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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, 2000
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
------------------- ---------------------
Common Units American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
----- -----
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
X
-------
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 American Stock Exchange on March 1, 2001, was approximately $46 million.
At March 1, 2001, 8,623,916 Common Units were outstanding.
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GENESIS ENERGY, L.P.
2000 FORM 10-K ANNUAL REPORT
Table of Contents
Page
Part I ----
Item 1. Business 3
Item 2. Properties 10
Item 3. Legal Proceedings 10
Item 4. Submission of Matters to a Vote of Security Holders 11
Part II
Item 5. Market for Registrant's Common Units and Related Security
Holder Matters 12
Item 6. Selected Financial Data 13
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations 14
Item 7a. Quantitative and Qualitative Disclosures about Market Risk 23
Item 8. Financial Statements and Supplementary Data 23
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 23
Part III
Item 10. Directors and Executive Officers of the Registrant 24
Item 11. Executive Compensation 25
Item 12. Security Ownership of Certain Beneficial Owners and Management 29
Item 13. Certain Relationships and Related Transactions 29
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 30
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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 an independent gatherer and
marketer
of crude oil. 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 73 leased 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 2000, Genesis purchased an average of approximately
96,000 barrels per day of crude oil at the wellhead.
Genesis currently transports a total of approximately 84,000 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 1.4 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. Until
December 7, 2000, Salomon owned 1,163,700 subordinated limited partner units in
GCOLP, representing 10.58% of GCOLP, and Howell owned 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.
On December 7, 2000, the unitholders of Genesis approved a restructuring of the
Partnership. As a result of this approval, the GCOLP partnership agreement was
amended to:
* reduce the minimum quarterly distribution on Common Units from the
previous $0.50 to the new $0.20 per unit;
* reduce correspondingly the respective per unit dollar distribution
thresholds that must be achieved before the General Partner is entitled
to incentive compensation payments from the prior threshold levels of
$0.55, $0.635 and $0.825 per unit to the new levels of $0.25, $0.28 and
$0.33 per unit;
* eliminate all of the Subordinated OLP Units in GCOLP, and as a result,
provide that the Common Units will no longer accrue arrearages if the
minimum quarterly distribution is not paid in full in any quarter; and
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* eliminate, without payment of any consideration, all of the outstanding
additional partnership interests, or APIs, issued to Salomon in exchange
for its distribution support and, as a result, eliminate the
Partnership's obligation to redeem the APIs issued to Salomon.
Additionally, as a result of the approval of the restructuring:
* Salomon contributed to GCOLP in cash the remaining distribution support
of $3.8 million. After payment of $1.4 million of transaction costs
associated with the restructuring, a special distribution of the
remaining cash of $2.4 million, or $0.28 per Common Unit, was paid on
December 28, 2000, to Common Unitholders of record on December 18, 2000;
and
* Salomon extended the expiration date of its $300 million credit support
obligation to GCOLP from March 31, 2001, to December 31, 2001, under its
current terms and conditions.
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.
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
5
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 800 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
2000, with its staff of division order specialists, Genesis distributed payments
to approximately 22,000 interest owners.
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,
2001, 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 8 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. Genesis has not experienced
any nonpayments or nonperformance by its customers in 2000.
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 800 producers. In 2000, approximately 31% of
the leasehold barrels were purchased from ten producers.
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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, 2000, 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 are represented by labor
unions, and the General Partner believes that the relationships with the
employees are good.
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
7
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 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. The Partnership has not
made
any claims on Salomon or Howell under these environmental provisions.
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. A portion of 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. The spill was cleaned up, with
ongoing monitoring and reduced clean-up activity expected to continue for an
undetermined period of time. The oil spill is covered by insurance and the
financial impact to the Partnership for the cost of the clean-up has not been
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 19 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. The
Partnership plans in 2001 to perform testing of the affected segment of the
pipeline at an estimated cost of $0.2 million to determine a course of action to
restart the system. 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. Subject to the results of
testing and regulatory approval, the Partnership intends to restart this segment
of the Mississippi System during the latter half of 2001.
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
8
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", limiting 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 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 to 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.
9
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 have been 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
of
its pipeline systems. Significant expenses could be 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 leased 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, maintaining 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.
10
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 may be 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 management of the General Partner believes that its expectations
regarding future events are based on reasonable assumptions, no assurance can be
made that the Partnership's goals will be achieved or that expectations
regarding
future developments will prove to be correct. Important factors that could
cause
actual results to differ materially from the expectations reflected in the
forward looking statements herein include, but are not limited to, the
following:
* changes in regulations;
* the Partnership's success in obtaining additional lease barrels;
* changes in crude oil production volumes (both world-wide and 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 risk management activities;
* credit requirements by the counterparties;
* the Partnership's ability to replace the credit support from Salomon
with a bank facility and to replace the working capital facility with
BNP Paribas with another facility;
* the Partnership's ability in the future to generate sufficient amounts
of Available Cash to permit the distribution to unitholders at least the
minimum quarterly distribution;
* any requirements for testing or changes in the Mississippi pipeline
system as a result of the oil spill that occurred there in December
1999;
* any fines and penalties federal and state regulatory agencies may impose
in connection with the oil spill that would not be reimbursed by
insurance;
* results of current or threatened litigation; and
* conditions of capital markets and equity markets during the periods
covered by the forward looking statements.
All subsequent written or oral forward looking statements attributable to
the Partnership, or persons acting on the Partnership's behalf, are expressly
qualified in their entirety by the foregoing cautionary 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 1.4 million barrels of storage capacity
associated with the pipelines. These storage capacities include approximately
0.4 million barrels each on the Mississippi and Jay Systems and 1.0 million
barrels on the Texas System, primarily at the Satsuma terminal in Houston,
Texas.
In addition to transporting crude oil by pipeline, the Partnership transports
crude oil through a fleet of leased tractors and trailers. At December 31,
2000,
the trucking fleet consisted of approximately 73 tractor-trailers. The trucking
fleet generally hauls the crude oil to one of the approximately 110 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, is not expected
to have a material adverse effect on the financial condition or results of
operations of the Partnership. See Note 19 of Notes to Consolidated Financial
Statements.
11
Item 4. Submission of Matters to a Vote of Security Holders
During the year ended December 31, 2000, Company Unitholders were asked to
approve a proposal to restructure the Partnership. A proxy statement was mailed
on October 23, 2000, to Common Unitholders of record on October 18, 2000.
On December 7, 2000, the unitholders of Genesis approved a restructuring of
the Partnership. As a result of this approval, the GCOLP partnership agreement
was amended to:
* reduce the minimum quarterly distribution on Common Units from the
previous $0.50 to the new $0.20 per unit;
* reduce correspondingly the respective per unit dollar distribution
thresholds that must be achieved before the General Partner is entitled
to incentive compensation payments from the prior threshold levels of
$0.55, $0.635 and $0.825 per unit to the new levels of $0.25, $0.28 and
$0.33 per unit;
* eliminate all of the Subordinated OLP Units in GCOLP, and as a result,
provide that the Common Units will no longer accrue arrearages if the
minimum quarterly distribution is not paid in full in any quarter; and
* eliminate, without payment of any consideration, all of the outstanding
additional partnership interests, or APIs, issued to Salomon in exchange
for its distribution support and, as a result, eliminate the
Partnership's obligation to redeem the APIs issued to Salomon.
Additionally, as a result of the approval of the restructuring:
* Salomon contributed to GCOLP in cash the remaining distribution support
of $3.8 million. After payment of $1.4 million of transaction costs
associated with the restructuring, a special distribution of the
remaining cash of $2.4 million, or $0.28 per Common Unit, was paid on
December 28, 2000, to Common Unitholders of record on December 18, 2000;
and
* Salomon extended the expiration date of its $300 million credit support
obligation to GCOLP from March 31, 2001, to December 31, 2001, under its
current terms and conditions.
12
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
-------- -------- ------------------
2000
- ----
First Quarter $10.5625 $ 7.5000 $0.50
Second Quarter $ 9.8750 $ 4.8750 $0.50
Third Quarter $ 8.0000 $ 5.6875 $0.50
Fourth Quarter $ 7.0000 $ 3.2500 $0.78
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
- --------------------
Cash distributions are shown in the quarter paid and are based on the
prior
quarter's activities.
Includes a special distribution of $0.28 per unit paid in conjunction with
the restructuring of the Partnership that was approved by Common Unitholders on
December 7, 2000.
At December 31, 2000, there were 8,623,916 Common Units outstanding. As of
December 31, 2000, there were approximately 12,000 record holders and beneficial
owners (held in street name) of the Partnership's Common 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.
In the fourth quarter of 2000, the Partnership was restructured pursuant to a
vote of the Common Unitholders. As a result of this restructuring, the Minimum
Quarterly Distribution ("MQD") was reduced from $0.50 per Common Unit to $0.20
per Common Unit beginning with the distribution for the fourth quarter of 2000,
which was paid on February 14, 2001.
Until February 1, 2001, the Common Units of Genesis were traded on the New York
Stock Exchange ("NYSE"). In December 2000, the Partnership was notified that it
failed to meet the NYSE's continued listing requirements and that the NYSE was
commencing delisting procedures. Management of the General Partner submitted a
plan to the NYSE to cure the continued listing deficiencies. However,
management
later concluded that it would be preferable to list the Partnership's Common
Units on the American Stock Exchange ("AMEX"). On January 31, 2001, the
Partnership's Common Units ceased to be listed on the NYSE and, on February 1,
2001, began being listed on the AMEX. The Common Units of the General Partner
are still traded under the symbol GEL.
13
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, 2000, 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
Year Ended December 31,
Ended Ended
------------------------------------------
- ---------------- December 31, November 30,
2000 1999 1998
1997 1996 1996 1996
---------- ---------- ---------- ------
- ---- ---------- -------- ----------
(Pro forma) (Predecessor)
(Unaudited)
Income Statement Data:
Revenues:
Gathering & marketing revenues $4,309,614 $2,144,646 $2,216,942
$3,354,939 $4,565,834 $370,559 $3,598,107
Pipeline revenues 14,940 16,366 16,533
17,989 16,780 1,426 -
---------- ---------- ---------- ------
- ---- ---------- -------- ----------
Total revenues 4,324,554 2,161,012 2,233,475
3,372,928 4,582,614 371,985 3,598,107
Cost of sales:
Crude cost 4,281,567 2,118,318 2,184,529
3,331,184 4,526,363 366,723 3,573,086
Field operating costs 13,673 11,669 12,778
12,107 15,092 1,290 6,744
Pipeline operating costs 8,652 8,161 7,971
6,016 4,978 463 -
---------- ---------- ---------- ------
- ---- ---------- -------- ----------
Total cost of sales 4,303,892 2,138,148 2,205,278
3,349,307 4,546,433 368,476 3,579,830
---------- ---------- ---------- ------
- ---- ---------- -------- ----------
Gross margin 20,662 22,864 28,197
23,621 36,181 3,509 18,277
General and administrative expenses 10,942 11,649 11,468
8,557 9,470 1,363 3,316
Depreciation and amortization 8,032 8,220 7,719
6,300 6,834 518 1,396
Nonrecurring charge 1,387 - 373
- - - - -
---------- ---------- ---------- ------
- ---- ---------- -------- ----------
Operating income 301 2,995 8,637
8,764 19,877 1,628 13,565
Interest income (expense), net (1,010) (929) 154
1,063 56 56 294
Other income (expense) 1,148 849 28
21 (74) - (83)
---------- ---------- ---------- ------
- ---- ---------- -------- ----------
Net income before minority interests 439 2,915 8,819
9,848 19,859 1,684 13,776
Minority interests 258 583 1,763
1,968 3,970 337 -
---------- ---------- ---------- ------
- ---- ---------- -------- ----------
Net income $ 181 $ 2,332 $ 7,056 $
7,880 $ 15,889 $ 1,347 $ 13,776
========== ========== ==========
========== ========== ======== ==========
Net income per common unit-basic
and diluted $ 0.02 $ 0.27 $ 0.80 $
0.90 $ 1.81 $ 0.15 N/A
========== ========== ==========
========== ========== ======== ==========
Balance Sheet Data (at end of period):
Current assets $ 350,604 $ 274,717 $ 185,216 $
232,202 $ 410,371 $410,371 N/A
Total assets 449,343 380,592 297,173
331,114 509,900 509,900 N/A
Long-term liabilities - 3,900 15,800
- - - - N/A
Minority interests 520 30,571 29,988
28,225 26,257 26,257 N/A
Partners' capital 82,615 53,585 67,871
78,351 85,080 85,080 N/A
Other Data:
Maintenance capital expenditures $ 1,685 $ 1,682 $ 1,509 $
3,785 $ 2,535 $ 106 $ 1,100
EBITDA $9,481 $ 12,064 $ 16,384 $
15,085 $ 26,637 $ 2,146 $ 14,878
Volumes (bpd):
Gathering and marketing:
Wellhead 99,602 93,397 114,400
104,506 116,263 120,553 83,239
Bulk and exchange 297,776 242,992 325,468
346,760 463,054 380,354 417,939
Pipeline 86,458 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).
14
The table below summarizes the Partnership's quarterly financial data for 2000
and 1999 (in thousands, except per unit data).
2000 Quarters
-------------------------------------------------
First Second Third Fourth
---------- ---------- ---------- ----------
Revenues $1,001,843 $1,194,896 $1,093,032 $1,034,783
Gross margin $ 4,299 $ 5,042 $ 6,904 $ 4,417
Operating income (loss) $ (403) $ (287) $ 2,071 $ (1,654)
Net income (loss) $ (581) $ 10 $ 1,520 $ (768)
Net income (loss) per
Common Unit-basic and
diluted $ (0.07) $ 0.00 $ 0.17 $ (0.09)
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
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,
------------------------------------
2000 1999 1998
---------- ---------- ----------
Revenues
Gathering & marketing $4,309,614 $2,144,646 $2,216,942
Pipeline $ 14,940 $ 16,366 $ 16,533
Gross margin
Gathering & marketing $ 14,374 $ 14,659 $ 19,635
Pipeline $ 6,288 $ 8,205 $ 8,562
General and administrative expenses $ 10,942 $ 11,649 $ 11,468
Depreciation and amortization $ 8,032 $ 8,220 $ 7,719
Nonrecurring charges $ 1,387 $ - $ 373
Operating income $ 301 $ 2,995 $ 8,637
Interest income (expense), net $ (1,010) $ (929) $ 154
Net gain on disposal of surplus assets $ 1,148 $ 849 $ 28
The profitability of Genesis depends to a significant extent upon its
ability to maximize gross margin. Gross margins from gathering and marketing
operations are a function of volumes purchased and 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.
The
absolute price levels for crude oil do not necessarily bear a relationship to
gross margin as absolute price levels normally impact revenues and cost of sales
by equivalent amounts. 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.
15
In our gathering and marketing business, we seek to purchase and sell crude
oil at points along the Distribution Chain where we can achieve positive gross
margins. We generally purchase crude oil at prevailing prices from producers at
the wellhead under short-term contracts. We then transport the crude along the
Distribution Chain for sale to or exchange with customers. In addition to
purchasing crude at the wellhead, Genesis purchases crude oil in bulk at major
pipeline terminal points and enters into exchange transactions with third
parties. We generally enter into exchange transactions only when the cost of
the
exchange is less than the alternate cost we would incur in transporting or
storing the crude oil. In addition, we often exchange one grade of crude oil
for
another to maximize our margins or meet our contract delivery requirements.
These bulk and exchange transactions are characterized by large volumes and
narrow profit margins on purchases and sales.
Generally, as we purchase crude oil, we simultaneously establish 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 NYMEX. Through these transactions, we
seek 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 our policy not to hold crude oil, futures contracts or other
derivative products for the purpose of speculating on crude oil price changes.
Pipeline revenues and gross margins are 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.
Year Ended December 31, 2000 Compared with Year Ended December 31, 1999
Gross Margin. Gathering and marketing gross margins decreased $0.3
million or 2% to $14.4 million for the year ended December 31, 2000, as compared
to $14.7 million for the year ended December 31, 1999. During 2000, the
Partnership recognized an unrealized loss on written option contracts of $0.6
million. This loss, when combined with several other factors, netted the
decrease of $0.3 million.
The other factors affecting gross margin were:
* an increase of 18 percent in wellhead, bulk and exchange purchase
volumes between 1999 and 2000, resulting in an increase in gross margin of
$5.0 million;
* a 5 percent decline in the average difference between the price of
crude oil at the point of purchase and the price of crude oil at the point
of sale, which reduced gross margin by $1.6 million;
* an increase of $1.1 million in credit costs due to the increase in
purchase volumes and a 57 percent increase in the average absolute price
level of crude oil; and
* an increase of $2.0 million in field operating costs, primarily from a
$0.7 million increase in payroll and benefits costs, $0.7 million increase
in fuel costs, and $0.6 million increase in rental costs due to the
replacement of the tractor/trailer fleet with a leased fleet in the fourth
quarter of 2000. The increased payroll-related costs and fuel costs can
be attributed to an approximate 16% increase in the number of barrels
transported by the Partnership in trucks.
Pipeline gross margin decreased $1.9 million or 23% to $6.3 million for
the year ended December 31, 2000, as compared to $8.2 million for the year ended
December 31, 1999. Pipeline revenues declined $2.7 million as a result of
declines in throughput and average tariffs. Throughput declined 8 percent
between the two years, resulting in a revenue decrease of $1.4 million. The
average tariff collected on shipments was down 10%, resulting in a revenue
decrease of $1.3 million. Revenues from sales of pipeline loss allowance
barrels
increased $1.3 million as a result of an increase in the amount of pipeline loss
allowance that the Partnership is allowed to collect under the terms of its
tariffs and higher crude prices. Pipeline operating costs were $0.5 million
higher in the 2000 period primarily due to $0.3 million of increased
expenditures
in areas of spill prevention and employee benefits.
General and administrative expenses. General and administrative expenses
decreased $0.7 million in 2000 from the 1999 level. In 1999, the Partnership
incurred $0.4 million of costs related to Year 2000 remediation. No such costs
were incurred in 2000. Additionally, in 2000, the Partnership's costs for
professional services and contract labor declined $0.2 million.
16
Depreciation and amortization. Depreciation and amortization expense
decreased $0.2 million in 2000 from the 1999 level. This decrease is primarily
attributable to a portion of the Partnership's assets becoming fully depreciated
in 2000, as well as asset sales in the latter part of 2000.
Non-recurring charge. In 2000, the Partnership, after approval by the
Common Unitholders, was restructured as discussed below in "Partnership
Restructuring". The costs associated with this restructuring were charged to
expense. These costs, totaling $1.4 million, consisted primarily of legal and
accounting fees, financial advisor fees, proxy solicitation expenses and the
costs to print and mail a proxy statement to Common Unitholders. The payment of
these restructuring costs did not affect Available Cash for distributions as
cash
provided by Salomon under the Distribution Support Agreement was used to fund
these costs.
Interest income (expense), net. In 2000, the Partnership had an increase
in its net interest expense of $0.1 million. Interest expense increased $0.2
million and interest income increased $0.1 million. The increase in interest
expense resulted from higher interest rates, offset by lower average debt
outstanding. The average interest rate increased 1.93%, resulting in an
increase
of $0.2 million of interest, while the average debt outstanding declined by $2.0
million, resulting in a decrease in interest expense of $0.1 million. Interest
income increased primarily as a result of an increase in interest earned on
margin deposits with NYMEX brokers due to higher average balances. The higher
balances were required due to increased volatility of crude oil prices in the
futures market during 2000.
Net gain on disposal of surplus assets. In 2000, management of the
General Partner made the decision to lease its tractor/trailer fleet from Ryder
Transportation Services. The existing fleet was sold, resulting in cash
proceeds
of $1.8 million and a net gain of $1.0 million. The Partnership sold additional
surplus assets, which resulted in proceeds of $0.1 million and a gain of $0.1
million.
In 1999, the Partnership sold surplus trailers, receiving cash proceeds of
$1.0 million that resulted in a gain of $0.9 million.
As a result of the change to a lease of the fleet in the fourth quarter of
2000, the Partnership expects field operating costs to increase in 2001 for
rental charges. This increase should be partially offset by a reduction in
repairs and greater fuel efficiency.
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 barrels per day. The Partnership increased
wellhead
volumes during the second half of 1999 primarily by obtaining existing
production
by paying higher prices for the production than the previous purchaser.
Increased volumes obtained through competition based on price for existing
production generally result in incrementally lower margins per barrel. Wellhead
purchases increased to 92,000 barrels per day during the third quarter and to
99,000 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. The
changes
implemented were a review of tractor and
17
trailer utilization and realignment of the locations of equipment, allowing
Genesis to sell excess equipment and reduce personnel and operating costs
related
to the vehicles. Field operating costs decreased in total by $1.1 million, with
the reductions in the number of drivers and supervisory personnel decreasing
payroll and benefits by $0.9 million. Disposals of excess tractors and trailers
reduced fuel and repair costs by $0.2 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 of approximately $0.1 million and the costs associated with the spill
the
Partnership had from its Mississippi System in December 1999 of approximately
$0.1 million.
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 decreases
of less than $0.1 million each in travel and entertainment expenses and expense
related to the restricted unit plan due to employee resignations.
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.
Nonrecurring charge. In 1998, the Partnership recorded a nonrecurring
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 cash related to the
shut-in and a $0.3 million write-down of the asset.
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 interest rates, as evidenced by the prime rate, rose during 1999 by
0.75%,
also increasing the Partnership's interest costs.
Net gain on disposal of surplus assets. In 1999, the Partnership
recognized a gain of $0.9 million as a result of the sale of excess tractors and
trailers.
Hedging Activities
Genesis routinely utilizes forward contracts, swaps, options and futures
contracts in an effort to minimize the impact of market fluctuations on
inventories and contractual commitments. Gains and losses on forward contracts,
swaps and futures contracts used to hedge future contract purchases of unpriced
crude oil, where firm commitments to sell are required prior to establishment of
the purchase price, are deferred until the margin from the underlying risk
element of the hedged item is recognized. The Partnership recognized a net loss
of $1.5 million for the year ended December 31, 2000. The Partnership
recognized
net gains of $0.7 million and $1.4 million for the years ended December 31, 1999
and 1998, respectively, related to its hedging activity.
Partnership Restructuring
On October 23, 2000, a proxy statement was mailed to Common Unitholders of
record on October 18, 2000. This proxy statement requested that the Common
Unitholders vote on a proposed restructuring of the Partnership at a meeting of
unitholders held on December 7, 2000. On December 7, 2000, the unitholders of
Genesis approved a restructuring of the Partnership. As a result of this
approval, the GCOLP partnership agreement was amended to:
* reduce the minimum quarterly distribution on Common Units from the
previous $0.50 to the new $0.20 per unit;
18
* reduce correspondingly the respective per unit dollar distribution
thresholds that must be achieved before the General Partner is entitled to
incentive compensation payments from the prior threshold levels of $0.55,
$0.635 and $0.825 per unit to the new levels of $0.25, $0.28 and $0.33 per
unit;
* eliminate all of the Subordinated OLP Units in GCOLP, and as a result,
provide that the Common Units will no longer accrue arrearages if the
minimum quarterly distribution is not paid in full in any quarter; and
* eliminate, without payment of any consideration, all of the outstanding
additional partnership interests, or APIs, issued to Salomon in exchange for
its distribution support and, as a result, eliminate the Partnership's
obligation to redeem the APIs issued to Salomon.
Additionally, as a result of the approval of the restructuring:
* Salomon contributed to GCOLP in cash the remaining distribution support
of $3.8 million. After payment of $1.4 million of transaction costs
associated with the restructuring, a special distribution of the remaining
cash of $2.4 million, or $0.28 per Common Unit, was paid on December 28,
2000, to Common Unitholders of record on December 18, 2000; and
* Salomon extended the expiration date of its $300 million credit support
obligation to GCOLP from March 31, 2001, to December 31, 2001, under its
current terms and conditions.
Liquidity and Capital Resources
Cash Flows
Net cash provided by operations was $4.4 million for the year ended
December 31, 2000 as compared to $10.1 million for the year ended December 31,
1999. The decrease in cash flow in 2000 was due primarily to the reduction in
the Partnership's gross margin of $2.2 million offset by the cash premiums
collected on the sale of written call options related to 2001. This cash,
totaling $7.3 million, increased accrued liabilities at December 31, 2000, and
will be recognized into income as the option periods expire.
Net cash provided by investing activities was $0.3 million for the year
ended December 31, 2000, and net cash used in investing activities was $1.3
million for the year ended December 31, 1999. In 2000, the Partnership received
cash totaling $1.9 million from the sale of its tractor/trailer fleet and other
surplus assets. The Partnership expended $1.7 million on property additions,
primarily in its pipeline operations. In 1999, the Partnership expended $2.7
million on property additions and received $1.0 million from the sale of excess
trucking equipment.
Net cash used in financing activities was $5.8 million and $9.8 million
for the years ended December 31, 2000 and 1999, respectively. In 2000, the
Partnership paid regular quarterly distributions to Common Unitholders and the
General Partner totaling $17.6 million and a special distribution to Common
Unitholders in December 2000 totaling $2.4 million. The special distribution
was
paid pursuant to the restructuring discussed above. The Partnership received
$13.7 million of Distribution Support from Salomon in 2000 of which 1.4 million
was used to pay restructuring costs. In 1999, 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 in 2000 and 1999 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 $2.1 million and $4.1 million under the loan
agreement in 2000 and 1999, respectively.
Capital Expenditures
In 2000, the Partnership expended $1.7 million for maintenance capital
expenditures. The majority of these maintenance capital expenditures related to
pipeline operations.
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
19
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.
The Partnership has no material commitments for capital expenditures for
2001; however, the Partnership does plan to perform testing of the out-of-
service
segment of its Mississippi System. Until testing is completed and approval is
obtained from regulators, an estimate of the amount of expenditures needed to
put
the segment back in service cannot be made.
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, 2001
(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. In 2000, the fee was 0.50% for the first half of the
year and 0.75% for the remainder of the year. For 2001, the fee is 0.75%. The
Partnership will pay an additional fee of 1% on any guaranty utilization in
excess of the $300 million commitment. In May and June, 2000, the Partnership
exceeded the $300 million commitment and, as a result, paid Salomon $0.1 million
for the excess utilization. Guaranty fees, including excess utilization fees,
paid for the years ended December 31, 2000, 1999 and 1998 were $1.7 million,
$0.6
million and $0.7 million, respectively.
At December 31, 2000, the aggregate amount of obligations covered by
guarantees was $258 million, including $127 million in payable obligations and
$131 million in estimated crude oil purchase obligations for January 2001.
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 with Bank One, Texas, N.A. That
agreement was replaced with a secured revolving credit facility ("Credit
Agreement") with BNP Paribas in June 2000. The Credit Agreement provides for
loans or letters of credit in the aggregate not to exceed the lesser of $25
million or the Borrowing Base (as defined in the Credit Agreement). If BNP
Paribas obtains loan commitments for an additional $10 million, the amount
available under the Credit Agreement would increase to $35 million. As of
December 31, 2000, BNP Paribas had not obtained loan commitments for the
additional $10 million. During 2000, interest was calculated, at the
Partnership's option, by using either LIBOR plus 1.4% or BNP Paribas' prime rate
minus 1.0%. In 2001, the Credit Agreement was amended to change the interest
rates to LIBOR plus 2.25 % or BNP Paribas prime rate minus 0.875%.
The Credit Agreement expires on the earlier of (a) February 28, 2003 or
(b) 30 days prior to the termination of the Master Credit Support Agreement with
Salomon. As the Master Credit Support Agreement terminates on December 31,
2001,
the Credit Agreement with BNP Paribas is currently scheduled to expire on
November 30, 2001.
The Credit Agreement is collateralized by the accounts receivable,
inventory, cash accounts and margin accounts of GCOLP, subject to the terms of
an
Intercreditor Agreement between BNP Paribas and Salomon. There is no
compensating balance requirement under the Credit 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 the following: (a)
maintain a Current Ratio (calculated after the exclusion of debt under the
Credit
Agreement from current liabilities) of 1.0 to 1.0; (b) maintain a Tangible
Capital Base (as defined in the Credit Agreement) in GCOLP of not less than $65
million; and (c) maintain a Maximum Leverage Ratio (as defined in the Credit
Agreement) of not more than 5.0 to 1.0. In 2001, the agreement was amended to
change the Maximum Leverage Ratio requirement to not more than 7.5 to 1.0.
Additionally, the Credit Agreement imposes restrictions on the ability of GCOLP
to sell its assets, incur other indebtedness, create liens and engage in mergers
and acquisitions. The Partnership was not in compliance with the Maximum
Leverage Ratio covenant at the end of each month from June 30, 2000 through
November 30, 2000. A waiver for each period has been obtained from BNP Paribas.
The Partnership was in compliance with the Maximum Leverage Ratio and all other
ratios of the Credit Agreement at December 31, 2000.
20
At December 31, 2000, the Partnership had $22.0 million of loans
outstanding under the Credit Agreement. The Partnership had no letters of
credit
outstanding at December 31, 2000. At December 31, 2000, $3.0 million was
available to be borrowed under the Credit Agreement. The current average
interest rate is 9.5%.
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 2001.
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 and the Credit Agreement with a working capital/letter of
credit facility with one or more lenders prior to November 30, 2001. The
General
Partner expects that a replacement facility will cost more than its current
Guaranty 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.
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.
At December 31, 2000, the Partnership's consolidated balance sheet
reflected a working capital deficit of $15.6 million. This working capital
deficit combined with the short-term nature of both the Guaranty Facility with
Salomon and the Credit Agreement with BNP Paribas could have a negative impact
on
the Partnership. Some counterparties use the balance sheet and the nature of
available credit support as a basis for determining the level of credit support
demanded from the Partnership as a condition of doing business. Increased
demands for credit support beyond the maximum credit limitations and higher
credit costs may 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 for
distributions.
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.) As a result of
the
restructuring approved by unitholders on December 7, 2000, the minimum quarterly
distribution ("MQD") for each quarter has been reduced to $0.20 per unit
beginning with the distribution for the fourth quarter of 2000, which was paid
in
February 2001.
In 2000, the Partnership paid regular distributions to the Common
Unitholders and the General Partner totaling $2.00 per unit and a special
distribution of $0.28 per unit to the Common Unitholders as a result of the
approval of the Partnership restructuring. In 1999 and 1998, the Partnership
paid total distributions of $2.00 per unit to the Common Unitholders and the
General Partner. A distribution of $0.20 per unit, applicable to the fourth
quarter of 2000, was paid on February 14, 2001 to holders of record on January
31, 2001.
The distributions in 2000 were paid utilizing distribution support from
Salomon of $12.3 million. In 1999, distribution support of $3.9 million was
utilized. The obligation of Salomon to provide distribution support provided
for
a total of $17.6 million. With the utilization of $1.4 million of distribution
support to pay the restructuring costs, all distribution support had been
utilized at December 31, 2000.
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. A portion of 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. The spill was cleaned up, with
ongoing monitoring and reduced clean-up activity expected to continue for an
undetermined period of time. The oil spill is covered by insurance and the
financial impact to the Partnership for the cost of the clean-up has not been
material.
The estimated cost of the spill clean-up is expected to be $20.2 million.
This amount includes actual clean-up costs and estimates for ongoing maintenance
and settlement of potential liabilities to landowners in connection
21
with the spill. The incident was reported to insurers. At December 31, 2000,
$17.6 million had been paid to vendors and claimants for spill costs, and $2.6
million was included in accrued liabilities for estimated future expenditures.
Current assets included $1.8 million of expenditures submitted and approved by
insurers but not yet reimbursed, $1.2 million for expenditures not yet submitted
to insurers and $2.6 million for expenditures not yet incurred or billed to the
Partnership. At December 31, 2000, $14.6 million in reimbursements had been
received from insurers.
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 19 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. The
Partnership plans in 2001 to perform testing of the affected segment of the
pipeline at an estimated cost of $0.2 million to determine a course of action to
restart the system. 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. Subject to the results of
testing and regulatory approval, the Partnership intends to restart this segment
of the Mississippi System during the latter half of 2001.
If Management of the Partnership determines that the costs of additional
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 $0.3 million from the 2000 level 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 $5.7
million.
The Partnership was named as one of the defendants in a complaint filed by
Garner Environmental Services, Inc. ("Garner") on October 12, 2000 in the 265th
District Court of Harris County, Cause No. 200019833. Garner, who participated
in the pipeline oil spill clean-up, had sued the Partnership on account and
breach of contract. In March 2001 this lawsuit was settled for a minimal
amount.
Crude Oil Contamination
In the first quarter of 2000, the Partnership purchased crude oil from a
third party that was subsequently determined to contain organic chlorides.
These
barrels were delivered into the Partnership's Texas pipeline system and
potentially contaminated 24,000 barrels of oil held in storage and 44,000
barrels
of oil in the pipeline. The Partnership has disposed of all contaminated crude.
The Partnership incurred costs associated with transportation, testing and
consulting in the amount of $230,000 as of December 31, 2000.
The Partnership has recorded a receivable for $230,000 to reflect the
expected recovery of the accrued costs from the third party. The third party
has
provided the Partnership with evidence that it has sufficient resources to cover
the total expected damages incurred by the Partnership. Management of the
Partnership believes that it will recover any damages incurred from the third
party.
The Partnership has been named one of the defendants in a complaint filed by
Thomas Richard Brown on January 11, 2001, in the 125th District Court of Harris
County, cause No. 2001-01176. Mr. Brown, an employee of Pennzoil-Quaker State
Company ("PQS"), seeks damages for burns and other injuries suffered as a result
of a fire and explosion that occurred at the Pennzoil Quaker State refinery in
Shreveport, Louisiana, on January 18, 2000.
On January 17, 2001, PQS filed a Plea in Intervention in the cause filed by
Mr. Brown. PQS seeks property damages, loss of use and business interruption.
Both plaintiffs claim the fire and explosion was caused, in part, by Genesis
selling to PQS crude oil that was contaminated with organic chlorides.
Management of the Partnership believes that the suit is without merit and
intends
to vigorously defend itself in this matter. Management of the Partnership
believes that any potential liability will be covered by insurance.
Change to American Stock Exchange
Until February 1, 2001, the Common Units of Genesis were traded on the New
York Stock Exchange ("NYSE"). In December 2000, the Partnership was notified
that it failed to meet the NYSE's continued listing requirements and that the
NYSE was commencing delisting procedures. Management of the General Partner
submitted a plan to the NYSE to cure the continued listing deficiencies.
However, management later concluded that it would be preferable to list the
Partnership's Common Units on the AMEX. On January 31, 2001,
22
the Partnership's Common Units ceased to be listed on the NYSE and, on
February 1, 2001, began being listed on the AMEX.
Current Business Conditions
Changes in the price of crude oil impact gathering and marketing and
pipeline gross margins to the extent that oil producers adjust production
levels.
Short-term and long-term price trends impact the amount of cash flow that
producers have available to maintain existing production and to invest in new
reserves, which in turn impacts the amount of crude oil that is available to be
gathered and marketed by the Partnership and its competitors.
Although crude oil prices have increased from $12 per barrel in January 1999
to more than $31 per barrel in the fourth quarter of 2000, U.S. onshore crude
oil
production volumes have not improved. Further, producers appear to be
responding
cautiously to the oil price increase and are focusing more on drilling for
natural gas.
This change is clearly demonstrated by the Baker Hughes North American
Rotary Rig Count for 1997 to 2000.
Baker Hughes North American Rotary Rig Count
Average Number of Rigs Drilling For Crude Oil
Year Oil Gas Price per bbl*
---- --- --- -------------
1997 376 566 $20.60
1998 264 560 $14.40
1999 128 496 $19.25
2000 197 720 $30.30
* Annual average price for 1997 through 2000 for West Texas Intermediate at
Cushing, Oklahoma
Based on the limited improvement in the number of rigs drilling for oil,
management of the General Partner believes that oil production in its primary
areas of operation is likely to continue to decrease. Although there has been
some increase since 1999 in the number of drilling and workover rigs being
utilized in the Partnership's primary areas of operation, management of the
General Partner believes that this activity is more likely to have the effect of
reducing the rate of decline rather than meaningfully increasing wellhead
volumes
in its operating areas in 2001 and 2002.
The Partnership's improved volumes in 2000 compared to 1999 were primarily
due to obtaining existing production by paying higher prices for the production
than the previous purchaser. Increased volumes obtained through competition
based on price for existing production generally result in incrementally lower
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 has taken steps to reduce or restrict the
Partnership's gathering and marketing activities due to the $300 million limit
of
the Guaranty Facility.
Additionally, as prices rise, the Partnership may have to increase the
amount of its Credit Agreement 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 Credit Agreement
or that changes to the terms of such increased Credit Agreement would not have a
material impact on the results of operations or cash flows of the Partnership.
Adoption of FAS 133 for 2001
In January 2001, the Partnership adopted the provisions of SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities", which
established
new accounting and reporting guidelines for derivative instruments and hedging
activities. SFAS No. 133 established accounting and reporting standards
requiring that every derivative instrument (including certain derivative
instruments embedded in other contracts) be recorded in the balance sheet as
either an asset or liability measured at its fair value. SFAS No. 133 requires
that changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special accounting for
qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the income statement. Companies must formally
document, designate and assess the effectiveness of transactions that receive
hedge accounting.
23
Under SFAS No. 133, the Partnership will mark-to-market all of its
derivative instruments at each period end with changes in fair value being
recorded as unrealized gains or losses. Such unrealized gains or losses will
change, based on prevailing market prices, at each balance sheet date prior to
the period in which the transaction actually occurs. In general, SFAS No. 133
requires that at the date of initial adoption, the difference between the fair
value of derivative instruments and the previous carrying amount of those
derivatives be recorded in net income or other comprehensive income, as
appropriate, as the cumulative effect of a change in accounting principle. The
adoption of SFAS No. 133 will result in a charge of approximately $3.8 million
to
net income, which will be reflected as the cumulative effect of a change in
accounting principle.
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 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, 2000, the Partnership used
futures, forward and options contracts exclusively in its hedging program with
the latest contract being settled in July 2002. 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) 34
Carrying value $ 847
Fair value $ 847
Commodity Futures Contracts:
Contract volumes (1,000 bbls) 13,205 13,997
Weighted average price per bbl $ 29.01 $ 28.52
Contract value (in thousands) $383,027 $399,250
Fair value (in thousands) $344,906 $361,741
Commodity Forward Contracts:
Contract volumes (1,000 bbls) 4,904 4,465
Weighted average price per bbl $ 29.42 $ 29.09
Contract value (in thousands) $144,305 $129,882
Fair value (in thousands) $129,757 $119,103
Commodity Option Contracts:
Contract volumes (1,000 bbls) 22,080
Weighted average strike price per bbl $ 2.60
Contract value (in thousands) $ 6,717
Fair value (in thousands) $ 7,347
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, 2000 closing prices of the applicable
NYMEX futures contract adjusted for location and grade differentials, as
necessary.
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 33.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosures
None.
24
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 54 Director and Chairman of the Board
Mark J. Gorman 46 Director, Chief Executive Officer and
President
John P. vonBerg 47 Director, Vice Chairman of the Board, and
Executive Vice President, Trading and
Price Risk Management
Herbert I. Goodman 78 Director
J. Conley Stone 69 Director
Robert T. Moffett 49 Director
John M. Fetzer 47 Executive Vice President
Ross A. Benavides 47 Chief Financial Officer, General Counsel and
Secretary
Ben F. Runnels 60 Vice President, Trucking Operations
Kerry W. Mazoch 54 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 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.
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.
25
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.
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.
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 no Forms 5 were
required for those persons, the General Partner believes that during 2000 its
officers and directors complied with all applicable filing requirements in a
timely manner.
Representatives of Salomon 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 2000, 1999 and 1998 to the Chief Executive
Officer and each of Genesis' four other most highly compensated executive
officers (the "Named Officers").
26
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 2000 270,000 50,000 - -
10,200
Chief Executive Officer 1999 236,000 - - -
9,600
and President 1998 230,000 37,500 -
570,891 9,600
John P. vonBerg 2000 270,000 97,500 - -
10,200
Executive Vice President, 1999 410,000 - - -
9,600
Trading and Price Risk 1998 350,000 - -
570,891 9,600
Management
John M. Fetzer 2000 270,000 50,000 - -
10,200
Executive Vice President 1999 211,000 - - -
9,600
1998 200,000 37,500 -
570,891 9,600
Ross A. Benavides 2000 150,000 50,000 - -
9,173
Chief Financial Officer, 1999 150,000 - - -
9,586
General Counsel and 1998 31,700 10,000 -
185,000 1,904
Secretary
Kerry W. Mazoch 2000 166,000 30,000 - -
10,080
Vice President, Crude 1999 166,000 25,000 - -
9,600
Oil Acquisitions 1998 166,000 25,000 -
231,057 4,800
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.
Includes $5,100 of Company-matching contributions to a defined contribution plan
and $5,100 of profit-sharing contributions to a defined contribution plan.
Includes $4,587 of Company-matching contributions to a defined contribution plan
and $4,586 of profit-sharing contributions to a defined contribution plan.
Includes $4,980 of Company-matching contributions to a defined contribution plan
and $5,100 of profit-sharing contributions to a defined contribution plan.
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 vested in
increments of one-
third annually beginning on December 8, 1998. The vested units cannot be sold
until one year after vesting. 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, 2000,
Mr. Gorman had 6,842 vested restricted units and 13,683 vested units for which
the restriction
period had expired. These units had a combined value of $74,403 (determined
using closing market price of unrestricted units on December 31, 2000). He had
no unvested
restricted units. Mr. Gorman relinquished 2,855 of the units that vested in
2000, 1999 and 1998, respectively, so that the value of the units on the vesting
date ($4.3125,
$6.6875 and
27
$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, 2000,
Mr. vonBerg had 5,717 vested restricted units and 12,558 vested units for which
the restriction
period had expired. These units had a combined value of $66,247 (determined
using closing market price of unrestricted units on December 31, 2000). He had
no unvested
restricted units. Mr. vonBerg relinquished 3,980, 3,980 and 2,855 of the units
that vested in 2000, 1999 and 1998, respectively, so that the value of the units
on the vesting
date ($4.3125, $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, 2000,
Mr. Fetzer had 6,163 vested restricted units and 13,683 vested units for which
the restriction
period had expired. These units had a combined value of $71,942 (determined
using closing market price of unrestricted units on December 31, 2000). He had
no unvested
restricted units. Mr. Fetzer relinquished 3,534, 2,855 and 2,855 of the units
that vested in 2000, 1999 and 1998, respectively, so that the value of the units
on the vesting
date ($4.3125, $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. 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. After vesting, Mr. Benavides
will receive
distributions whenever distributions are paid to the Common Unitholders. At
December 31, 2000, Mr. Benavides had 2,352 vested restricted units and 1,965
vested units for which
the restriction period had expired. These units had a combined value of $15,649
(determined using closing market price of unrestricted units on December 31,
2000). He had
3,334 unvested restricted units with a value of $12,086. Mr. Benavides
relinquished 981 and 1,368 of the units that vested in 2000 and 1999,
respectively, so that the value of
the units on the vesting date ($4.3125 and $6.6875 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, 2000,
Mr. Mazoch had 2,383 vested restricted units and 5,702 vested units for which
the restriction
period had expired. These units had a combined value of $29,308 (determined
using closing market price of unrestricted units on December 31, 2000). He had
no unvested
restricted units. Mr. Mazoch relinquished 1,658, 1,189 and 1,189 of the units
that vested in 2000, 1999 and 1998, respectively, so that the value of the units
on the vesting
date ($4.3125, $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 $952 of Company matching contributions to a defined contribution plan
and $952 of profit-sharing contributions to a defined contribution plan.
Includes $4,800 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 expired in October 2000. The
agreement with Mr. Runnels has five additional optional extension terms of one
year each ("Extension Terms"). The agreements with Mr. Runnels includes 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
28
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 terminated on December 31, 2000; however, 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 261,000
Common Units (the "Restricted Units") have been allocated to approximately 34
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 31,000 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. 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.
Bonus Plan
In February 2001, the Compensation Committee of the Board of Directors of
the General Partner approved a Bonus Plan (the "Bonus Plan") for the executive
officers and employees of the General Partner. The Bonus Plan is designed to
enhance the financial performance of the Partnership by rewarding all employees
for achieving financial performance objectives. The Bonus Plan will be
administered by the Compensation Committee. Under this plan, amounts will be
allocated for the payment of bonuses to executive officers and employees each
time GCOLP earns $1.5 million of Available Cash. The amount allocated to the
bonus pool increases for each $1.5 million earned, such that a bonus pool of
$1.2
million will exist if the Partnership earns $9.0 million of Available Cash.
Bonuses will be paid to executive officers and employees as each $1.5 million
increment of Available Cash is earned. Payments under the Bonus Plan will be at
the discretion of the Compensation Committee, and the General Partner will be
able to amend or change the Bonus Plan at any time.
29
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
28,
2001.
Amount and
Nature
Name and Address of Beneficial
Ownership Percent
Title of Class of Beneficial Owner as of January
1, 2001 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
54.00
Salomon Brothers Holding Company Inc.
46.00
333 Greenwich
New York, NY 10013
_____________________
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 28, 2001,
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 25,525 -
*
John P. vonBerg 27,275 -
*
Herbert I. Goodman 2,000 -
*
J. Conley Stone 1,000 -
*
Robert T. Moffett - -
- -
John M. Fetzer 24,846 -
*
Kerry W. Mazoch 8,085 -
*
Ross A. Benavides 7,317 -
*
All directors and
executive officers
as a group (10 in
number) 103,391 -
1
- -------------------
* Less than 1%
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
Until December 7, 2000, Salomon and Howell owned 1,163,700 and 991,300
Subordinated OLP Units, respectively, representing a 10.58% and 9.01% limited
partner interest in GCOLP. As part of the Partnership restructuring, the
Subordinated OLP Units were eliminated. 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.
Genesis enters into transactions with Salomon and its subsidiaries, Howell and
its subsidiaries and the General Partner in the ordinary course of its
operations. During 2000, these transactions included:
30
* Sales and purchases of crude oil from a subsidiary of Salomon totaling
$35.1 million and $121.1 million, respectively.
* Purchases of crude oil from a subsidiary of Howell totaling $9.6 million.
* Provision of personnel to manage and operate the assets and operations of
Genesis by the General Partner. Genesis reimbursed the General Partner for
all direct and indirect costs of these services in the amount of $16.9
million.
* Provision of guarantees to counterparties by Salomon for GCOLP in the
maximum aggregate amount of $300 million. Genesis paid fees to Salomon for
guaranty utilization totaling $1.7 million.
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 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 was limited to a maximum amount
outstanding at any one time equal to $17.6 million. During 1999, $3.9 million
of
the Distribution Support was utilized. During 2000, $9.9 million of the
Distribution Support was utilized for the distributions in February, May and
August. In connection with the approval of the restructuring of Genesis by the
Common Unitholders on December 7, 2000, the remaining Distribution Support of
$3.8 million was contributed to the Partnership. The costs of the
restructuring,
totaling $1.4 million, were paid from this amount and the remainder was paid to
Common Unitholders in a special distribution. The special distribution,
totaling
$2.4 million, or $0.28 per Common Unit, was paid on December 28, 2000, to
unitholders of record on December 18, 2000. As part of the restructuring, all
APIs were eliminated, without payment of consideration, and as a result, the
obligation of the Partnership to redeem the APIs issued to Salomon was also
eliminated.
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 33.
(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 Amended and Restated Agreement of Limited Partnership of Genesis
(incorporated by reference to Exhibit 2 of Form 8-A filed January 30,
2001)
** 3.3 Certificate of Limited Partnership of Genesis Crude Oil, L.P. (the
"Operating Partnership")
* 3.4 Second Amended and Restated Agreement of Limited Partnership of
the Operating Partnership
** 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
10.6 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)
10.7 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)
10.8 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)
10.9 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)
31
10.10 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)
** 10.11 Employment Agreement between Genesis Energy, L.L.C. and Ben F.
Runnels
10.12 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)
10.13 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)
10.14 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)
10.15 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)
10.16 Tenth Amendment to Master Credit Support Agreement (incorporated
by reference to Exhibit 10.1 to Form 8-K dated June 1, 1999)
10.17 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)
10.18 Twelfth Amendment to Master Credit Support Agreement
(incorporated by reference to Exhibit 10.1 to Form 10-Q for the
quarterly period ended September 30, 2000)
* 10.19 Thirteenth Amendment to Master Credit Support Agreement
10.20 Amended and Restated Restricted Unit Plan (incorporated by
reference to Exhibit 10.18 to Form 10-K for the year ended December
31, 1997)
10.21 Credit Agreement dated as of June 6, 2000, between Genesis Crude
Oil, L.P. and Certain Lenders, with Paribas as Agent (incorporated by
reference to Exhibit 10 to Form 10-Q for the quarterly period ended
June 30, 2000)
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
- -------------------
* 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
A report on Form 8-K was filed on December 8, 2000, announcing the approval
by unitholders on December 7, 2000, of the restructuring of the Partnership
as described in the proxy statement mailed October 23, 2000, to unitholders
of record on October 18, 2000.
32
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 21st day of March,
2001.
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 21, 2001
----------------------- and President
Mark J. Gorman (Principal Executive Officer)
/s/ Ross A. Benavides Chief Financial Officer, March 21, 2001
----------------------- General Counsel and
Ross A. Benavides Secretary
(Principal Financial and
Accounting Officer)
/s/ A. Richard Janiak Chairman of the Board and March 21, 2001
----------------------- Director
A. Richard Janiak
/s/ John P. vonBerg Vice Chairman, Director, and Executive March 21, 2001
----------------------- Vice President, Trading and Price
John P. vonBerg Risk Management
Director March 21, 2001
-----------------------
Herbert I. Goodman
/s/ J. Conley Stone Director March 21, 2001
-----------------------
J. Conley Stone
/s/ Robert T. Moffett Director March 21, 2001
-----------------------
Robert T. Moffett
33
GENESIS ENERGY, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
Report of Independent Public Accountants 34
Consolidated Balance Sheets, December 31, 2000 and 1999 35
Consolidated Statements of Operations for the Years Ended
December 31, 2000, 1999 and 1998 36
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2000, 1999 and 1998 37
Consolidated Statements of Partners' Capital for the Years Ended
December 31, 2000, 1999 and 1998 38
Notes to Consolidated Financial Statements 38
34
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, 2000 and 1999, and the
related consolidated statements of operations, cash flows and partners' capital
for each of the three years in the period ended December 31, 2000. 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, 2000 and 1999, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2000, in
conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas
March 2, 2001
35
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31, December 31,
2000 1999
-------- --------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 5,508 $ 6,664
Accounts receivable -
Trade 329,464 241,529
Related party - 7,030
Inventories 994 404
Insurance receivable for pipeline spill costs 5,527 16,586
Other 9,111 2,504
-------- --------
Total current assets 350,604 274,717
FIXED ASSETS, at cost 113,715 116,332
Less: Accumulated depreciation (25,609) (22,419)
-------- --------
Net fixed assets 88,106 93,913
OTHER ASSETS, net of amortization 10,633 11,962
-------- --------
TOTAL ASSETS $449,343 $380,592
======== ========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Bank borrowings $ 22,000 $ 19,900
Accounts payable -
Trade 322,912 251,742
Related party 4,750 1,604
Accrued liabilities 16,546 19,290
-------- --------
Total current liabilities 366,208 292,536
COMMITMENTS AND CONTINGENCIES (Note 19)
ADDITIONAL PARTNERSHIP INTERESTS - 3,900
MINORITY INTERESTS 520 30,571
PARTNERS' CAPITAL
Common unitholders, 8,625 units issued; 8,624
and 8,620 units outstanding at December 31,
2000 and 1999, respectively 80,960 52,574
General partner 1,661 1,051
-------- --------
Subtotal 82,621 53,625
Treasury units, 1 and 5 units at December 31,
2000 and 1999, respectively (6) (40)
-------- --------
Total partners' capital 82,615 53,585
-------- --------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $449,343 $380,592
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
36
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
Year Ended December 31,
------------------------------------
2000 1999 1998
---------- ---------- ----------
REVENUES:
Gathering and marketing revenues
Unrelated parties $4,274,519 $2,067,451 $2,178,224
Related parties 35,095 77,195 38,718
Pipeline revenues 14,940 16,366 16,533
---------- ---------- ----------
Total revenues 4,324,554 2,161,012 2,233,475
COST OF SALES:
Crude costs, unrelated parties 4,150,888 2,043,506 2,141,715
Crude costs, related parties 130,679 74,812 42,814
Field operating costs 13,673 11,669 12,778
Pipeline operating costs 8,652 8,161 7,971
---------- ---------- ----------
Total cost of sales 4,303,892 2,138,148 2,205,278
---------- ---------- ----------
GROSS MARGIN 20,662 22,864 28,197
EXPENSES:
General and administrative 10,942 11,649 11,468
Depreciation and amortization 8,032 8,220 7,719
Nonrecurring charges 1,387 - 373
---------- ---------- ----------
OPERATING INCOME 301 2,995 8,637
OTHER INCOME (EXPENSE):
Interest income 259 156 421
Interest expense (1,269) (1,085) (267)
Net gain on disposal of surplus assets 1,148 849 28
---------- ---------- ----------
Net income before minority interests 439 2,915 8,819
Minority interests 258 583 1,763
---------- ---------- ----------
NET INCOME $ 181 $ 2,332 $ 7,056
========== ========== ==========
NET INCOME PER COMMON UNIT- BASIC
AND DILUTED $ 0.02 $ 0.27 $ 0.80
========== ========== ==========
WEIGHTED AVERAGE NUMBER OF COMMON
UNITS OUTSTANDING 8,617 8,604 8,606
========== ========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
37
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Year Ended December 31,
2000 1999 1998
-------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 181 $ 2,332 $ 7,056
Adjustments to reconcile net income to net cash provided by (used in)
operating
activities -
Depreciation 6,714 6,832 6,529
Amortization of intangible assets 1,318 1,388 1,190
(Gain) loss on disposal of assets (1,148) (849) 269
Minority interests equity in earnings 258 583 1,763
Restructuring costs 1,387 - -
Other noncash charges 1,801 1,459 1,503
Changes in components of working capital -
Accounts receivable (80,905) (76,325) 37,635
Inventories (590) 1,562 1,384
Other current assets 4,436 (15,784) 182
Accounts payable 74,316 75,003 (39,648)
Accrued liabilities (3,355) 13,861 (1,446)
-------- -------- --------
Net cash provided by operating activities 4,413 10,062 16,417
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (1,685) (2,717) (13,431)
Change in other assets 11 416 (4,270)
Proceeds from sales of assets 1,942 1,012 188
-------- -------- --------
Net cash provided by (used in) investing
activities 268 (1,289) (17,513)
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank borrowings, net 2,100 4,100 15,800
Distributions to common unitholders (19,645) (17,206) (17,208)
Distributions to General Partner (352) (352) (352)
Issuance of additional partnership interests 13,702 3,900 -
Payment of restructuring costs (1,387) - -
Purchase of treasury units (255) (261) (1,246)
-------- -------- --------
Net cash used in financing activities (5,837) (9,819) (3,006)
Net decrease in cash and cash equivalents (1,156) (1,046) (4,102)
Cash and cash equivalents at beginning of
period 6,664 7,710 11,812
-------- -------- --------
Cash and cash equivalents at end of period $ 5,508 $ 6,664 $ 7,710
======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
38
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, 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
Net income 177 4 -
181
Cash distributions (19,645) (352) -
(19,997)
Purchase of treasury units - - (255)
(255)
Issuance of treasury units to Restricted
Unit Plan participants - - 289
289
Excess of expense over cost of treasury units
issued for Restricted Unit Plan 901 - -
901
Elimination of additional partnership interests 17,248 352 -
17,600
Elimination of subordinated limited partner
interests in Operating Partnership 29,705 606 -
30,311
------- ------ -------
- --------
Partners' capital, December 31, 2000 $80,960 $1,661 $ (6)
$ 82,615
======= ====== =======
========
The accompanying notes are an integral part of these consolidated financial
statements.
39
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Partnership Structure
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.
Restructuring
On December 7, 2000, the unitholders of the Partnership approved a
restructuring which amended the GCOLP partnership agreement to:
* reduce the minimum quarterly distribution on Common Units from the
previous $0.50 to the new $0.20 per unit;
* reduce correspondingly the respective per unit dollar distribution
thresholds that must be achieved before the General Partner is entitled to
incentive compensation payments from the prior threshold levels of $0.55,
$0.635 and $0.825 per unit to the new levels of $0.25, $0.28 and $0.33 per
unit;
* eliminate all of the Subordinated OLP Units in GCOLP, and as a result,
provide that the Common Units will no longer accrue arrearages if the minimum
quarterly distribution is not paid in full in any quarter; and
* eliminate, without payment of any consideration, all of the outstanding
additional partnership interests, or APIs, issued to Salomon in exchange for
its distribution support and, as a result, eliminate the Partnership's
obligation to redeem the APIs issued to Salomon.
Additionally, as a result of the approval of the restructuring:
* Salomon contributed to GCOLP in cash the remaining distribution support of
$3.8 million. After payment of $1.4 million of transaction costs associated
with the restructuring, a special distribution of the remaining cash of $2.4
million, or $0.28 per Common Unit, was paid on December 28, 2000, to Common
Unitholders of record on December 18, 2000; and
40
* Salomon extended the expiration date of its $300 million credit support
obligation to GCOLP from March 31, 2001, to December 31, 2001, under its
current terms and conditions.
2. Basis of Presentation
The accompanying financial statements and related notes present the
consolidated financial position as of December 31, 2000 and 1999 for GELP and
its
results of operations, cash flows and changes in partners' capital for the years
ended December 31, 2000, 1999 and 1998.
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.
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 96,000 barrels per day at the wellhead
principally in the southern and southwestern states. The Partnership also owns
and operates three crude oil pipelines. The pipelines are in Texas,
Mississippi/Louisiana and Florida/Alabama.
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 the lower of average cost
or market. Fuel inventories 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 of $9.4 million 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. See Note 7.
41
Minority Interests
Until December 7, 2000, 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. As part of the restructuring
discussed above, minority interest at December 31, 2000, represents a 0.01%
general partner interest 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.
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 8,616,744, 8,604,352 and 8,605,934 for the years ended December
31, 2000, 1999 and 1998, respectively. For this purpose, the 2% or 0.01%
General
Partner interest, as applicable, 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. 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. No customer accounted for more than
10% of the Partnership's revenues in any period.
5. Inventories
Inventories consisted of the following (in thousands).
December 31,
------------
2000 1999
---- ----
Crude oil inventories, at lower of cost or market $847 $ -
Fuel and supplies inventories, at lower of cost or market 147 404
---- ----
Total inventories $994 $404
==== ====
6. Fixed Assets
Fixed assets consisted of the following (in thousands).
December 31,
------------------
2000 1999
-------- --------
Land and buildings $ 3,718 $ 3,726
Pipelines and related assets 96,670 95,378
Vehicles and transportation equipment 1,894 5,950
Office equipment, furniture and fixtures 2,569 2,347
Other 8,864 8,931
-------- --------
113,715 116,332
Less - Accumulated depreciation (25,609) (22,419)
-------- --------
Net fixed assets $ 88,106 $ 93,913
======== ========
42
Depreciation expense was $6,714,000, $6,832,000 and $6,529,000 for the years
ended December 31, 2000, 1999 and 1998, respectively.
7. Other Assets
Other assets consisted of the following (in thousands).
December 31,
----------------
2000 1999
------- -------
Goodwill $ 9,401 $ 9,401
NYMEX seats 1,203 1,203
Covenant not to compete 4,238 4,238
Other 51 62
------- -------
14,893 14,904
Less - Accumulated amortization (4,260) (2,942)
------- -------
Net other assets $10,633 $11,962
Amortization expense was $1,318,000, $1,388,000 and $1,190,000 for the years
ended December 31, 2000, 1999 and 1998, respectively.
8. 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, 2001 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, 2001 (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.
At
December 31, 2000, the aggregate amount of obligations covered by guarantees was
$258 million, including $127 million in payable obligations and $131 million of
estimated crude oil purchase obligations for January 2001.
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 its
Consolidated Current Liabilities to Consolidated Working Capital plus net
property, plant and equipment of not more than 7.5 to 1, and (d) 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.
43
Working Capital Facility
In August 1998, GCOLP entered into a revolving credit/loan agreement ("Loan
Agreement") with Bank One, Texas, N.A. to replace a Working Capital Facility
that
had been provided by Salomon. In June 2000, the Loan Agreement was replaced
with
a secured revolving credit facility ("Credit Agreement") with BNP Paribas. The
Credit Agreement provides for loans or letters of credit in the aggregate not to
exceed the greater of $25 million or the Borrowing Base (as defined in the
Credit
Agreement). If BNP Paribas obtains loan commitments for an additional $10
million, the amount available under the Credit Agreement would increase to $35
million. As of December 31, 2000, BNP Paribas had not obtained loan commitments
for the additional $10 million.
During 2000, loans bore interest at a rate chosen by GCOLP which would be one
or more of the following: (a) a rate based on LIBOR plus 1.4% or (b) BNP
Paribas' prime rate minus 1.0% In 2001, the Credit Agreement was amended to
change the interest rates to LIBOR plus 2.25% or BNP Paribas prime rate minus
0.875%.
The Credit Agreement expires on the earlier of (a) February 28, 2003 or (b)
30 days prior to the termination of the Master Credit Support Agreement with
Salomon. As the Master Credit Support Agreement terminates on December 31,
2001,
the Credit Agreement with BNP Paribas is currently scheduled to expire on
November 30, 2001.
The Credit Agreement is collateralized by the accounts receivable, inventory,
cash accounts and margin accounts of GCOLP, subject to the terms of an
Intercreditor Agreement between BNP Paribas and Salomon. There is no
compensating balance requirement under the Credit 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 the following: (a)
maintain a Current Ratio (calculated after the exclusion of debt under the
Credit
Agreement from current liabilities) of 1.0 to 1.0; (b) maintain a Tangible
Capital Base (as defined in the Credit Agreement) in GCOLP of not less than $65
million; and (c) maintain a Maximum Leverage Ratio (as defined in the Credit
Agreement) of not more than 5.0 to 1.0. The agreement was amended in 2001 to
change the Maximum Leverage Ratio requirement to not more than 7.5 to 1.0.
Additionally, the Credit Agreement imposes restrictions on the ability of GCOLP
to sell its assets, incur other indebtedness, create liens and engage in mergers
and acquisitions. The Partnership was not in compliance with the Maximum
Leverage Ratio covenant at the end of each month from June 30, 2000 through
November 30, 2000. A waiver for each period has been obtained from BNP Paribas.
The Partnership was in compliance with the Maximum Leverage Ratio and all other
ratios of the Credit Agreement at December 31, 2000.
At December 31, 2000, the Partnership had $22.0 million of loans outstanding
under the Credit Agreement. The Partnership had no letters of credit
outstanding
at December 31, 2000. At December 31, 2000, $3.0 million was available to be
borrowed under the Credit Agreement.
Credit Availability
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 2001.
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 and the Credit Agreement with a working capital/letter of
credit facility with one or more lenders prior to November 30, 2001. The
General
Partner expects that a replacement facility will cost more than its current
Guaranty 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.
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.
At December 31, 2000, the Partnership's consolidated balance sheet reflected
a working capital deficit of $15.6 million. This working capital deficit
combined with the short-term nature of both the Guaranty Facility with Salomon
and the Credit Agreement with BNP Paribas could have a negative impact on the
Partnership. Some counterparties use the balance sheet and the nature of
available credit support as a basis for determining the level of credit support
demanded from the Partnership as a condition of doing business. Increased
demands for credit
44
support beyond the maximum credit limitations and higher credit costs may
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 for distributions.
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.) As a result of
the
restructuring approved by unitholders on December 7, 2000, the minimum quarterly
distribution ("MQD") for each quarter has been reduced to $0.20 per unit
beginning with the distribution for the fourth quarter of 2000, which was paid
in
February 2001.
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.
9. 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. The
Partnership is managed by the General Partner.
Until December 7, 2000, GELP had an approximate 80.01% general partner interest
in GCOLP. The remainder of GCOLP was held by Salomon, Howell and the General
Partner. These interests, reflected in the consolidated financial statements as
minority interests, were subordinated limited partner interests held by Salomon
and Howell of 10.58% and 9.01%, respectively, and the general partner interest
in
GCOLP of 0.40% held by the General Partner.
As discussed in Note 1, on December 7, 2000, the unitholders of the Partnership
approved a restructuring which amended the GCOLP partnership agreement. As a
result, GELP now holds a 99.99% limited partner interest in GCOLP. The General
Partner holds a 0.01% general partner interest in GCOLP, which is reflected as a
minority interest in the consolidated balance sheet at December 31, 2000. The
subordinated limited partner interests in GCOLP were eliminated.
10. Nonrecurring Charges
In connection with the restructuring of the Partnership, costs totaling $1.4
million were incurred primarily for legal and accounting fees, financial advisor
fees, proxy solicitation expenses and the costs to print and mail proxy
materials
to Common Unitholders. These costs are reflected as a nonrecurring charge in
the
consolidated statement of operations for 2000. The cash needed to fund these
expenses was provided from the final distribution support obligation payment
made
by Salomon pursuant to the terms of the proxy statement.
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.
11. 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.
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,
--------------------------
2000 1999 1998
-------- ------- -------
Sales to affiliates $ 35,095 $77,195 $38,718
Purchases from affiliates $130,679 $74,812 $42,814
45
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
$16,946,000, $16,687,000 and $15,428,000 for the years ended December 31, 2000,
1999 and 1998, respectively.
Treasury Services
In 1998, Salomon provided treasury management services to the Partnership
pursuant to the Treasury Management Agreement. Under the Treasury Management
Agreement, the Partnership invested excess cash with Salomon and earned interest
at market rates. For the year ended December 31, 1998, the Partnership earned
interest of $288,000 on the investments with Salomon. The Treasury Management
Agreement has expired.
Credit Facilities
As discussed in Note 8, Salomon provides Credit Facilities to the
Partnership. For the years ended December 31, 2000, 1999 and 1998, the
Partnership paid Salomon $1,712,000, $680,000 and $578,000, respectively, for
guarantee fees under the Credit Facilities. The guarantee fees are included as
a
component in cost of crude on the consolidated statements of operations. The
Partnership paid Salomon $18,000 for interest under the Credit Facilities during
1998.
12. Supplemental Cash Flow Information
In 2000, two noncash transactions occurred as a result of the restructuring of
the Partnership. APIs and minority interests related to the Subordinated OLP
Units were eliminated and resulted in an increase in the capital accounts of the
Common Unitholders and General Partner of GELP.
Cash received by the Partnership for interest during the years ended December
31, 2000, 1999 and 1998 was $241,000, $152,000 and $422,000, respectively.
Payments of interest were $1,370,000, $1,035,000 and $274,000 during the years
ended December 31, 2000, 1999 and 1998, respectively.
13. 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.
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 $570,000, $566,000 and $619,000 for the years ended December 31, 2000, 1999
and 1998, respectively.
The General Partner also provided certain health care and survivor benefits for
its active employees. In 1998, these plans were fully-insured. In 2000 and
1999, these benefit programs were self-insured. The General Partner plans to
continue self-insuring these plans in the future. The expenses of the General
Partner for these benefits were $1,718,000, $1,067,000 and $1,338,000 in 2000,
1999 and 1998, respectively.
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.
46
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 261,000 Common Units (the "Restricted Units") have been
allocated to approximately 34 individuals, subject to the vesting conditions
described below and subject to other customary terms and conditions. The
remaining rights to receive 30,000 Common Units 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 2000, 1999 and 1998, the Partnership recorded expense of $1,192,000,
$1,459,000 and $1,617,000, respectively, related to the Restricted Units.
Bonus Plan
In February 2001, the Compensation Committee of the Board of Directors of
the General Partner approved a Bonus Plan (the "Bonus Plan") for the executive
officers and employees of the General Partner. The Bonus Plan is designed to
enhance the financial performance of the Partnership by rewarding all employees
for achieving financial performance objectives. The Bonus Plan will be
administered by the Compensation Committee. Under this plan, amounts will be
allocated for the payment of bonuses to executive officers and employees each
time GCOLP earns $1.5 million of Available Cash. The amount allocated to the
bonus pool increases for each $1.5 million earned, such that a bonus pool of
$1.2
million will exist if the Partnership earns $9.0 million of Available Cash.
Bonuses will be paid to executive officers and employees as each $1.5 million
increment of Available Cash is earned. Payments under the Bonus Plan will be at
the discretion of the compensation Committee, and the General Partner will be
able to amend or change the Bonus Plan at any time.
14. Sale of Tractor/Trailer Fleet
Management of the Partnership made the decision to sell its existing
tractor/trailer fleet and replace it with vehicles provided by Ryder
Transportation Services ("Ryder") under an operating lease. During 2000, the
Partnership sold 22 tractors and 68 trailers for a total of $1,802,000 and
recognized a gain of $1,037,000 on the sale of this equipment. The remaining 31
tractors were sold on January 8, 2001, for $400,000. The net book value of
those
tractors, totaling $286,000, is reflected in other current assets at December
31,
2000.
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.
47
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 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, 2000, 1999 and 1998 are as follows (in thousands).
2000 1999
1998
-------------------------- -------------------------
- -------------------------
Net Net
Net
Carrying Fair Gains Carrying Fair Gains
Carrying Fair Gains
Amount Value (Losses) Amount Value (Losses)
Amount Value (Losses)
-------- ------ -------- -------- ----- --------
- -------- ----- --------
Option contracts written $7,347 $7,347 $ - $390 $390 $ -
$ - $ - $ -
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. Derivatives and Hedging
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 gain of $1,570,000 was
deferred on these contracts at December 31, 2000 and unrecognized loss of
$1,718,000 was deferred at December 31, 1999.
Should a hedging contract become 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 market value, and
the resulting unrealized gains and losses are recognized currently in crude
costs
in the Consolidated Statements of Operations.
In January 2001, the Partnership adopted the provisions of SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities", which
established
new accounting and reporting guidelines for derivative instruments and hedging
activities. SFAS No. 133 established accounting and reporting standards
requiring that every derivative instrument (including certain derivative
instruments embedded in other contracts) be recorded in the balance sheet as
either an asset or liability measured at its fair value. SFAS No. 133 requires
that changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special accounting for
qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged
48
item in the income statement. Companies must formally document, designate and
assess the effectiveness of transactions that receive hedge accounting.
Under SFAS No. 133, the Partnership will mark-to-market all of its derivative
instruments at each period end with changes in fair value being recorded as
unrealized gains or losses. Such unrealized gains or losses will change, based
on prevailing market prices, at each balance sheet date prior to the period in
which the transaction actually occurs. In general, SFAS No. 133 requires that
at
the date of initial adoption, the difference between the fair value of
derivative
instruments and the previous carrying amount of those derivatives be recorded in
net income or other comprehensive income, as appropriate, as the cumulative
effect of a change in accounting principle. The adoption of SFAS No. 133 will
result in a charge of approximately $3.8 million to net income, which will be
reflected as the cumulative effect of a change in accounting principle.
19. Commitments and Contingencies
The Partnership uses surface, vehicle and office leases in the course of its
business operations. The Partnership leases its tractor/trailer fleet from
Ryder. The lease with Ryder covers 73 tractors and 73 trailers and is a full-
service maintenance agreement. It also provides for maintenance on 10 trailers
that GCOLP retained. 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, 2000, were as follows (in thousands).
2001 $ 3,513
2002 3,243
2003 3,073
2004 3,104
2005 2,554
2006 and thereafter 3,692
-------
Total minimum lease obligations $19,179
=======
Total operating lease expense was as follows (in thousands).
Year ended December 31, 2000 $ 2,500
Year ended December 31, 1999 $ 1,674
Year ended December 31, 1998 $ 1,921
The Partnership has contractual commitments (primarily forward contracts)
arising in the ordinary course of business. At December 31, 2000, the
Partnership had commitments to purchase 18,462,000 barrels of crude oil at fixed
prices ranging from $20.20 to $35.75 per barrel extending to February 2002, and
commitments to sell 18,109,000 barrels of crude oil at fixed prices ranging from
$20.25 to $35.40 per barrel extending to July 2002. Additionally, the
Partnership had commitments to purchase 24,819,000 barrels of crude oil
extending
to June 2003, and commitments to sell 9,329,000 barrels of crude oil extending
to
July 2001, 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 the Partnership and for any environmental liabilities which Basis
or Howell may have assumed from prior owners of these assets.
Unitholder Litigation
On June 7, 2000, Bruce E. Zoren, a holder of units of limited partner
interests in the partnership, filed a putative class action complaint in the
Delaware Court of Chancery, No. 18096-NC, seeking to enjoin the restructuring
and
seeking damages. Defendants named in the complaint include the partnership,
Genesis Energy L.L.C., members of the board of directors of Genesis Energy,
L.L.C., and Salomon Smith Barney Holdings Inc. The plaintiff alleges numerous
breaches of the duties of care and loyalty owed by the defendants to the
purported class in connection with making a proposal for restructuring.
Management of the General Partner believes that the complaint is without merit
and intends to vigorously defend the action.
49
Crude Oil Contamination and Pennzoil Lawsuit
In the first quarter of 2000, the Partnership purchased crude oil from a
third party that was subsequently determined to contain organic chlorides.
These
barrels were delivered into the Partnership's Texas pipeline system and
potentially contaminated 24,000 barrels of oil held in storage and 44,000
barrels
of oil in the pipeline. The Partnership has disposed of all contaminated crude.
The Partnership incurred costs associated with transportation, testing and
consulting in the amount of $230,000 as of December 31, 2000.
The Partnership has recorded a receivable for $230,000 to reflect the
expected recovery of the accrued costs from the third party. The third party
has
provided the Partnership with evidence that it has sufficient resources to cover
the total expected damages incurred by the Partnership. Management of the
Partnership believes that it will recover any damages incurred from the third
party.
The Partnership has been named one of the defendants in a complaint filed by
Thomas Richard Brown on January 11, 2001, in the 125th District Court of Harris
County, cause No. 2001-01176. Mr. Brown, an employee of Pennzoil-Quaker State
Company ("PQS"), seeks damages for burns and other injuries suffered as a result
of a fire and explosion that occurred at the Pennzoil Quaker State refinery in
Shreveport, Louisiana, on January 18, 2000.
On January 17, 2001, PQS filed a Plea in Intervention in the cause filed by
Mr. Brown. PQS seeks property damages, loss of use and business interruption.
Both plaintiffs claim the fire and explosion was caused, in part, by Genesis
selling to PQS crude oil that was contaminated with organic chlorides.
Management of the Partnership believes that the suit is without merit and
intends
to vigorously defend itself in this matter. Management of the Partnership
believes that any potential liability will be covered by insurance.
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. A portion of 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. The spill was cleaned up, with
ongoing monitoring and reduced clean-up activity expected to continue for an
undetermined period of time. The oil spill is covered by insurance and the
financial impact to the Partnership for the cost of the clean-up has not been
material.
The estimated cost of the spill clean-up is expected to be $20.2 million.
This amount includes actual clean-up costs and estimates for ongoing maintenance
and settlement of potential liabilities to landowners in connection with the
spill. The incident was reported to insurers. At December 31, 2000, $17.6
million had been paid to vendors and claimants for spill costs, and $2.6 million
was included in accrued liabilities for estimated future expenditures. Current
assets included $1.8 million of expenditures submitted and approved by insurers
but not yet reimbursed, $1.2 million for expenditures not yet submitted to
insurers and $2.6 million for expenditures not yet incurred or billed to the
Partnership. At December 31, 2000, $14.6 million in reimbursements had been
received from insurers.
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.
The segment of the Mississippi System where the spill occurred has been shut
down and will not be restarted until regulators give their approval. The
Partnership plans in 2001 to perform testing of the affected segment of the
pipeline at an estimated cost of $0.2 million to determine a course of action to
restart the system. 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. Subject to the results of
testing and regulatory approval, the Partnership intends to restart this segment
of the Mississippi System during the latter half of 2001.
If Management of the Partnership determines that the costs of additional
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 $0.3 million from the 2000 level 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 $5.7
million.
50
The Partnership is subject to lawsuits in the normal course of business and
examination 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.