No. 333-11545)
** 10.1 Purchase & Sale and Contribution & Conveyance Agreement dated
as of December 3, 1996 among Basis Petroleum, Inc. ("Basis"),
Howell Corporation ("Howell"), certain subsidiaries of Howell,
Genesis, the Operating Partnership and Genesis Energy, L.L.C.
** 10.2 First Amendment to Purchase & Sale and Contribution &
Conveyance Agreement
** 10.3 Distribution Support Agreement among the Operating Partnership
and Salomon Inc
** 10.4 Master Credit Support Agreement among the Operating
Partnership, Salomon Inc and Basis
** 10.5 Redemption and Registration Rights Agreement among Basis,
Howell, certain Howell subsidiaries, Genesis and the Operating
Partnership
26
27
10.7 Non-competition Agreement among Genesis, the Operating
Partnership, Salomon Inc, Basis and Howell (incorporated by
reference to Exhibit 10.6 to Registration Statement, File No. 333-
11545)
10.8 Severance Agreement between Genesis Energy, L.L.C. and John P.
vonBerg (incorporated by reference to Exhibit 10.3 to Form 10-Q for
the quarterly period ended September 30, 1999)
10.9 Severance Agreement between Genesis Energy, L.L.C. and Mark J.
Gorman (incorporated by reference to Exhibit 10.2 to Form 10-Q for
the quarterly period ended September 30, 1999)
10.10 Severance Agreement between Genesis Energy, L.L.C. and
John M. Fetzer (incorporated by reference to Exhibit 10.4 to Form
10-Q for the quarterly period ended September 30, 1999)
10.11 Employment Agreement between Genesis Energy, L.L.C. and
Ross A. Benavides (incorporated by reference to Exhibit 10.3 to
Form 10-Q for the quarterly period ended September 30, 1998)
** 10.12 Employment Agreement between Genesis Energy, L.L.C. and
Ben F. Runnels
10.13 Extension of Employment Agreement between Genesis Energy,
L.L.C. and Ben F. Runnels, (incorporated by reference to Exhibit
10.6 to Form 10-Q for the quarterly period ended September 30,
1999)
10.14 Office Lease at One Allen Center between Trizec Allen
Center Limited Partnership (Landlord) and Genesis Crude Oil, L.P.
(Tenant) (incorporated by reference to Exhibit 10 to Form 10-Q for
the quarterly period ended September 30, 1997)
10.15 Third Amendment to Master Credit Support Agreement
(incorporated by reference to Exhibit 10 to Form 10-Q for the
quarterly period ended September 30, 1997)
10.16 Sixth Amendment to Master Credit Support Agreement
(incorporated by reference to Exhibit 10.17 to Form 10-K for the
year ended December 31, 1997)
10.17 Tenth Amendment to Master Credit Support Agreement
(incorporated by reference to Exhibit 10.1 to Form 8-K dated June
1, 1999)
10.18 Eleventh Amendment to Master Credit Support Agreement
(incorporated by reference to Exhibit 10.1 to Form 10-Q for the
quarterly period ended September 30, 1999)
10.19 Amended and Restated Restricted Unit Plan (incorporated
by reference to Exhibit 10.18 to Form 10-K for the year ended
December 31, 1997)
10.20 Agreement by and between Genesis Crude Oil, L.P. and Bank
One, Texas, N.A. dated as of August 14, 1998 (incorporated by
reference to Exhibit 10.1 to Form 10-Q for the quarterly period
ended September 30, 1998)
10.21 Amendment No. 1 to Loan Agreement by and between Genesis
Crude Oil, L.P. and Bank One, Texas, N.A. dated as of August 14,
1998 (incorporated by reference to Exhibit 10.2 to Form 10-Q for
the quarterly period ended September 30, 1998)
10.22 Amendment No. 2 to Loan Agreement by and between Genesis
Crude Oil, L.P. and Bank One, Texas, N.A. dated as of August 14,
1998 (incorporated by reference to Exhibit 10.21 to Form 10-K for
the year ended December 31, 1998)
10.23 Credit Agreement dated as of March 29, 2000, between
Genesis Crude Oil, L.P. and Certain Lenders, with Paribas as Agent
11.1 Statement Regarding Computation of Per Share Earnings (See Note 3
to the Consolidated Financial Statements - "Net Income Per Common
Unit")
* 21.1 Subsidiaries of the Registrant
* 27 Financial Data Schedule
----------------------
27
28
* Filed herewith
** Filed as an exhibit to the Partnership's Annual Report on Form 10-K for
the year ended December 31, 1996.
(b) Reports on Form 8-K
None.
28
29
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 on the 27th day of
March, 2000.
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
By: GENESIS ENERGY, L.L.C., as
General Partner
By:/s/ Mark J. Gorman
------------------------
Mark J. Gorman
Chief Executive Officer and President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons in the capacities and on
the dates indicated.
/s/ Mark J. Gorman Director, Chief Executive Officer March 27, 2000
----------------------
Mark J. Gorman and President
(Principal Executive Officer)
/s/ Ross A. Benavides Chief Financial Officer, March 27, 2000
----------------------
Ross A. Benavides General Counsel and
Secretary
(Principal Financial and
Accounting Officer)
/s/ A. Richard Janiak Chairman of the Board and March 27, 2000
----------------------
A. Richard Janiak Director
/s/ Herbert I. Goodman Director March 27, 2000
----------------------
Herbert I. Goodman
/s/ J. Conley Stone Director March 27, 2000
----------------------
J. Conley Stone
/s/ Michael A. Peak Director March 27, 2000
----------------------
Michael A. Peak
/s/ Robert T. Moffett Director March 27, 2000
----------------------
Robert T. Moffett
/s/ John P. vonBerg Vice Chairman, Director, and Executive March 27, 2000
---------------------
John P. vonBerg Vice President, Trading and Price
Risk Management
29
30
GENESIS ENERGY, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
Report of Independent Public Accountants 31
Consolidated Balance Sheets, December 31, 1999 and 1998 32
Consolidated Statements of Operations for the Years Ended December
31, 1999, 1998 and 1997 33
Consolidated Statements of Cash Flows for the Years Ended December
31, 1999, 1998 and 1997 34
Consolidated Statements of Partners' Capital for the Years Ended
December 31, 1999, 1998 and 1997 35
Notes to Consolidated Financial Statements 36
30
31
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Genesis Energy, L.P.:
We have audited the accompanying consolidated balance sheets of Genesis Energy,
L.P., (a Delaware limited partnership) as of December 31, 1999 and 1998 and the
related consolidated statements of operations, cash flows and partners' capital
for each of the three years in the period ended December 31, 1999. These
financial statements are the responsibility of the Partnership's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Genesis Energy, L.P.
as of December 31, 1999 and 1998, and the results of its operations and its 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.
ARTHUR ANDERSEN LLP
Houston, Texas
March 2, 2000
31
32
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31, December 31,
1999 1998
------------ ------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 6,664 $ 7,710
Accounts receivable -
Trade 241,529 167,600
Related party 7,030 4,634
Inventories 404 1,966
Other 19,090 3,306
-------- --------
Total current assets 274,717 185,216
FIXED ASSETS, at cost 116,332 119,310
Less: Accumulated depreciation (22,419) (20,707)
-------- --------
Net fixed assets 93,913 98,603
OTHER ASSETS, net of amortization 11,962 13,354
-------- --------
TOTAL ASSETS $380,592 $297,173
======== ========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Current portion of long-term debt $ 19,900 $ -
Accounts payable -
Trade 251,742 172,143
Related party 1,604 6,200
Accrued liabilities 19,290 5,171
-------- --------
Total current liabilities 292,536 183,514
LONG-TERM DEBT - 15,800
COMMITMENTS AND CONTINGENCIES (Note 18)
ADDITIONAL PARTNERSHIP INTERESTS 3,900 -
MINORITY INTERESTS 30,571 29,988
PARTNERS' CAPITAL
Common unitholders, 8,625 units issued;
8,620 and 8,604 units outstanding
at December 31, 1999 and 1998,
respectively 52,574 66,832
General partner 1,051 1,357
-------- --------
Subtotal 53,625 68,189
Treasury units, 5 and 21 units at
December 31, 1999 and 1998,
respectively (40) (318)
-------- --------
Total partners' capital 53,585 67,871
-------- --------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $380,592 $297,173
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
32
33
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
Year Ended December 31,
---------------------------------
1999 1998 1997
---------- ---------- ----------
REVENUES:
Gathering and marketing revenues
Unrelated parties $2,067,451 $2,178,224 $2,911,333
Related parties 77,195 38,718 443,606
Pipeline revenues 16,366 16,533 17,989
---------- ---------- ----------
Total revenues 2,161,012 2,233,475 3,372,928
COST OF SALES:
Crude costs, unrelated parties 2,043,506 2,141,715 3,147,694
Crude costs, related parties 74,812 42,814 183,490
Field operating costs 11,669 12,778 12,107
Pipeline operating costs 8,161 7,971 6,016
---------- ---------- ----------
Total cost of sales 2,138,148 2,205,278 3,349,307
---------- ---------- ----------
GROSS MARGIN 22,864 28,197 23,621
EXPENSES:
General and administrative 11,649 11,468 8,557
Depreciation and amortization 8,220 7,719 6,300
Nonrecurring charges - 373 -
---------- ---------- ----------
OPERATING INCOME 2,995 8,637 8,764
OTHER INCOME (EXPENSE):
Interest income 156 421 1,190
Interest expense (1,085) (267) (127)
Other, net 849 28 21
---------- ---------- ----------
Net income before minority interests 2,915 8,819 9,848
Minority interests 583 1,763 1,968
---------- ---------- ----------
NET INCOME $ 2,332 $ 7,056 $ 7,880
NET INCOME PER COMMON UNIT- BASIC AND DILUTED $ 0.27 $ 0.80 $ 0.90
========== ========== ==========
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING 8,604 8,606 8,625
========== ========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
33
34
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Year Ended December 31,
1999 1998 1997
-------- -------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 2,332 $ 7,056 $ 7,880
Adjustments to reconcile net income to net
cash provided by (used in) operating
activities -
Depreciation 6,832 6,529 5,820
Amortization of intangible assets 1,388 1,190 480
(Gain) loss on disposal of assets (849) 269 (21)
Minority interests equity in earnings 583 1,763 1,968
Other noncash charges 1,459 1,503 66
Changes in components of working capital -
Accounts receivable (76,325) 37,635 178,938
Inventories 1,562 1,384 1,257
Other current assets (15,784) 182 (2,092)
Accounts payable 75,003 (39,648) (172,761)
Accrued liabilities 13,861 (1,446) (1,330)
-------- -------- ---------
Net cash provided by operating activities 10,062 16,417 20,205
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (2,717) (13,431) (5,848)
Change in other assets 416 (4,270) (162)
Proceeds from sales of assets 1,012 188 348
-------- -------- ---------
Net cash used in investing activities (1,289) (17,513) (5,662)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under Loan Agreement 4,100 15,800 -
Distributions to common unitholders (17,206) (17,208) (14,317)
Distributions to General Partner (352) (352) (292)
Issuance of additional partnership interests 3,900 - -
Purchase of treasury units (261) (1,246) -
-------- -------- ---------
Net cash used in financing activities (9,819) (3,006) (14,609)
Net decrease in cash and cash equivalents (1,046) (4,102) (66)
Cash and cash equivalents at beginning of period 7,710 11,812 11,878
-------- -------- ---------
Cash and cash equivalents at end of period $ 6,664 $ 7,710 $ 11,812
======== ======== =========
The accompanying notes are an integral part of these consolidated financial
statements.
34
35
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(In thousands)
Partners' Capital
--------------------------------------
Common General Treasury
Unitholders Partner Units Total
-------- ----- ------- --------
Partners' capital at December 31, 1996 $ 83,378 $1,702 $ - $ 85,080
Net income 7,722 158 - 7,880
Cash distributions (14,317) (292) - (14,609)
-------- ------ ------- --------
Partners' capital at December 31, 1997 76,783 1,568 - 78,351
Net income 6,915 141 - 7,056
Cash distributions (17,208) (352) - (17,560)
Purchase of treasury units - - (1,246) (1,246)
Issuance of treasury units to Restricted
Unit Plan participants - - 928 928
Excess of expense over cost of treasury
units issued for Restricted Unit Plan 342 - - 342
-------- ------ ------- --------
Partners' capital, December 31, 1998 66,832 1,357 (318) 67,871
Net income 2,286 46 - 2,332
Cash distributions (17,206) (352) - (17,558)
Purchase of treasury units - - (261) (261)
Issuance of treasury units to Restricted Unit
Plan participants - - 539 539
Excess of expense over cost of treasury units
issued for Restricted Unit Plan 662 - - 662
-------- ------ ------- --------
Partners' capital, December 31, 1999 $ 52,574 $1,051 $ (40) $ 53,585
======== ====== ======= ========
The accompanying notes are an integral part of these consolidated financial
statements.
35
36
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Formation and Offering
In December 1996, Genesis Energy, L.P. ("GELP" or the "Partnership")
completed an initial public offering of 8.6 million Common Units at $20.625 per
unit, representing limited partner interests in GELP of 98%. Genesis Energy,
L.L.C. (the "General Partner") serves as general partner of GELP and its
operating limited partnership, Genesis Crude Oil, L.P. Genesis Crude Oil, L.P.
has two subsidiary limited partnerships, Genesis Pipeline Texas, L.P. and
Genesis Pipeline USA, L.P. Genesis Crude Oil, L.P. and its subsidiary
partnerships will be referred to collectively as GCOLP. The General Partner
owns a 2% general partner interest in GELP.
Transactions at Formation
At the closing of the offering, GELP contributed the net proceeds of the
offering ($163.0 million) to GCOLP in exchange for a 80.01% general partner
interest in GCOLP. With the net proceeds of the offering, GCOLP purchased for
$74.0 million a portion of the crude oil gathering, marketing and pipeline
operations of Howell Corporation ("Howell") and made a distribution of $86.9
million to Basis Petroleum, Inc. ("Basis") in exchange for its conveyance of a
portion of its crude oil gathering and marketing operations. GCOLP issued an
aggregate of 2.2 million subordinated limited partner units ("Subordinated OLP
Units") to Basis and Howell to obtain the remaining operations. Basis'
Subordinated OLP Units were transferred to its then parent, Salomon Smith Barney
Holdings Inc. ("Salomon") in May 1997. The General Partner received an
effective 2% general partner interest in GELP in exchange for a contribution of
$2.9 million. The effects of these transactions, and the dilutive effect of
differences in the consideration paid by the respective parties for their
interests, have been reflected in the initial capital recorded by the
Partnership.
At formation, Basis had the largest ownership interest in the Partnership,
with an effective 10.58% limited partner interest in GCOLP and ownership of 54%
of the General Partner; therefore, the net assets acquired from Basis were
recorded at their historical carrying amounts and the crude oil gathering and
marketing division of Basis were treated as the Predecessor and the acquirer of
Howell's operations. The acquisition of Howell's operations was treated as a
purchase for accounting purposes.
2. Basis of Presentation
The accompanying financial statements and related notes present the
consolidated financial position as of December 31, 1999 and 1998 for GELP and
its results of operations, cash flows and changes in partners' capital for the
years ended December 31, 1999, 1998 and 1997.
No provision for income taxes related to the operation of GELP is included in
the accompanying consolidated financial statements, as such income will be
taxable directly to the partners holding partnership interests in the
Partnership.
3. Summary of Significant Accounting Policies
Principles of Consolidation
The Partnership owns and operates its assets through GCOLP, an operating
limited partnership. The accompanying consolidated financial statements reflect
the combined accounts of the Partnership and the operating partnership after
elimination of intercompany transactions. All material intercompany accounts
and transactions have been eliminated.
Nature of Operations
The principal business activities of the Partnership are the purchasing,
gathering, transporting and marketing of crude oil in the United States. The
Partnership gathers approximately 99,000 barrels per day at the wellhead
principally in the southern and southwestern states. The Partnership also owns
and operates three crude oil pipelines onshore. The onshore pipelines are in
Texas, Mississippi/Louisiana and Florida/Alabama.
36
37
Use of Estimates
The preparation of consolidated 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, if any, at the date of the
consolidated financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
Cash and Cash Equivalents
The Partnership considers investments purchased with an original maturity
of three months or less to be cash equivalents. The Partnership has no
requirement for compensating balances or restrictions on cash.
Inventories
Crude oil inventories held for sale are valued at market. Store warehouse
inventories, including tractor and trailer parts, supplies and fuel, are carried
at the lower of cost or market.
Fixed Assets
Property and equipment are carried at cost. Depreciation of property and
equipment is provided using the straight-line method over the respective
estimated useful lives of the assets. Asset lives are 20 years for pipelines
and related assets, 3 to 7 years for vehicles and transportation equipment, and
3 to 10 years for buildings, office equipment, furniture and fixtures and other
equipment. Maintenance and repair costs are charged to expense as incurred.
Costs incurred for major replacements and upgrades are capitalized and
depreciated over the remaining useful life of the asset. Certain volumes of
crude oil are classified in fixed assets, as they are necessary to ensure
efficient and uninterrupted operations of the gathering businesses. These crude
oil volumes are carried at their weighted average cost.
Other Assets
Other assets consist primarily of intangibles and goodwill. Intangibles
include a covenant not to compete, which is being amortized over five years.
Goodwill represents the excess of purchase price over fair value of the net
assets acquired for acquisitions accounted for as purchases and is being
amortized over a period of 20 years.
Minority Interests
Minority interests represent the Subordinated OLP Units held by Salomon and
Howell totaling 19.59% in GCOLP and the 0.4% interest the General Partner owns
directly in GCOLP.
Environmental Liabilities
The Partnership provides for the estimated costs of environmental
contingencies when liabilities are likely to occur and reasonable estimates can
be made. Ongoing environmental compliance costs, including maintenance and
monitoring costs, are charged to expense as incurred.
Hedging Activities
The Partnership routinely utilizes forward contracts, swaps, options and
futures contracts in an effort to minimize the impact of crude oil price
fluctuations on inventories and contractual commitments. Gains and losses
related to these hedging activities are deferred until the transaction being
hedged has settled and its related profit or loss is recognized. Deferred gains
and losses from hedging activities are included in the Consolidated Balance
Sheets in accrued liabilities or accounts receivable, respectively. Recognized
gains and losses from hedging activities are included in crude costs in the
Consolidated Statements of Operations. Unrecognized loss of $1,718,000 and
$1,042,000 were deferred on these contracts at December 31, 1999 and 1998,
respectively.
Based on the historical correlations between the NYMEX price for West Texas
intermediate crude at Cushing, Oklahoma, and the various trading hubs at which
the Partnership trades, the Partnership's management believes the hedging
program has been effective in minimizing the overall price risk. The
Partnership continuously monitors the basis (location) differentials between its
various trading hubs and Cushing, Oklahoma, to further manage its exposure.
Should a hedging contract became ineffective or otherwise cease to serve as
a hedge, the hedging instrument is accounted for under the mark-to-market method
of accounting. Under this method, the contract is reflected at
37
38
market value, and the resulting unrealized gains and losses are recognized
currently in crude costs in the Consolidated Statements of Operations.
Revenue Recognition
Gathering and marketing revenues are recognized when title to the crude oil
is transferred to the customer. Pipeline revenues are recognized upon delivery
of the barrels to the location designated by the shipper.
Cost of Sales
Cost of sales consists of the cost of crude oil and field and pipeline
operating expenses. Field and pipeline operating expenses consist primarily of
labor costs for drivers and pipeline field personnel, truck rental costs, fuel
and maintenance, utilities, insurance and property taxes.
Net Income Per Common Unit
Basic net income per Common Unit is calculated on the weighted average
number of outstanding Common Units. The weighted average number of Common Units
outstanding was 8,604,352, 8,605,934 and 8,625,000 for the years ended December
31, 1999, 1998 and 1997, respectively. For this purpose, the 2% General Partner
interest is excluded from net income. Diluted net income per Common Unit did
not differ from basic net income per Common Unit for any period presented.
4. New Accounting Pronouncements
In November 1998, the Emerging Issues Task Force (EITF) reached a consensus
on EITF Issue 98-10, "Accounting for Energy Trading and Risk Management
Activities". This consensus, effective in the first quarter of 1999, requires
that certain energy related contracts be marked-to-market, with gains or losses
recognized in current earnings. The Partnership has determined that its
activities do not meet the definition in EITF Issue 98-10 of "energy trading"
activities and, therefore, it was not required to make any change in its
accounting.
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities",
was issued in June 1998. This standard was subsequently amended by SFAS 137.
This new standard, which the Partnership will be required to adopt for its
fiscal year 2001, will change the method of accounting for changes in the fair
value of certain derivative instruments by requiring that an entity recognize
the derivative at fair value as an asset or liability on its balance sheet.
Depending on the purpose of the derivative and the item it is hedging, the
changes in fair value of the derivative will be recognized in current earnings
or as a component of other comprehensive income in partners' capital. The
Partnership is in the process of evaluating the impact that this statement will
have on its results of operations and financial position. This new standard
could increase volatility in net income and comprehensive income.
5. Business Segment and Customer Information
Based on its management approach, the Partnership believes that all of its
material operations revolve around the gathering, transportation and marketing
of crude oil, and it currently reports its operations, both internally and
externally, as a single business segment. A significant portion of the
Partnership's revenues in 1997 resulted from transactions with Basis and other
Salomon affiliates. No other customer accounted for more than 10% of the
Partnership's revenues in any period.
6. Inventories
Inventories consisted of the following (in thousands).
December 31,
--------------
1999 1998
---- ------
Crude oil inventories, at market $ - $1,644
Store warehouse inventories, at lower of
cost or market 404 322
---- ------
Total inventories $404 $1,966
==== ======
38
39
7. Fixed Assets
Fixed assets consisted of the following (in thousands).
December 31,
------------------
1999 1998
-------- --------
Land and buildings $ 3,726 $ 3,489
Pipelines and related assets 95,378 93,796
Vehicles and transportation equipment 5,950 8,006
Office equipment, furniture and fixtures 2,347 5,281
Other 8,931 8,738
-------- --------
116,332 119,310
Less - Accumulated depreciation (22,419) (20,707)
-------- --------
Net fixed assets $ 93,913 $ 98,603
======== ========
Depreciation expense was $6,832,000, $6,529,000 and $5,820,000 for the years
ended December 31, 1999, 1998 and 1997, respectively.
8. Other Assets
Other assets consisted of the following (in thousands).
December 31,
-----------------
1999 1998
------- -------
Goodwill $ 9,401 $ 9,401
NYMEX seats 1,203 1,203
Covenant not to compete 4,238 4,393
Other 62 66
------- -------
14,904 15,063
Less - Accumulated amortization (2,942) (1,709)
------- -------
Net other assets $11,962 $13,354
======= =======
Amortization expense was $1,388,000, $1,190,000 and $480,000 for the years
ended December 31, 1999, 1998 and 1997, respectively.
9. Credit Resources and Liquidity
GCOLP entered into credit facilities with Salomon (collectively, the "Credit
Facilities"), pursuant to a Master Credit Support Agreement. GCOLP's
obligations under the Credit Facilities are secured by its receivables,
inventories, general intangibles and cash.
Guaranty Facility
Salomon is providing a Guaranty Facility through December 31, 2000 in
connection with the purchase, sale and exchange of crude oil by GCOLP. The
aggregate amount of the Guaranty Facility is limited to $300 million for the
year ending December 31, 2000 (to be reduced in each case by the amount of any
obligation to a third party to the extent that such third party has a prior
security interest in the collateral). GCOLP pays a guarantee fee to Salomon
which increases over the remaining term, thereby increasing the cost of the
Guaranty Facility. At December 31, 1999, the aggregate amount of obligations
covered by guarantees was $164 million, including $72 million in payable
obligations and $92 million of estimated crude oil purchase obligations for
January 2000.
The Master Credit Support Agreement contains various restrictive and
affirmative covenants including (i) restrictions on indebtedness other than (a)
pre-existing indebtedness, (b) indebtedness pursuant to Hedging Agreements (as
defined in the Master Credit Support Agreement) entered into in the ordinary
course of business and (c) indebtedness incurred in the ordinary course of
business by acquiring and holding receivables to be collected in accordance with
customary trade terms, (ii) restrictions on certain liens, investments,
guarantees, loans, advances, lines of business, acquisitions, mergers,
consolidations and sales of assets and (iii) compliance with certain risk
management policies, audit and receivable risk exposure practices and cash
management practices as may from time to time be revised or altered by Salomon
in its sole discretion.
Pursuant to the Master Credit Support Agreement, GCOLP is required to
maintain (a) Consolidated Tangible Net Worth of not less than $50 million, (b)
Consolidated Working Capital of not less than $1 million, (c) a ratio of
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its Consolidated Current Liabilities to Consolidated Working Capital plus net
property, plant and equipment of not more than 7.5 to 1, (d) a ratio of
Consolidated Earnings before Interest, Taxes, Depreciation and Amortization to
Consolidated Fixed Charges of at least 1.75 to 1 as of the last day of each
fiscal quarter prior to December 31, 1999 and (e) a ratio of Consolidated Total
Liabilities to Consolidated Tangible Net Worth of not more than 10.0 to 1 (as
such terms are defined in the Master Credit Support Agreement). The Partnership
is currently in compliance with the provisions of this agreement.
An Event of Default could result in the termination of the Credit
Facilities at the discretion of Salomon. Significant Events of Default include
(a) a default in the payment of (i) any principal on any payment obligation
under the Credit Facilities when due or (ii) interest or fees or other amounts
within two business days of the due date, (b) the guaranty exposure amount
exceeding the maximum credit support amount for two consecutive calendar months,
(c) failure to perform or otherwise comply with any covenants contained in the
Master Credit Support Agreement if such failure continues unremedied for a
period of 30 days after written notice thereof and (d) a material
misrepresentation in connection with any loan, letter of credit or guarantee
issued under the Credit Facilities. Removal of the General Partner will result
in the termination of the Credit Facilities and the release of all of Salomon's
obligations thereunder.
There can be no assurance of the availability or the terms of credit for
the Partnership. At this time, Salomon does not intend to provide guarantees or
other credit support after the credit support period expires in December 2000.
If the General Partner is removed without its consent, Salomon's credit support
obligations will terminate. In addition, Salomon's obligations under the Master
Credit Support Agreement may be transferred or terminated early subject to
certain conditions. Management of the Partnership intends to replace the
Guaranty Facility with a letter of credit facility with one or more third party
lenders prior to December 2000 and has had preliminary discussions with banks
about a replacement letter of credit facility. The General Partner may be
required to reduce or restrict the Partnership's gathering and marketing
activities because of limitations on its ability to obtain credit support and
financing for its working capital needs. The General Partner expects that the
overall cost of a replacement facility may be substantially greater than what
the Partnership is incurring under its existing Master Credit Support Agreement.
Any significant decrease in the Partnership's financial strength, regardless of
the reason for such decrease, may increase the number of transactions requiring
letters of credit or other financial support, make it more difficult for the
Partnership to obtain such letters of credit, and/or may increase the cost of
obtaining them. This situation could in turn adversely affect the Partnership's
ability to maintain or increase the level of its purchasing and marketing
activities or otherwise adversely affect the Partnership's profitability and
Available Cash.
Working Capital Facility
Until replaced as described below, Salomon provided GCOLP with a Working
Capital Facility of up to $50 million, which amount included direct cash
advances not to exceed $35 million outstanding at any one time and letters of
credit that may be required in the ordinary course of GCOLP's business.
In August 1998, GCOLP entered into a revolving credit/loan agreement ("Loan
Agreement") with Bank One, Texas, N.A. ("Bank One") to replace the Working
Capital Facility that had been provided by Salomon. The Loan Agreement provides
for loans or letters of credit in the aggregate not to exceed the greater of $35
million or the Borrowing Base (as defined in the Loan Agreement). Loans will
bear interest at a rate chosen by GCOLP which would be one or more of the
following: (a) a Floating Base Rate (as defined in the Loan Agreement) that is
generally the prevailing prime rate less one percent; (b) a rate based on the
Federal Funds Rate plus one and one-half percent or (c) a rate based on LIBOR
plus one and one-quarter percent. The Loan Agreement provides for a revolving
period until August 14, 2000, with interest to be paid monthly. All loans
outstanding on August 14, 2000, are due at that time.
The Loan Agreement is collateralized by the accounts receivable and
inventory of GCOLP, subject to the terms of an Intercreditor Agreement between
Bank One and Salomon. There is no compensating balance requirement under the
Loan Agreement. A commitment fee of 0.35% on the available portion of the
commitment is provided for in the agreement. Material covenants and
restrictions include requirements to maintain a ratio of current assets (as
defined in the Loan Agreement) to current liabilities of at least 1:1 and to
maintain tangible net worth in GCOLP, as defined in the Loan Agreement, of not
less than $65 million. The Partnership is currently in compliance with the
provisions of this agreement.
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At December 31, 1999, the Partnership had $19.9 million of loans
outstanding under the Loan Agreement. The Partnership had no letters of credit
outstanding at December 31, 1999. At December 31, 1999, $15.1 million was
available to be borrowed under the Loan Agreement.
Management of the Partnership has entered into discussions with a bank
regarding replacement of the Bank One Loan Agreement with a long-term facility.
Based upon these discussions, management expects that it will be able to
replace the Loan Agreement with a long-term facility subject to similar terms.
If the Partnership is unable to complete the replacement agreement noted above,
then other options will be pursued, some of which may have terms not as
favorable to the Partnership, including increasing costs and pledging
additional collateral. While management believes that it will be able to
replace the Loan Agreement on a long-term basis prior to its maturity, there
can be no assurance that it will be able to do so.
Distributions
Generally, GCOLP will distribute 100% of its Available Cash within 45 days
after the end of each quarter to Unitholders of record and to the General
Partner. Available Cash consists generally of all of the cash receipts less
cash disbursements of GCOLP adjusted for net changes to reserves. (A full
definition of Available Cash is set forth in the Partnership Agreement.)
Distributions of Available Cash to the holders of Subordinated OLP Units are
subject to the prior rights of holders of Common Units to receive the minimum
quarterly distribution ("MQD") for each quarter during the subordination period
(which will not end earlier than December 31, 2001) and to receive any
arrearages in the distribution of the MQD on the Common Units for prior quarters
during the subordination period. MQD is $0.50 per unit.
Salomon has committed, subject to certain limitations, to provide total
cash distribution support, with respect to quarters ending on or before December
31, 2001, in an amount up to an aggregate of $17.6 million in exchange for
Additional Partnership Interests ("APIs"). Salomon's obligation to purchase
APIs will end no later than December 31, 2001, with the actual termination
subject to the levels of distributions that have been made prior to the
termination date. In 1999, the Partnership utilized $3.9 million of the
distribution support from Salomon. An additional $2.2 million of distribution
support was utilized in February 2000. After the distribution in February 2000,
$6.1 million of distribution support has been utilized and $11.5 million remains
available through December 31, 2001 or until such amount is fully utilized,
whichever comes first.
APIs purchased by Salomon are not entitled to cash distributions or voting
rights. The APIs will be redeemed if and to the extent that Available Cash for
any future quarter exceeds an amount necessary to distribute the MQD on all
Common Units and Subordinated OLP Units and to eliminate any arrearages in the
MQD on Common Units for prior periods.
In addition, the Partnership Agreement authorizes the General Partner to
cause GCOLP to issue additional limited partner interests and other equity
securities, the proceeds from which could be used to provide additional funds
for acquisitions or other GCOLP needs.
10. Partnership Equity
Partnership equity in GELP consists of the general partner interest of 2% and
8.6 million Common Units representing limited partner interests of 98%. The
Common Units were sold to the public in an initial public offering in December
1996. The general partner interest is held by the General Partner.
GELP has an approximate 80.01% general partner interest in GCOLP. The
remainder of GCOLP is held by Salomon, Howell and the General Partner. These
interests, reflected in the consolidated financial statements as minority
interests, are as follows.
Interest in
GCOLP
-----
Subordinated limited partner interest held by:
Salomon 10.58%
Howell 9.01
General partner interest in GCOLP held by the
General Partner 0.40
-----
Total minority interests 19.99%
=====
The Partnership is managed by the General Partner. Common Units will receive
distributions in liquidation in preference to Subordinated OLP Units. See Note
9 for a discussion regarding distributions.
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Conversion of Subordinated OLP Units
There is no established public market for the Subordinated OLP Units. The
Subordinated OLP Units will convert into common units of GCOLP ("Common OLP
Units") upon the expiration of the subordination period. The subordination
period will not end prior to December 31, 2001 and will only end thereafter if
GCOLP satisfies certain cash distribution and earnings tests. Subordinated OLP
Units that have converted into Common OLP Units will share equally in
distributions of Available Cash with the Common Units.
Once the Subordinated OLP Units have converted into Common OLP Units,
Salomon or Howell may request that these units be redeemed. At such time,
pursuant to a Redemption and Registration Rights Agreement, GELP will use its
reasonable best efforts to sell the number of Common Units equal to the number
of Common OLP Units in GCOLP that are to be redeemed. The proceeds, net of
underwriting discount or placement fees from such sale, will be contributed to
GCOLP and used to redeem such Common OLP Units. GELP is obligated to pay the
expenses incidental to redemption requests, other than underwriting discount or
placement fees. The General Partner will have a proportionate percentage of its
general partner interest in GCOLP redeemed when Common OLP Units are redeemed in
connection with the exercise of the redemption right.
11. Nonrecurring Charge
In the second quarter of 1998, the Partnership shut-in its Main Pass
pipeline. A charge of $373,000 was recorded, consisting of $109,000 of costs
related to the shut-in and a non-cash write-down of the asset of $264,000.
12. Transactions with Related Parties
Sales, purchases and other transactions with affiliated companies, except the
guarantee fees paid to Salomon, in the opinion of management, are conducted
under terms no more or less favorable than those conducted with unaffiliated
parties. Basis was a wholly-owned subsidiary of Salomon until May 1, 1997, when
Basis was sold to Valero Energy Corporation. Basis transferred its 54% interest
in the general partner and its approximately 1.2 million Subordinated OLP Units
to Salomon in conjunction with the sale of Basis.
Sales and Purchases of Crude Oil
A summary of sales to and purchases from related parties of crude oil is as
follows (in thousands).
Year Ended December 31,
--------------------------
1999 1998 1997
------- ------- --------
Sales to affiliates $77,195 $38,718 $443,606
Purchases from affiliates $74,812 $42,814 $183,490
Clearing of Commodities Futures Transactions
The Partnership cleared a portion of its commodity futures transactions on
the NYMEX through Basis Clearing, Inc., a wholly-owned subsidiary of Basis. In
April 1997, Basis Clearing, Inc. ceased its clearing activities for the
Partnership. The Partnership paid commissions to Basis Clearing, Inc. of
$29,000 in 1997.
General and Administrative Services
The Partnership does not directly employ any persons to manage or operate
its business. Those functions are provided by the General Partner. The
Partnership reimburses the General Partner for all direct and indirect costs of
these services. Total costs reimbursed to the General Partner by the
Partnership were $16,687,000, $15,428,000 and $14,973,000 for the years ended
December 31, 1999, 1998 and 1997, respectively.
The Partnership entered into a Corporate Services Agreement with Basis
pursuant to which Basis, directly or through its affiliates, provided certain
administrative and support services for the benefit of the Partnership. Such
services included human resources, tax, accounting, data processing, NYMEX
transaction clearing and other similar administrative services. The Partnership
no longer receives any services under the Corporate Services Agreement. Charges
by Basis under the Corporate Services Agreement during the period in 1997 that
Basis was a related party to the Partnership were approximately $100,000 per
month.
Treasury Services
The Partnership entered into a Treasury Management Agreement with Basis.
Effective May 1, 1997, Salomon replaced Basis as a party to the Treasury
Management Agreement. Under the Treasury Management Agreement, the Partnership
invested excess cash with Salomon and earned interest at market rates. At
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December 31, 1998 and 1997, the Partnership had $9.0 million and $14.0 million
in funds, respectively, deposited with Salomon under the Treasury Management
Agreement. Such amounts have been classified in the consolidated balance sheets
as cash and cash equivalents. For the years ended December 31, 1998 and 1997,
the Partnership earned interest of $288,000 and $833,000, respectively, on the
investments with Salomon. The Treasury Management Agreement has expired.
Credit Facilities
As discussed in Note 9, Salomon provides Credit Facilities to the
Partnership. For the years ended December 31, 1999, 1998 and 1997, the
Partnership paid Salomon $680,000, $578,000 and $730,000, respectively, for
guarantee fees under the Credit Facilities. The Partnership paid Salomon
$18,000 for interest under the Credit Facilities during 1998. The Partnership
paid Basis $85,000 for interest under the Credit Facilities during 1997.
13. Supplemental Cash Flow Information
Cash received by the Partnership for interest for the years ended December
31, 1999, 1998 and 1997 was $152,000, $422,000 and $1,139,000, respectively.
Payments of interest were $1,035,000, $274,000 and $122,000 for the years ended
December 31, 1999, 1998 and 1997, respectively.
14. Employee Benefit Plans
The Partnership does not directly employ any of the persons responsible for
managing or operating the Partnership. Employees of the General Partner provide
those services and are covered by various retirement and other benefit plans.
The General Partner's employees participated in the plans of Basis in 1997.
Beginning in 1998, the General Partner maintained its own plans.
In order to encourage long-term savings and to provide additional funds for
retirement to its employees, the General Partner sponsors a profit-sharing and
retirement savings plan. Under this plan, the General Partner's matching
contribution is calculated as the lesser of 50% of each employee's annual pretax
contribution or 3% of each employee's total compensation. The General Partner
also made a profit-sharing contribution of at least 3% of each eligible
employee's total compensation. The General Partner's costs relating to this
plan were $566,000, $619,000 and $474,000 for the years ended December 31, 1999,
1998 and 1997, respectively.
The General Partner also provided certain health care and survivor benefits
for its active employees. In 1998, these plans were fully-insured. In 1999 and
1997, these benefit programs were self-insured. In 2000, these plans will be
self-insured. The expenses of the General Partner for these benefits were
$1,067,000, $1,338,000 and $1,731,000 in 1999, 1998, 1997, respectively.
The General Partner also adopted two plans in January 1997 and amended these
plans in January 1998. These plans are a restricted unit plan ("Restricted Unit
Plan") for key employees of the General Partner and the Genesis Incentive
Compensation Plan ("Incentive Plan").
Restricted Unit Plan
In January 1997, the General Partner adopted a restricted unit plan for key
employees of the General Partner that provided for the award of rights to
receive Common Units under certain restrictions, including meeting thresholds
tied to Available Cash and Adjusted Operating Surplus. Initially, rights to
receive 291,000 Common Units were available under the restricted unit plan with
rights to receive 194,000 Common Units allocated to approximately 30
individuals. The restricted units would vest upon the conversion of
Subordinated OLP Units to Common OLP Units. In the event of early conversion of
a portion of the Subordinated OLP Units into Common OLP Units, the restricted
units would vest in the same proportion. The Partnership recorded no
compensation expense related to the restricted unit plan in 1997 due to
uncertainty as to whether the necessary vesting conditions would be met.
Likewise, the restricted units were not considered in diluted net income per
common unit in 1997 as none of the vesting conditions had been met in any
period.
In January 1998, the restricted unit plan was amended and restated, and the
thresholds tied to Available Cash and Adjusted Operating Surplus were
eliminated. The discussion that follows is based on the terms of the Amended
and Restated Restricted Unit Plan (the "Restricted Unit Plan"). Initially,
rights to receive 291,000 Common Units are available under the Restricted Unit
Plan. From these Units, rights to receive 240,000 Common Units (the "Restricted
Units") have been allocated to approximately 32 individuals, subject to the
vesting conditions described below and subject to other customary terms and
conditions. The remaining rights to receive 51,000
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Common Units initially available under the Restricted Unit Plan may be
allocated or issued in the future to key employees on such terms and
conditions (including vesting conditions) as the Compensation Committee of
the General Partner ("Compensation Committee") shall determine.
Upon "vesting" in accordance with the terms and conditions of the
Restricted Unit Plan, Common Units allocated to a plan participant will be
issued to such participant. Units issued to participants may be newly issued
Units acquired by the General Partner from the Partnership at then
prevailing market prices or may be acquired by the General Partner in the open
market. In 1998, one-third of the Restricted Units allocated to each individual
vested and the units issued were acquired on the open market. In either case,
the associated expense will be borne by the Partnership. Until Common Units
have vested and have been issued to a participant, such participant shall not be
entitled to any distributions or allocations of income or loss and shall not
have any voting or other rights in respect of such Common Units. The
participant shall receive cash awards based on the number of non-vested units
held by such participant to the extent that distributions are paid on
Subordinated OLP Units. To date, no distributions have been paid with respect
to Subordinated OLP Units. No consideration will be payable by the participants
in the Restricted Unit Plan upon vesting and issuance of the Common Units.
Additionally, the participant cannot sell the Common Units until one year after
the date of vesting.
Termination without cause in violation of a written employment agreement,
or a Significant Event as defined in the Restricted Unit Plan, will result in
immediate vesting of all non-vested units and conversion to Common Units without
any restrictions.
In 1999 and 1998, the Partnership recorded expense of $1,459,000 and
$1,617,000, respectively, related to the Restricted Units.
Incentive Plan
The Incentive Plan is designed to enhance the financial performance of the
Partnership by rewarding the executive officers and other specific key employees
for achieving annual financial performance objectives. The Incentive Plan will
be administered by the Compensation Committee. Individual participants and
payments, if any, for each calendar year will be determined by and in the
discretion of the Compensation Committee. No incentive payment will be made
with respect to any year unless (i) the aggregate MQD in the Incentive Plan year
has been distributed to each holder of Common Units, plus any arrearage thereon,
(ii) the Adjusted Operating Surplus generated during such year has equaled or
exceeded the sum of the MQD on all of the outstanding Common Units and the
related distribution on the General Partner's interest during such year and
(iii) no APIs are outstanding. In addition, incentive payments will not exceed
$375,000 with respect to any year unless (i) each holder of Subordinated OLP
Units has also received the aggregate MQD and (ii) the Adjusted Operating
Surplus generated during such year exceed the sum of the MQD on all of the
outstanding Common Units and Subordinated OLP Units and the related distribution
on the General Partner's interest during such year. Any incentive payments will
be at the discretion of the Compensation Committee, and the General Partner will
be able to amend or change the Incentive Plan at any time. No incentive
payments have been made under the Incentive Plan, although the Compensation
Committee has awarded performance bonuses.
15. Market Risk
The Partnership's market risk in the purchase and sale of its crude oil
contracts is the potential loss that can be caused by a change in the market
value of the asset or commitment. In order to hedge its exposure to such market
fluctuations, the Partnership enters into various financial contracts, including
futures, options and swaps. Normally, any contracts used to hedge market risk
are less than one year in duration. Changes in the market value of these
transactions are deferred until the gain or loss is recognized on the hedged
transaction, at which time such gains and losses are recognized through crude
costs.
16. Concentration and Credit Risk
The Partnership derives its revenues from customers primarily in the crude
oil industry. This industry concentration has the potential to impact the
Partnership's overall exposure to credit risk, either positively or negatively,
in that the Partnership's customers could be affected by similar changes in
economic, industry or other conditions. However, the Partnership believes that
the credit risk posed by this industry concentration is offset by the
creditworthiness of the Partnership's customer base. The Partnership's
portfolio of accounts receivable is comprised primarily of major international
corporate entities with stable payment experience. The credit risk
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related to contracts which are traded on the New York Mercantile Exchange
(NYMEX) is limited due to the daily cash settlement procedures and other
NYMEX requirements.
The Partnership has established various procedures to manage its credit
exposure, including initial credit approvals, credit limits, collateral
requirements and rights of offset. Letters of credit, prepayments and
guarantees are also utilized to limit credit risk to ensure that management's
established credit criteria are met.
17. Fair Value of Financial Instruments
The carrying values of cash and cash equivalents, accounts receivable,
accounts payable and accrued liabilities in the Consolidated Balance Sheets
approximated fair value due to the short maturity of these instruments.
Additionally, the carrying value of the long-term debt approximated fair value
due to its floating rate of interest.
Estimated fair values of option contracts used as hedges and the net gains
and losses, both recognized and deferred, arising from hedging activities at
December 31, 1999, 1998 and 1997 are as follows (in thousands).
1999 1998 1997
----------------------- ----------------------- -----------------------
Net Net Net
Carrying Fair Gains Carrying Fair Gains Carrying Fair Gains
Amount Value (Losses) Amount Value (Losses) Amount Value (Losses)
-------- ----- -------- -------- ----- -------- -------- ----- --------
Option contracts written $390 $390 $ - $ - $ - $ - $1,356 $803 $553
Quoted market prices are used in determining the fair value of the option
contracts. If quoted prices are not available, fair values are estimated on the
basis of pricing models or quoted prices for contracts with similar
characteristics. Judgment is required in interpreting market data and the use
of different market assumptions or estimation methodologies may affect the
estimated fair value amounts.
18. Commitments and Contingencies
The Partnership uses surface, vehicle and office leases in the course of its
business operations. The Partnership also leases a segment of pipeline and four
tanks for use in its pipeline operations. The future minimum rental payments
under all noncancelable operating leases as of December 31, 1999, were as
follows (in thousands).
2000 $1,051
2001 776
2002 672
2003 481
2004 513
2005 and thereafter 448
------
Total minimum lease obligations $3,941
======
Total operating lease expense was as follows (in thousands).
Year ended December 31, 1999 $1,674
Year ended December 31, 1998 $1,921
Year ended December 31, 1997 $1,060
The Partnership has contractual commitments (primarily forward contracts)
arising in the ordinary course of business. At December 31, 1999, the
Partnership had commitments to purchase 17,222,000 barrels of crude oil at fixed
prices ranging from $14.87 to $27.20 per barrel extending to January 2001, and
commitments to sell 17,495,000 barrels of crude oil at fixed prices ranging from
$14.60 to $27.25 per barrel extending to February 2001. Additionally, the
Partnership had commitments to purchase 28,514,000 barrels of crude oil
extending to February 2001, and commitments to sell 13,268,000 barrels of crude
oil extending to June 2000, both associated with market-price related contracts.
The Partnership is subject to various environmental laws and regulations.
Policies and procedures are in place to monitor compliance. The Partnership's
management has made an assessment of its potential environmental exposure and
determined that such exposure is not material to its consolidated financial
position, results of operations or cash flows. As part of the formation of the
Partnership, Basis and Howell agreed to be responsible for certain environmental
conditions related to their ownership and operation of their respective assets
contributed to
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the Partnership and for any environmental liabilities which Basis
or Howell may have assumed from prior owners of these assets.
The Partnership is subject to lawsuits in the normal course of business and
examinations by tax and other regulatory authorities. Such matters presently
pending are not expected to have a material adverse effect on the financial
position, results of operations or cash flows of the Partnership.
As part of the formation of the Partnership, Basis and Howell agreed to each
retain liability and responsibility for the defense of any future lawsuits
arising out of activities conducted by Basis and Howell prior to the formation
of the Partnership and have also agreed to cooperate in the defense of such
lawsuits.
Pipeline Oil Spill
On December 20, 1999, the Partnership had a spill of crude oil from its
Mississippi System. Approximately 8,000 barrels of oil spilled from the
pipeline near Summerland, Mississippi and entered a creek nearby. The oil then
flowed into the Leaf River.
The Partnership responded to this incident immediately, deploying crews to
evaluate, clean up and monitor the spilled oil. At February 1, 2000, the spill
had been substantially cleaned up, with ongoing maintenance and reduced clean-up
activity expected to continue for several more months.
The estimated cost of the spill clean-up is expected to be $17 million. A
final determination as to the cause of the spill has not been completed. The
incident was reported to insurers, and incurred costs related to the clean-up
efforts have been reimbursed or approved for reimbursement by the insurers.
The insurers, however, have reserved the right to claim the return of the
insurance proceeds should the final determination of cause be a cause not
covered by the insurance policies. Based on its review of the policies
and its understanding of the facts associated with the spill, management of
the General Partner believes that the costs of the spill are covered by
insurance and collection of the receivable is probable.
In its 1999 financial statements, the Partnership charged to expense the
deductible of $50,000, recorded a liability for the $17 million of estimated
clean-up costs and recorded a receivable from the insurance company for the
insurance proceeds. Should the ultimate determination of the cause of the
spill proves not to be covered by insurance, the Partnership will be required
to write off the receivable of $17 million.
As a result of this crude oil spill, certain federal and state regulatory
agencies may impose fines and penalties that would not be reimbursed by
insurance. At this time, it is not possible to predict whether the Partnership
will be fined, the amounts of such fines, or whether such governmental agencies
would prevail in imposing such fines.
The segment of the Mississippi System where the spill occurred has been
temporarily shut down and will not be returned to service until regulators give
their approval. Regulatory authorities may require specific testing or changes
to the pipeline before allowing the Partnership to restart that segment of the
system. At this time, it is unknown whether there will be any required testing
or changes and the related cost of that testing or changes.
If the costs of testing or changes are too high, that segment of the
system may not be restarted. If this part of the Mississippi System is taken
out of service, annual tariff revenues would be reduced by approximately $0.6
million and the net book value of that portion of the pipeline would be
written down to its net realizable value, resulting in a non-cash write-off
of approximately $6.0 million.
19. Subsequent Event
On February 28, 2000, Howell sold its 46% interest in the General Partner to
Salomon, resulting in Salomon owning 100% of the General Partner.
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