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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, 1998
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 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
----- -----
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 New York Stock Exchange on March 1, 1999, was approximately $116 million.
<PAGE> 1
GENESIS ENERGY, L.P.
1998 FORM 10-K ANNUAL REPORT
Table of Contents
Page
----
Part I
Item 1. Business 3
Item 2. Properties 9
Item 3. Legal Proceedings 10
Item 4. Submission of Matters to a Vote of Security Holders 10
Part II
Item 5. Market for Registrant's Common Units and Related Security
Holder Matters 11
Item 6. Selected Financial Data 12
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations 13
Item 7a.Price Risk Management and Financial Instruments 19
Item 8. Financial Statements and Supplementary Data 19
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure 20
Part III
Item 10.Directors and Executive Officers of the Registrant 20
Item 11.Executive Compensation 22
Item 12.Security Ownership of Certain Beneficial Owners and Management 25
Item 13.Certain Relationships and Related Transactions 26
Part IV
Item 14.Exhibits, Financial Statement Schedules and Reports on Form 8-K 27
<PAGE> 2
PART I
Item 1. Business
General
Genesis Energy, L.P., a Delaware limited partnership, was formed in
December 1996. With the proceeds of an offering of common limited partnership
units ("Common Units") to the public, Genesis Energy, L.P., through its
affiliated limited partnership, Genesis Crude Oil, L.P., and its subsidiary
partnerships (collectively the "Partnership" or "Genesis") acquired the crude
oil gathering and marketing operations of Basis Petroleum, Inc. ("Basis") and
the crude oil gathering, marketing and pipeline operations of Howell Corporation
and its subsidiaries ("Howell"). The Partnership is one of the largest
independent gatherers and marketers of crude oil in North America. Genesis'
operations are concentrated in Texas, Louisiana, Alabama, Florida, Mississippi,
New Mexico, Kansas and Oklahoma. In its gathering and marketing business,
Genesis is principally engaged in the purchase and aggregation of crude oil at
the wellhead and the bulk purchase of crude oil at pipeline and terminal
facilities for resale at various points along the crude oil distribution chain,
which extends from the wellhead to aggregation and terminal facilities,
refineries and other end markets (the "Distribution Chain"). The Partnership's
gathering and marketing margins are generated by buying crude oil at competitive
prices, efficiently transporting or exchanging the crude oil along the
Distribution Chain and marketing the crude oil to refineries or other customers
at favorable prices. In addition to its gathering and marketing business,
Genesis' operations include transportation of crude oil at regulated published
tariffs on its three common carrier pipeline systems.
Genesis utilizes its trucking fleet of approximately 71 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 1998, Genesis purchased an average of approximately
114,000 bpd of crude oil at the wellhead from approximately 9,200 leases. In
the first quarter of 1999, the Partnership expects its wellhead purchases to
decrease by approximately 21,000 bpd of crude oil as a result of the loss of a
large contract with Pioneer Natural Resources USA, Inc. ("Pioneer"). Due to the
profit sharing nature of the contract with Pioneer, Genesis does not expect the
effect on gross margin to be material. Wellhead purchases in 1999 are also
expected to decrease due to natural declines in production where the Partnership
purchases crude oil with a resulting effect on gross margin.
Genesis currently transports a total of approximately 85,000 barrels per
day on its three common carrier crude oil pipeline systems and related gathering
lines. These systems are the Texas System, the Jay System extending between
Florida and Alabama, and the Mississippi System extending between Mississippi
and Louisiana. In October 1998, Genesis acquired 200 additional miles of
pipelines and gathering lines that have become part of its Texas System. This
additional pipeline mileage extends from the West Columbia area in Texas to
Webster, Texas. Approximately 2.0 million barrels of associated storage
capacity is owned by Genesis.
Genesis Energy, L.L.C. (the "General Partner"), a Delaware limited
liability company, serves as the sole general partner of Genesis Energy, L.P.,
and as the operating general partner of its affiliated limited partnership,
Genesis Crude Oil, L.P. (GCOLP) and GCOLP's subsidiary partnerships, Genesis
Pipeline Texas, L.P. and Genesis Pipeline USA, L.P. The General Partner is
owned 54% by Salomon Smith Barney Holdings Inc. ("Salomon") and 46% by Howell.
Salomon also owns 1,163,700 subordinated limited partner units in GCOLP,
representing 10.58% of GCOLP. Howell owns 991,300 subordinated limited partner
units in GCOLP, representing 9.01% of GCOLP. These subordinated limited partner
interests are hereinafter referred to as Subordinated OLP Units.
Business Overview
In its gathering and marketing business, the Partnership seeks to purchase
and sell crude oil at points along the Distribution Chain where gross margins
can be achieved. Genesis generally purchases crude oil at prevailing prices
from producers at the wellhead under short-term contracts or in bulk from major
oil companies, intermediaries and other third parties. Genesis then transports
the crude oil along the Distribution Chain for sale to or exchange with
customers. The Partnership's margins from its gathering and marketing
operations are generated by the difference between the price of crude oil at the
point of purchase and the price of crude oil at the point of sale, minus the
associated costs of aggregation and transportation. The Partnership utilizes
computerized
<PAGE> 3
management information systems to identify the optimal combination
of transportation and exchange transactions expected to result in the greatest
margin for each barrel of crude oil purchased. 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, have become increasingly important in creating and
maintaining margins. Such hedging techniques require significant resources
dedicated to managing forward positions and analyzing crude oil markets by grade
and location so as to manage these differentials. By analyzing information in
its database with internally developed software programs, Genesis is able to
monitor crude oil volumes, grades, locations and delivery schedules and to
coordinate marketing and exchange opportunities, as well as NYMEX hedging
positions. This coordination enables the Partnership to net positions
internally, thereby reducing NYMEX commissions, and further ensures that
Genesis' NYMEX hedging activities are consistent with its business objectives.
The effectiveness of risk management strategies will erode with volume erosion.
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 700 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
<PAGE> 4
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
1998, with its staff of division order specialists, Genesis distributed payments
to approximately 20,000 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,
1999, 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. If Genesis determines
that a customer should receive a credit line, it must then decide on the amount
of credit that should be extended. Since typical sales transactions can involve
tens of thousands of barrels of crude oil, the risk of nonpayment and
nonperformance by customers is a major consideration in Genesis' business.
Management believes that Genesis' sales are made to creditworthy entities or
entities with adequate credit support.
Credit review and analysis are also integral to Genesis' leasehold
purchases. Payment for all or substantially all of the monthly leasehold
production is sometimes made to the operator of the lease. The operator, in
turn, 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 a substantial
volume of domestic crude oil production throughout its area of operations. The
Partnership purchases leasehold barrels from more than 700 producers. In 1998,
approximately 49% of the leasehold barrels were purchased from ten producers,
with Pioneer accounting for 22% of 1998 leasehold purchases. The contract with
Pioneer expired December 31, 1998, and was not renewed. Genesis does not expect
the loss of the leasehold volumes purchased from Pioneer to have a material
effect on gross margin as these volumes were subject to a profit sharing
arrangement that limited the gross margin realized by the Partnership.
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 Scurlock Permian Oil Company,
Plains All American Pipeline, L.P., TEPPCO Partners, L.P., Texaco Trading &
Transportation Co., Inc., and EOTT Energy 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
<PAGE> 5
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, 1998, approximately
290 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. In January 1999, the number
of employees was reduced to approximately 260 as a result of changing business
conditions. These reductions were primarily truck drivers. None of the
employees is 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 law impose substantial penalties for violation of
these applicable requirements.
The Clean Water Act controls, among other things, the discharge of oil and
derivatives into certain surface waters. The Clean Water Act provides penalties
for any discharges of crude oil in harmful quantities and imposes liability for
the costs of removing an oil spill. State laws for the control of water
pollution also provide varying civil and criminal penalties and liabilities in
the case of a release of crude oil in surface waters or into the ground.
Federal and state permits for water discharges may be required. The Oil
Pollution Act of 1990 ("OPA"), as amended by the Coast Guard Authorization Act
of 1996, requires operators of offshore facilities to provide financial
assurance in the amount of $35 million to cover potential environmental cleanup
and restoration costs. This amount is subject to upward regulatory adjustment.
The Resource Conservation and Recovery Act regulates, among other things,
the generation, transportation, treatment, storage and disposal of hazardous
wastes. Transportation of petroleum, petroleum derivatives or other commodities
and maintenance activities may invoke the requirements of the federal statute,
or state counterparts, which impose substantial penalties for violation of
applicable standards.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
that are considered to have contributed to the release of a "hazardous
substance" into the environment. Such persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. Persons who are or were responsible for releases of hazardous substances
under CERCLA may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources, and it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances released
into the environment. In the ordinary course of the Partnership's operations,
substances may be generated or handled which fall within the definition of
"hazardous substances."
Under the National Environmental Policy Act ("NEPA"), a federal agency, in
conjunction with a permittee, may be required to prepare an environmental
assessment or a detailed environmental impact study before issuing a permit for
a pipeline extension or addition that would significantly affect the quality of
the environment. Should an environmental impact study or assessment be required
for any proposed pipeline extensions or additions, the effect of NEPA may be to
delay or prevent construction or to alter the proposed location, design or
method of construction.
<PAGE> 6
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 no knowledge of any outstanding liabilities or claims
relating to safety and environmental matters, individually or in the aggregate,
which would have a material adverse effect on the Partnership's financial
position or results of operations and that Partnership assets are in compliance
in all material respects with all applicable environmental laws and regulations.
No assurance can be given, however, as to the amount or timing of future
expenditures for environmental remediation or compliance, and actual future
expenditures may be different from the amounts currently anticipated.
Regulation
Pipeline regulation
Interstate Regulation Generally. The interstate common carrier pipeline
operations of the Jay and Mississippi systems are subject to rate regulation by
FERC under the Interstate Commerce Act ("ICA"). The ICA requires, among other
things, that to be lawful, petroleum pipeline rates be just and reasonable and
not unduly discriminatory. The ICA permits challenges to proposed new or
changed rates by protest and to rates that are already final and in effect by
complaint, and provides that upon an appropriate showing a complainant may
obtain reparations for damages sustained for a period of up to two years prior
to the filing of a complaint. Howell is responsible for any ICA liabilities
with respect to activities or conduct during periods prior to the closing of the
Partnership's initial public offering of Common Units, and the Partnership is
responsible for ICA liabilities with respect to activities or conduct
thereafter. The Partnership adopted all of Howell's tariffs in effect on the
date of the transfer of the assets to Genesis. None of the tariffs have been
subjected to a protest or complaint by any shipper or other interested party.
In general, the ICA requires that petroleum pipeline rates be cost based
and permits them to generate operating revenues on the basis of projected
volumes sufficient to cover, among other things, the following: (i) operating
expenses, (ii) depreciation and amortization, (iii) federal and state income
taxes determined on a separate company basis and adjusted or "normalized" to
reflect the impact of timing differences between book and tax accounting for
certain expenses, primarily depreciation and (iv) an overall allowed rate of
return on the pipeline's "rate base." Generally, rate base is a measure of
investment in or value of the common carrier assets which are used and useful in
providing the regulated services.
Effective January 1, 1995, FERC promulgated rules simplifying and
streamlining the ratemaking process. Previously established rates were
"grandfathered", limited the challenges that could be made to existing tariff
rates. Under the new regulations, petroleum pipelines are able to change their
rates within prescribed ceiling levels that are tied to the Producer Price Index
for Finished Goods, minus one percent. Rate increases made pursuant to the
index will be subject to protest, but such protests must show that the portion
of the rate increase resulting from application of the index is substantially in
excess of the pipeline's increase in costs. FERC's regulations provide, and a
recent FERC order in a contested pipeline rate proceeding affirms, that shippers
may not challenge that portion of the pipeline's rates which was grandfathered
whenever the pipeline files for its annual indexed rate increase; such
challenges are limited to the amount of the increase only unless, in a separate
showing, the complainant satisfies the threshold requirement to show that a
"substantial change" has occurred in the economic circumstances or the nature of
the pipeline's services. Rate decreases are mandated under the new regulations
if the index decreases and the carrier has been collecting rates equal to the
rate ceiling. The new indexing methodology can be applied to any existing rate,
including in particular all "grandfathered" rates, but also applies to rates
under
<PAGE> 7
investigation. If such rate is subsequently adjusted, the ceiling level
established under the index must be likewise adjusted.
The new indexation methodology is expected to cover all normal cost
increases. Cost-of-service ratemaking, while still available to the pipeline
for certain rate increases and to establish initial rates for new service, is
generally disfavored except in specified circumstances, primarily a substantial
divergence between the actual cost experienced by the carrier and the rate
resulting from the index such that the rate at the ceiling level would preclude
the carrier from being able to charge a just and reasonable rate. FERC
regulations also allow rate changes to occur through market- based rates (for
pipeline services which have been found to be eligible for such rates) and
through settlement rates, which are rates unanimously agreed by the carrier and
all shippers as appropriate. In respect of new facilities and new services
requiring the establishment of new, initial rates, the carrier may rely on
either cost-of-service ratemaking or may initiate service under rates which have
been contractually agreed with at least one nonaffiliated shipper; however,
other shippers may protest any new rates established in this manner, in which
event a cost-of-service showing is required.
Because of the novelty and uncertainty surrounding the indexing
methodology as well as numerous untested associated issues, the General Partner
is unable to predict with certainty whether, how or the extent to which FERC may
apply the methodologies to the Jay and Mississippi systems, which FERC
regulates. The General Partner adopted Howell's preexisting tariffs and rates
pertaining to the Jay and Mississippi Systems and intends to rely on the
indexation procedures available under FERC regulations. Nevertheless, by
protest, complaint or shipper challenge to the Partnership's grandfathered or
indexed rates, the Partnership could become involved in a cost-of-service
proceeding before FERC and be required to defend and support its rates based on
costs. In any such cost-of-service rate proceeding involving rates of the FERC-
regulated Jay and Mississippi Systems, FERC would be permitted to inquire into
and determine all relevant matters including such issues as (i) the appropriate
capital structure to be utilized in calculating rates, (ii) the appropriate rate
of return, (iii) the rate base, including the proper starting rate base, (iv)
the rate design and (v) the proper allowance for federal and state income taxes.
In addition to the regulatory considerations noted above, it is expected that
the interstate common carrier pipeline tariff rates will continue to be
constrained by competitive and other market factors.
Texas Intrastate Regulation
The intrastate common carrier pipeline operations of the Partnership in
Texas are subject to regulation by the Texas Railroad Commission. The
applicable Texas statutes require that pipeline rates be non-discriminatory and
provide a fair return on the aggregate value of the property of a common carrier
used and useful in the services performed after providing reasonable allowance
for depreciation and other factors and for reasonable operating expenses. There
is no case law interpreting these standards as used in the applicable Texas
statutes. This is because historically, as well as currently, the Texas
Railroad Commission has not been aggressive in regulating common carrier
pipelines such as those of the Partnership and has not investigated the rates or
practices of such carriers in the absence of shipper complaints, which have been
few and almost invariably settled informally. Given this history, although no
assurance can be given that the tariffs to be charged by the Partnership would
ultimately be upheld if challenged, the General Partner believes that the
tariffs now in effect can be sustained. Howell is responsible for any
liabilities under the applicable Texas statutes with respect to activities or
conduct during periods prior to the closing, and the Partnership is responsible
for such liabilities with respect to activities or conduct thereafter. The
Partnership adopted the tariffs in effect on the date of the closing of the
Partnership's initial public offering of Common Units.
Pipeline Safety Regulation
The Partnership's crude oil pipelines are subject to construction,
installation, operating and safety regulation by the Department of
Transportation ("DOT") and various other federal, state and local agencies. The
Pipeline Safety Act of 1992, among other things, amends the Hazardous Liquid
Pipeline Safety Act of 1979 ("HLPSA") in several important respects. It
requires the Research and Special Programs Administration ("RSPA") of DOT to
consider environmental impacts, as well as its traditional public safety
mandate, when developing pipeline safety regulations. In addition, the Pipeline
Safety Act mandates the establishment by DOT of pipeline operator qualification
rules requiring minimum training requirements for operators, and requires that
pipeline operators provide maps and records to RSPA. It also authorizes RSPA to
require that pipelines be modified to accommodate internal inspection devices,
to mandate the installation of emergency flow restricting devices for pipelines
in populated or sensitive areas, and to order other changes to the operation and
maintenance of petroleum pipelines. The Partnership has conducted hydrostatic
testing of most segments. Significant expenses could be
<PAGE> 8
incurred in the future
if additional safety measures are required or if safety standards are raised and
exceed the current pipeline control system capabilities.
States are largely preempted from regulating pipeline safety by federal
law but may assume responsibility for enforcing federal intrastate pipeline
regulations and inspection of intrastate pipelines. In practice, states vary
considerably in their authority and capacity to address pipeline safety. The
Partnership does not anticipate any significant problems in complying with
applicable state laws and regulations in those states in which it operates.
The Partnership's crude oil pipelines are also subject to the
requirements of the Federal Occupational Safety and Health Act ("OSHA") and
comparable state statutes. The General Partner believes that the Partnership's
crude oil pipelines have been operated in substantial compliance with OSHA
requirements, including general industry standards, record keeping requirements
and monitoring of occupational exposure to regulated substances.
In general, the General Partner expects to increase the Partnership's
expenditures in the future to comply with higher industry and regulatory safety
standards such as those described above. Such expenditures cannot be accurately
estimated at this time, although the General Partner does not expect that such
expenditures will have a material adverse impact on the Partnership, except to
the extent additional testing requirements or safety measures are imposed.
Trucking regulation
The Partnership operates its fleet of trucks as a private carrier.
Although a private carrier that transports property in interstate commerce is
not required to obtain operating authority from the ICC, the carrier is subject
to certain motor carrier safety regulations issued by the DOT. The trucking
regulations cover, among other things, driver operations, keeping of log books,
truck manifest preparations, the placement of safety placards on the trucks and
trailer vehicles, drug testing, safety of operation and equipment, and many
other aspects of truck operations. The Partnership is also subject to OSHA with
respect to its trucking operations.
Commodities regulation
The Partnership's price risk management operations are subject to
constraints imposed under the Commodity Exchange Act and the rules of the NYMEX.
The futures and options contracts that are traded on the NYMEX are subject to
strict regulation by the Commodity Futures Trading Commission.
Information Regarding Forward-Looking Information
The statements in this Annual Report on Form 10-K that are not historical
information are forward looking statements within the meaning of Section 27a of
the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934. Although the Partnership believes that its expectations regarding future
events are based on reasonable assumptions, it can give no assurance that its
goals will be achieved or that its expectations regarding future developments
will prove to be correct. Important factors that could cause actual results to
differ materially from those in the forward looking statements herein include
changes in regulations, the Partnership's success in obtaining additional lease
barrels, changes in crude oil production volumes (both world-wide as well as in
areas in which the Partnership has operations), developments relating to
possible acquisitions or business combination opportunities, volatility of crude
oil prices and grade differentials, the success of the Partnership's risk
management activities, the Partnership's ability to replace its credit support
from Salomon with a bank facility, the Partnership's success in dealing with the
Year 2000 issue and the related costs of the Year 2000 issue and conditions of
the capital markets and equity markets during the periods covered by the forward
looking statements.
Item 2. Properties
The Partnership owns and operates three common carrier crude oil pipeline
systems. The pipelines and related gathering systems consist of the 750-mile
Texas system, the 117-mile Jay System extending between Florida and Alabama, and
the 281-mile Mississippi System extending between Mississippi and Louisiana.
The Partnership also owns approximately 2.0 million barrels of storage capacity
associated with the pipelines. These storage capacities include approximately
200,000 barrels each on the Mississippi and Jay Systems and 1.4 million barrels
on the Texas System, primarily at the Satsuma terminal in Houston, Texas.
In addition to transporting crude oil by pipeline, the Partnership transports
crude oil through a fleet of owned and leased tractors and trailers. At
December 31, 1998, the trucking fleet consisted of approximately 92 tractor-
trailers. In February 1999, the trucking fleet was reduced to 71 tractor-
trailers through the sale of excess equipment.
<PAGE> 9
The trucking fleet generally
hauls the crude oil to one of the approximately 100 pipeline injection stations
owned or leased by the Partnership.
Item 3. Legal Proceedings
The Partnership is involved from time to time in various claims, lawsuits and
administrative proceedings incidental to its business. In the opinion of
management of the General Partner, the ultimate outcome, if any, will not have a
material adverse effect on the financial condition or results of operations of
the Partnership. See Note 16 of Notes to Consolidated Financial Statements.
Item 4. Submission of Matters to a Vote of Security Holders
There were no matters submitted to a vote of security holders during the year
ended December 31, 1998.
<PAGE> 10
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.
<TABLE>
<CAPTION>
Price Range
---------------------- Cash
High Low Distributions<F1>
-------- -------- ---------------
1998
----
<S> <C> <C> <C>
First Quarter $20.3750 $16.6250 $0.50
Second Quarter $19.8750 $17.2500 $0.50
Third Quarter $18.0000 $13.6875 $0.50
Fourth Quarter $19.1250 $13.6250 $0.50
1997
----
First Quarter $21.5000 $20.3750 $ -
Second Quarter $21.3750 $18.1250 $0.66
Third Quarter $20.7500 $19.6250 $0.50
Fourth Quarter $21.2500 $16.3750 $0.50
_____________________
<FN>
<F1> Cash distributions are shown in the quarter paid and are based on the
prior quarter's activities. The second quarter of 1997 was prorated for the
period between the closing of the Initial Public Offering and March 31, 1997
based on a minimum quarterly distribution of $0.50 per Common Unit per quarter.
</FN>
</TABLE>
As of December 31, 1998, there were approximately 11,000 record holders and
beneficial owners (held in street name) of the Partnership's Common Units.
There is no established public trading market for the Partnership's Subordinated
OLP Units. The Partnership will distribute 100% of its Available Cash as
defined in the Partnership Agreement within 45 days after the end of each
quarter to Unitholders of record and to the General Partner. Available Cash
consists generally of all of the cash receipts less cash disbursements of the
Partnership adjusted for net changes to reserves. The full definition of
Available Cash is set forth in the Partnership Agreement and amendments thereto,
a form of which is filed as an exhibit hereto. Distributions of Available Cash
to the Subordinated Unitholders will be subject to the prior rights of the
Common Unitholders to receive the Minimum Quarterly Distribution ("MQD") for
each quarter during the subordination period, which will not end earlier than
December 31, 2001, and to receive any arrearages in the distribution of the MQD
on the Common Units for prior quarters during the subordination period.
In connection with the Partnership's initial public offering of Common Units
in December 1996, Salomon and the Partnership entered into a Distribution
Support Agreement pursuant to which, among other things, Salomon agreed that it
would contribute up to $17.6 million to the Partnership in exchange for
Additional Partnership Interests ("APIs"), if necessary, to support the
Partnership's ability to pay the MQD on Common Units. Salomon's obligation to
purchase APIs will end no earlier than December 31, 1999 and end no later than
December 31, 2001, with the actual termination subject to the levels of
distributions that have been made prior to the termination date. At December
31, 1998, Salomon had not been required to provide any distribution support. As
a result of poor domestic crude oil market conditions, the General Partner may
have to draw on the cash distribution support from Salomon during 1999.
<PAGE> 11
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, 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 was treated as a
purchase for accounting purposes.
<TABLE>
<CAPTION>
Eleven
Year Year Year One Month Months
Ended Ended Ended Ended Ended Year Ended
December 31,December 31,December 31,December 31,November 30, December 31,
1998 1997 1996 <F1> 1996 1996 1995 1994
---------------------------------------------------------------------------------
(Pro forma) (Predecessor) (Predecessor)
(Unaudited)
<S> <C> <C> <C> <C> <C> <C> <C>
Income Statement Data:
Revenues:
Gathering and marketing revenues $2,216,942 $3,354,939 $4,565,834 $370,559 $3,598,107 $3,440,065 $1,830,721
Pipeline revenues 16,533 17,989 16,780 1,426 - - -
---------- ---------- ---------- -------- ---------- ---------- ----------
Total revenues 2,233,475 3,372,928 4,582,614 371,985 3,598,107 3,440,065 1,830,721
Cost of sales:
Crude cost 2,184,529 3,331,184 4,526,363 366,723 3,573,086 3,409,759 1,806,241
Field operating costs 12,778 12,107 15,092 1,290 6,744 7,152 7,778
Pipeline operating costs 7,971 6,016 4,978 463 - - -
---------- ---------- ---------- -------- ---------- ---------- ----------
Total cost of sales 2,205,278 3,349,307 4,546,433 368,476 3,579,830 3,416,911 1,814,019
---------- ---------- ---------- -------- ---------- ---------- ----------
Gross margin 28,197 23,621 36,181 3,509 18,277 23,154 16,702
General and administrative expenses 11,468 8,557 9,470 1,363 3,316 3,658 3,858
Depreciation and amortization 7,719 6,300 6,834 518 1,396 4,815 7,530
Nonrecurring charge 373 - - - - - -
---------- ---------- ---------- -------- ---------- ---------- ----------
Operating income 8,637 8,764 19,877 1,628 13,565 14,681 5,314
Interest income (expense) 154 1,063 56 56 294 173 (685)
Other income (expense) 28 21 (74) - (83) (197) 82
---------- ---------- ---------- -------- ---------- ---------- ----------
Net income before minority interests 8,819 9,848 19,859 1,684 13,776 14,657 4,711
Minority interests 1,763 1,968 3,970 337 - - -
---------- ---------- ---------- -------- ---------- ---------- ----------
Net income <F2> $ 7,056 $ 7,880 $ 15,889 $ 1,347 $ 13,776 $ 14,657 $ 4,711
========== ========== ========== ======== ========== ========== ==========
Net income per common unit-basic
and diluted $ 0.80 $ 0.90 $ 1.81 $ 0.15 N/A N/A N/A
========== ========== ========== ========
Balance Sheet Data (at end of period):
Current assets $ 185,216 $ 232,202 $ 410,371 $ 410,371 N/A $ 279,285 $ 184,253
Total assets 297,173 331,114 509,900 509,900 N/A 283,036 193,367
Long-term liabilities 15,800 - - - N/A - -
Equity of parent - - - - N/A (8,437) 4,393
Minority interest 29,988 28,225 26,257 26,257 N/A - -
Partners' capital 67,871 78,351 85,080 85,080 N/A - -
Other Data:
Maintenance capital expenditures <F3> $ 1,509 $ 3,785 $ 2,535 $ 106 $ 1,100 $ 17 $ 56
EBITDA <F4> $ 16,384 $ 15,085 $ 26,637 $ 2,146 $ 14,878 $ 19,299 $ 12,926
Volumes (bpd):
Gathering and marketing:
Wellhead 114,400 104,506 116,263 120,553 83,239 83,551 89,788
Bulk and exchange 325,468 346,760 463,054 380,354 417,939 439,060 214,519
Pipeline 85,594 89,117 86,557 85,874 - - -
<FN>
<F1> 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. See Note 2 of Notes to
the Consolidated Financial Statements for a description of the pro forma
adjustments.
<F2> Net income excludes the effect of income taxes and accounting changes for
the Predecessor.
<F3> The General Partner estimates that capital expenditures necessary to
maintain the existing asset base at current operating levels will be $3
million each year.
<F4> 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).
</FN>
</TABLE>
<PAGE> 12
The table below summarizes the Partnership's quarterly financial data for
1998 and 1997.
1998 Quarters
--------------------------------------
First Second Third Fourth
-------- -------- -------- --------
(Unaudited)
Revenues $650,257 $561,813 $526,442 $494,963
Gross margin $ 6,336 $ 6,047 $ 8,432 $ 7,382
Operating income $ 1,962 $ 889 $ 3,365 $ 2,421
Net income $ 1,728 $ 811 $ 2,662 $ 1,855
Net income per Common Unit-basic
and diluted $ 0.20 $ 0.09 $ 0.30 $ 0.21
1997 Quarters
---------------------------------------
First Second Third Fourth
--------- -------- -------- --------
(Unaudited)
Revenues $ 946,482 $890,686 $844,778 $690,982
Gross margin $ 7,034 $ 4,939 $ 5,939 $ 5,709
Operating income $ 3,336 $ 1,192 $ 2,320 $ 1,916
Net income $ 2,744 $ 1,282 $ 2,089 $ 1,765
Net income per Common Unit-basic
and diluted $ 0.31 $ 0.15 $ 0.24 $ 0.20
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,
-----------------------------------
1998 1997 1996
---------- ---------- ----------
(Pro forma)
(Unaudited)
Revenues
Gathering & marketing $2,216,942 $3,354,939 $4,565,834
Pipeline $ 16,533 $ 17,989 $ 16,780
Gross margin
Gathering & marketing $ 19,635 $ 11,648 $ 24,379
Pipeline $ 8,562 $ 11,973 $ 11,802
General and administrative expenses $ 11,468 $ 8,557 $ 9,470
Depreciation and amortization $ 7,719 $ 6,300 $ 6,834
Operating income $ 8,637 $ 8,764 $ 19,877
Interest income, net $ 154 $ 1,063 $ 56
The profitability of Genesis depends to a significant extent upon its
ability to maximize gross margin. The gross margin from gathering and marketing
operations is generated by the difference between the price of crude oil at the
point of purchase and the price of crude oil at the point of sale, minus the
associated costs of aggregation and transportation. In addition to purchasing
crude oil at the wellhead, Genesis purchases crude oil in bulk at major pipeline
terminal points and enters into exchange transactions with third parties. These
bulk and exchange transactions are characterized by large volumes and narrow
profit margins on purchase and sales transactions, and the absolute price levels
for crude oil do not necessarily bear a relationship to gross margin, although
such price levels significantly impact revenues and cost of sales. Because
period-to-period variations in revenues and cost of sales are not generally
meaningful in analyzing the variation in gross margin for gathering and
marketing
<PAGE> 13
operations, such changes are not addressed in the following
discussion. 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.
Gross margin from gathering, marketing and pipeline operations varies from
period to period, depending to a significant extent upon changes in the supply
and demand of crude oil and the resulting changes in U.S. crude oil inventory
levels. In general, gathering and marketing gross margin increases when crude
oil inventories decline, resulting in crude oil for prompt (generally the next
month) delivery being priced at an increased premium over crude oil for future
delivery.
Year Ended December 31, 1998 Compared with Year Ended December 31, 1997
Gross Margin. Gathering and marketing gross margins increased $7.9
million or 68% to $19.6 million for the year ended December 31, 1998, as
compared to $11.7 million for the year ended December 31, 1997. The increase in
gross margin can be attributed to the acquisition of the gathering and marketing
assets of Falco S&D, Inc., ("Falco") in April 1998 and improvements in the
relationships between various market prices during 1998, allowing the
Partnership to apply its risk management techniques to forward purchases and
sales opportunities to increase gross margin. There can be no assurance of the
availability of future opportunities to apply the Partnership's risk management
techniques.
By the end of 1998, price levels for crude oil had declined
approximately 39% from prices at the beginning of 1998. While the decline in
price levels, as stated above, does not directly impact the Partnership's gross
margins, the decline generally does reduce the quantities of crude oil available
for purchase at the wellhead due to curtailed production and drilling activity.
Through the acquisition of the gathering and marketing assets of Falco in April
1998, the Partnership was able to improve its average wellhead volumes over 1997
levels, although volumes in the fourth quarter had declined to an average of
107,758 barrels per day. The Partnership expects volumes to decline further in
the first quarter of 1999 due to reduced crude oil price levels and the loss of
the contract with Pioneer. Due to the profit-sharing aspects of that contract,
the Partnership does not expect the impact on gross margin from the loss of the
Pioneer contract to be material, however the overall volume decrease in U.S.
domestic crude oil production may have an adverse effect on future gross
margins.
Pipeline gross margin decreased $3.4 million or 28% to $8.6 million for
the year ended December 31, 1998, as compared to $12.0 million for the year
ended December 31, 1997. The Partnership experienced a decline in its daily
throughput volumes of 8%, decreasing pipeline revenues by $1.5 million. In
October 1998, the Partnership acquired 200 additional miles of pipeline in the
West Columbia area of Texas. This addition resulted in a restoration of
throughput volumes by the end of 1998 to levels at the beginning of the year.
Throughput volumes on the existing pipelines declined in 1998 as oil producers
reduced exploration and production volumes in areas serviced by the
Partnership's pipelines. Decreases in production volumes in areas serviced by
the Partnership's pipelines could have an adverse effect on future gross margin.
Also contributing to the decline in pipeline gross margins were higher
operating costs in 1998. These higher costs can be attributed to lease payments
beginning in the second quarter of 1998 on a new segment of pipeline, repairs on
the Main Pass pipeline prior to its shut-in, and increased routine maintenance
expenditures.
General and administrative expenses. In 1998, general and
administrative expenses increased by $2.9 million or 34% to $11.5 million. This
increase can be attributed primarily to three factors. First, the estimated
total charge for the Restricted Unit Plan is being recognized over the three-
year vesting period beginning in 1998. In 1998, that noncash charge was $1.6
million. Second, in 1998 the Partnership no longer benefited from the sharing
of certain costs with Basis under the terms of a Corporate Services Agreement as
it did in 1997. Third, costs increased due to the addition of marketing and
administrative personnel by the Partnership in April 1998 as a result of the
Falco asset acquisition.
Depreciation and amortization. Depreciation and amortization increased
from $6.3 million in 1997 to $7.7 million in 1998, primarily attributable to
depreciation and amortization on the assets acquired from Falco.
Nonrecurring charge. In 1998, the Partnership recorded a non-recurring
charge of $0.4 million as a result of the shut-in of its Main Pass pipeline
located offshore. The charge consisted of $0.1 million of costs related to the
shut-in and a $0.3 million write-down of the asset.
<PAGE> 14
Interest income (expense), net. Net interest income declined $0.8
million or 89% to $0.2 million for the year ended December 31, 1998 as compared
to $1.0 million for the year ended December 31, 1997. As a result of the
acquisition of the assets of Falco and the pipeline near West Columbia, Texas,
in 1998, the Partnership had less cash available to temporarily invest.
Interest expense increased as the Partnership borrowed funds under its loan
agreement during the year.
Year Ended December 31, 1997 Compared with Pro Forma Year Ended December
31, 1996
The following analysis compares the results of operations for the
Partnership for the year ended December 31, 1997 to the pro forma results of the
Partnership for the year ended December 31, 1996. The pro forma consolidated
financial statements of the Partnership reflect the historical operating results
of the crude oil gathering and marketing operations of Basis and the crude oil
gathering, marketing and pipeline transportation operations of Howell. Because
the Partnership had no long-term debt, the pro forma consolidated results
reflect the elimination of interest expense. Income taxes were also eliminated
from the pro forma consolidated results as the Partnership is not subject to
federal income taxes.
Gross Margin. Gathering and marketing gross margins decreased $12.7
million or 52% to $11.7 million for the year ended December 31, 1997, as
compared to $24.4 million for the year ended December 31, 1996. Field operating
expenses decreased $3.0 million, primarily due to a reduction in the number of
tractor-trailers. The reduction in the fleet size resulted from efficiencies
from the combination of the Howell and Basis fleets.
In 1996, crude oil inventories were at low levels and demand for crude
oil by refiners was strong. Gathering and marketing margins expanded as sale
prices increased faster than prices paid to producers for crude oil and the
wellhead. In 1997, crude oil supply exceeded refiner demand and gathering and
marketing margins declined as sale prices decreased much quicker than prices
paid to producers to acquire the crude oil. Margins in the 1997 period were
also adversely impacted by increases in the cost to exchange sweet and sour
grades of crude oil at Midland, Texas, for West Texas Intermediate at Cushing,
Oklahoma.
Pipeline gross margin increased $0.2 million or 2% to $12.0 million for
the year ended December 31, 1997, as compared to $11.8 million for the year
ended December 31, 1996. Daily pipeline throughput volumes increased 3%,
increasing pipeline revenues by $1.2 million. In 1997, the Partnership began
transporting crude from a new area in Texas, increasing its revenues. Costs
associated with transporting this crude are generally higher than the costs
associated with the other crude the Partnership transports.
General and Administrative Expenses. In 1997, general and
administrative expenses decreased by $0.9 million or 10% to $8.6 million.
Efficiencies from the combination of the Howell and Basis staffs contributed to
this decline. In addition, the Partnership benefited from the sharing of
certain services during the period in which Basis provided services to the
Partnership under the terms of a Corporate Services Agreement.
Depreciation and Amortization. Depreciation and amortization expense
decreased $0.5 million or 8% to $6.3 million for the year ended December 31,
1997, as compared to $6.8 million for the year ended December 31, 1996. The
reduction resulted partly from the full amortization of some assets contributed
to the Partnership by Basis.
Liquidity and Capital Resources
Cash Flows
Net cash provided by operations was $16.4 million for the year ended
December 31, 1998 as compared to $20.2 million for the year ended December 31,
1997. The decrease in cash flow in 1998 was due primarily to the timing of
payment of obligations. Net cash used in operating activities was $0.8 million
for the one-month ended December 31, 1996. The decrease in cash flow from the
formation of the Partnership to December 31, 1996 was due primarily to increases
in inventories. Net cash used in operating activities of the Predecessor was
$2.6 million for the eleven months ended November 30, 1996.
Net cash used in investing activities was $17.5 million and $5.7 million
for the years ended December 31, 1998 and 1997, respectively, due primarily to
asset additions. In 1998, the Partnership acquired the gathering and marketing
assets of Falco, a pipeline near West Columbia, Texas, and other pipeline
property additions. In 1997, cash was used primarily for pipeline property
additions. Net cash used in investing activities was $74.1 million for the one
month ended December 31, 1996. This amount primarily relates to the cash
expended to acquire the Howell operations. For the eleven months ended November
30, 1996, net cash used in investing activities for
<PAGE> 15
the Predecessor was $2.0
million primarily from the purchase of 26 new tractors and NYMEX seats
contributed to Genesis.
Net cash used in financing activities was $3.0 million and $14.6 million
for the years ended December 31, 1998 and 1997, respectively. In 1998 the
Partnership paid distributions to the Common Unitholders and the General Partner
totaling $17.6 million. The Partnership also paid $1.2 million to acquire
treasury units in the open market, some of which were subsequently reissued
under the Restricted Unit Plan. Cash flows from financing activities were
provided by borrowings in the amount of $15.8 million under the loan agreement.
Cash flows utilized in 1997 related to the payment of distributions to the
Common Unitholders and the General Partner. Net cash provided by financing
activities for the one month ended December 31, 1996, was $79.5 million,
consisting of the net public offering proceeds and general partner contribution
at formation of the Partnership totaling $165.9 million, offset by the
distribution to Basis at formation of $87.0 million. Net cash provided by
financing activities for the eleven months ended November 30, 1996 and net cash
used by financing activities for the year ended December 31, 1995 resulted from
advances between Basis and the Predecessor.
Capital Expenditures
In 1998, the Partnership expended $16.2 million for capital expenditures
for projects related to the expansion of its business activities and $1.5
million for maintenance capital expenditures. The expansion projects included
the acquisition of the gathering and marketing assets of Falco, located
primarily in Louisiana and East Texas and the acquisition of 200 miles of
pipeline in the West Columbia area of Texas. This pipeline begins in Jackson
County, Texas, and ends at Genesis' Webster Station in Harris County.
In 1997, the Partnership made a one-time expenditure of $1.5 million for
furnishings for new offices. Additionally, the Partnership expended $2.3
million for capital expenditures relating to its existing operations and $2.2
million for project additions. The principal project addition related to
expenditures needed to enable the Partnership to transport in its pipelines the
crude from a new area in Texas. Capital expenditures for the one month ended
December 31, 1996 and eleven months ended November 30, 1996 were $0.1 million
and $1.1 million, respectively. In each period, these expenditures were
maintenance capital expenditures. In the year ended December 31, 1995, capital
expenditures by the Predecessor were less than $0.1 million.
Maintenance capital expenditures on a pro forma basis for the year ended
December 31, 1996 were $2.5 million. The Partnership estimates future
maintenance capital expenditures to be approximately $3.0 million per year.
These expenditures are expected to be primarily for improvements related to the
three principal pipeline systems and for the periodic replacement of tractors
and trailers in the Partnership's fleet. The Partnership expects to fund its
maintenance capital expenditure requirements from internally generated cash.
Working Capital and Credit Resources
Pursuant to the Master Credit Support Agreement, Salomon is providing
credit support in the form of a Guaranty Facility over a period of approximately
three years 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, 1999 (to be reduced in each case by the amount of
any obligation to a third party to the extent that such party has a prior
security interest in the collateral under the Master Credit Support Agreement).
The Partnership is required to pay a guaranty fee to Salomon which will increase
over the remaining year, thereby increasing the cost of the credit support
provided to the Partnership under the Guaranty Facility.
At December 31, 1998, the aggregate amount of obligations covered by
guarantees was $152 million, including $89 million in payable obligations and
$63 million in estimated crude oil purchase obligations for January 1999.
Salomon received a security interest in all the Partnership's
receivables, inventories, general intangibles and cash to secure obligations
under the Master Credit Support Agreement. Salomon provided a Working Capital
Facility to the Partnership until August 1998. At that time, the Working Capital
Facility was replaced with a revolving credit/loan agreement ("Loan Agreement")
with Bank One, Texas, N.A. ("Bank One"). The Loan Agreement provides for loans
or letters of credit in the aggregate not to exceed the greater of $35 million
or the Borrowing Base (as defined in the Loan Agreement). Loans will bear
interest at a rate chosen by GCOLP which would be one or more of the following:
(a) a Floating Base Rate (as defined in the Loan Agreement) that is generally
the prevailing prime rate less one percent; (b) a rate based on the Federal
Funds Rate plus one and one-half percent or (c) a rate based on LIBOR plus one
and one-quarter percent. The Loan Agreement provides for a
<PAGE> 16
revolving period
until August 14, 2000, during which time interest will be paid monthly. All
loans outstanding on August 14, 2000, are due at that time.
The Loan Agreement is collateralized by the accounts receivable and
inventory of GCOLP, subject to the terms of an Intercreditor Agreement between
Bank One and Salomon. There is no compensating balance requirement under the
Loan Agreement. A commitment fee of 0.35% on the available portion of the
commitment is provided for in the agreement. Material covenants and
restrictions include requirements to maintain a ratio of current assets (as
defined in the Loan Agreement) to current liabilities of at least 1:1 and to
maintain tangible net worth in GCOLP, as defined in the Loan Agreement, of $65
million.
At December 31, 1998, the Partnership had $15.8 million of loans
outstanding under the Loan Agreement. The Partnership had no letters of credit
outstanding at December 31, 1998. At December 31, 1998, $19.2 million was
available to be borrowed under the Loan Agreement.
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 three-year credit support period expires in
December 1999. In addition, if the General Partner is removed without its
consent, Salomon's credit support obligations will terminate. In addition,
Salomon's obligations under the Master Credit Support Agreement may be
transferred or terminated early subject to certain conditions. Management of
the Partnership intends to replace the Guaranty Facility with a letter of credit
facility with one or more third party lenders prior to December 1999 and has had
preliminary discussions with banks about a replacement letter of credit
facility. The General Partner may be required to reduce or restrict the
Partnership's gathering and marketing activities because of limitations on its
ability to obtain credit support and financing for its working capital needs.
The General Partner expects that the overall cost of a replacement facility may
be substantially greater than what the Partnership is incurring under its
existing Master Credit Support Agreement. Any significant decrease in the
Partnership's financial strength, regardless of the reason for such decrease,
may increase the number of transactions requiring letters of credit or other
financial support, make it more difficult for the Partnership to obtain such
letters of credit, and/or may increase the cost of obtaining them. This
situation could in turn adversely affect the Partnership's ability to maintain
or increase the level of its purchasing and marketing activities or otherwise
adversely affect the Partnership's profitability and Available Cash.
Distributions
Generally, GCOLP will distribute 100% of its Available Cash within 45
days after the end of each quarter to Unitholders of record and to the General
Partner. Available Cash consists generally of all of the cash receipts less
cash disbursements of GCOLP adjusted for net changes to reserves. (A full
definition of Available Cash is set forth in the Partnership Agreement.)
Distributions of Available Cash to the holders of Subordinated OLP Units are
subject to the prior rights of holders of Common Units to receive the minimum
quarterly distribution ("MQD") for each quarter during the subordination period
(which will not end earlier than December 31, 2001) and to receive any
arrearages in the distribution of the MQD on the Common Units for prior quarters
during the subordination period. MQD is $0.50 per unit.
Salomon has committed, subject to certain limitations, to provide total
cash distribution support, with respect to quarters ending on or before December
31, 2001, in an amount up to an aggregate of $17.6 million in exchange for
Additional Partnership Interests ("APIs"). Salomon's obligation to purchase
APIs will end no later than December 31, 2001, with the actual termination
subject to the levels of distributions that have been made prior to the
termination date. Any APIs purchased by Salomon are not entitled to cash
distributions or voting rights. The APIs will be redeemed if and to the extent
that Available Cash for any future quarter exceeds an amount necessary to
distribute the MQD on all Common Units and Subordinated OLP Units and to
eliminate any arrearages in the MQD on Common Units for prior periods.
In 1998, the Partnership paid total distributions of $2.00 per unit to
the Common Unitholders and the General Partner. This amount represented
distributions for the period from October 1, 1997 to September 31, 1998. A
distribution of $0.50 per unit, applicable to the fourth quarter of 1998, was
paid on February 12, 1999 to holders of record on January 29, 1999. In 1997,
the Partnership paid total distributions of $1.66 per unit, representing
distributions for the period from the Partnership's inception in December 1996
through September 30, 1997.
As a result of poor domestic crude oil market conditions, the General
Partner may have to draw on the cash distribution support from Salomon during
1999.
<PAGE> 17
Year 2000 Issue
Many software applications, equipment and embedded chip systems identify
dates using only the last two digits of the year. These systems may be unable
to distinguish between dates in the year 2000 and the year 1900. If not
addressed, this condition could cause such systems to fail or provide incorrect
information when using dates after December 31, 1999. Due to the Partnership's
dependence on such systems, this condition could have an adverse effect on the
Partnership.
Partnership's State of Readiness
To address the Year 2000 issue, the Partnership has formed a Year 2000
Steering Committee to coordinate execution of a project to identify, assess, and
remedy any critical Year 2000 issues that might impact the Partnership ("Year
2000 Project" or "the Project"). The Year 2000 Project Steering Committee has
established six phases for the Project. The six phases include (i) awareness,
(ii) inventory, (iii) assessment, (iv) remediation, (v) testing and (vi)
implementation. The Year 2000 Steering Committee has classified the key
automated systems for analysis as (a) financial systems applications, (b)
operational system applications, (c) hardware and equipment, (d) embedded chip
systems and (e) third-party systems. The Year 2000 Project includes addressing
the Year 2000 exposure of third parties whose operations are material to the
operations of the Partnership. The Partnership has retained a Year 2000
consulting firm to review the Partnership's Year 2000 Project Plan, execution of
that Plan and associated contingency plans. The Year 2000 consulting firm
reports its findings to the Year 2000 Steering Committee periodically. The
status of the Year 2000 Project is reviewed with the Board of Directors at its
quarterly meetings.
The awareness phase of the Year 2000 project consists of an enterprise-
wide awareness program to communicate to employees and other stakeholders the
Year 2000 problems, the issues affecting the Partnership, the processes to be
applied to the Project and to solicit participation to enhance the likelihood of
success of this Project. The initial awareness phase activities have been
completed; however, activities associated with the awareness phase will continue
throughout the course of the Project.
The inventory phase entails identifying all software applications,
equipment, embedded chip systems and third-party systems that should be
evaluated as part of this Project. All applications, equipment and systems have
been identified for evaluation. Due to the dynamic nature of systems in the
operations of the Partnership, the identification phase will be updated and
reassessed throughout the course of the Project. A Year 2000 Change Management
Program is being developed to monitor and control system changes that could
affect the Partnership's Year 2000 Project.
The assessment phase includes analysis and testing of inventoried
applications, equipment and systems to determine the business impact,
probability of failure and identification of the proper course of action to
achieve Year 2000 compliance. All systems have been analyzed to determine the
business impact of failure. All critical applications, equipment and systems
have been assessed as to the probability of failure. The determination of the
proper course of action for all critical applications, equipment and systems
that are not yet compliant is substantially complete.
The assessment phase of the project includes reasonable efforts to
obtain representation and assurances from third parties that their applications,
hardware and equipment, and systems being used by or impacting the Partnership
are or will be modified to be Year 2000 compliant. To date, the responses from
such third parties are positive but inconclusive. As a result, management
cannot predict the potential consequences to the Partnership if applications,
hardware or systems under the control of third parties are not Year 2000
compliant.
The remediation phase will include the modification, conversion or
replacement of existing applications, hardware and systems that are determined
not to be Year 2000 compliant. A software consulting firm has been engaged to
perform the remediation phase on the Partnership's critical financial and
operational systems that are to be modified or converted. Remediation of all
other critical systems is currently underway and is expected to be completed by
the end of the second quarter of 1999 or shortly thereafter.
The testing phase will validate the results of the remediation phase.
The implementation phase will perform business system modifications for
applications, hardware and systems that are affected by the remediation phase.
Management expects that the testing and implementation phases will be
substantially completed during the third quarter of 1999. Since the Partnership
does not expect to materially change operating processes as part of the Year
2000 Project, management does not expect the implementation phase to be a
significant part of the Project.
<PAGE> 18
Costs of the Year 2000 Project
While the total cost of the Year 2000 Project is still under evaluation,
management currently estimates that the total costs to be incurred by the
Partnership for the Year 2000 Project will be between $400,000 and $600,000.
The Partnership expects to fund these expenditures with cash from operations or
borrowings. Cash expenditures through December 31, 1998 were approximately
$100,000. The Partnership does not separately track the internal costs incurred
for the Year 2000 Project. Internal costs are primarily the payroll related
costs for the Partnership's information systems group, Year 2000 Steering
Committee members and other operations personnel involved in the Project.
Management has not deferred specific information technology projects as a direct
result of the Year 2000 issue.
Risk of Year 2000 Issues
Major applications that pose the greatest Year 2000 risks for the
Partnership if the Year 2000 Project is not successful are the Partnership's
financial and operational system applications and embedded chip systems in field
equipment. Potential problems resulting if the Year 2000 Project is not
successful include disruptions of the Partnership's financial and operational
functions. Affected financial functions include the ability to collect revenue,
issue payments and carry on commercial and banking transaction execution
activities. Operational functions that could be disrupted include the
Partnership's crude oil transportation, storage, gathering and marketing
activities.
Contingency Plans
The goal of the Year 2000 Project is to ensure that all critical systems
and business processes under the direct control of the Partnership remain
functional. However, since certain systems and processes may be interrelated
with systems outside of the control of the Partnership, there can be no
assurance that the Year 2000 Project will be completely successful.
Consequently, contingency and business plans are being developed to respond to
any Year 2000 compliance failures that may occur. Such plans are expected to be
completed by the end of the third quarter of 1999.
Management does not expect the costs of the Year 2000 project to have a
material adverse effect on the Partnership's financial position, results of
operations or cash flows. At this time, however, the Partnership cannot
conclude that any failure of the Partnership or third parties to achieve Year
2000 compliance will not adversely affect the Partnership.
Item 7a. Price Risk Management and Financial Instruments
The Partnership's primary price risk relates to the effect of crude oil price
fluctuations on its inventories and the fluctuations each month in grade and
location differentials and their effects on future contractual commitments. The
Partnership utilizes New York Mercantile Exchange ("NYMEX") commodity based
futures contracts, forward contracts, swap agreements and option contracts to
hedge its exposure to these market price fluctuations. Management believes the
hedging program has been effective in minimizing overall price risk. At
December 31, 1998, the Partnership used futures and forward contracts
exclusively in its hedging program with the latest contract being settled in
January 2000. Information about these contracts is contained in the table set
forth below.
Sell (Short) Buy (Long)
Contracts Contracts
------------ ----------
Commodity Futures Contracts
Contract volumes (1,000 bbls) 14,424 13,552
Weighted average price per bbl $ 12.94 $ 12.96
Contract value (in thousands) $186,655 $175,631
Fair value (in thousands) $176,843 $166,425
Commodity Forward Contracts:
Contract volumes (1,000 bbls) 5,469 6,288
Weighted average price per bbl $ 11.88 $ 12.25
Contract value (in thousands) $64,966 $77,010
Fair value (in thousands) $64,975 $75,453
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
<PAGE> 19
amount in barrels multiplied by the December 31, 1998 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 30.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosures
None.
Part III
Item 10. Directors and Executive Officers of the Registrant
The Partnership does not directly employ any persons responsible for managing
or operating the Partnership or for providing services relating to day-to-day
business affairs. The General Partner provides such services and is reimbursed
for its direct and indirect costs and expenses, including all compensation and
benefit costs.
The Board of Directors of the General Partner has established a committee
(the "Audit Committee") consisting of individuals who are neither officers nor
employees of the General Partner or any affiliate of the General Partner. The
committee has the authority to review, at the request of the General Partner,
specific matters as to which the General Partner believes there may be a
conflict of interest in order to determine if the resolution of such conflict is
fair and reasonable to the Partnership. In addition, the committee reviews the
external financial reporting of the Partnership, recommends engagement of the
Partnership's independent accountants, and reviews the Partnership's procedures
for internal auditing and the adequacy of the Partnership's internal accounting
controls.
Directors and Executive Officers of the General Partner
Set forth below is certain information concerning the directors and
executive officers of the General Partner. All directors of the General Partner
are elected annually by the General Partner. All executive officers serve at
the discretion of the General Partner.
Name Age Position
------------------ --- ----------------------------------
Thomas W. Jasper 50 Director and Chairman of the Board
John P. vonBerg 45 Director, Chief Executive Officer
and President
Mark J. Gorman 44 Director, Chief Operating Officer
and Executive
Vice President
Michael A. Peak 45 Director
Paul N. Howell 80 Director
Robert T. Moffett 47 Director
Donald H. Anderson 50 Director
Herbert I. Goodman 76 Director
J. Conley Stone 67 Director
John M. Fetzer 45 Senior Vice President, Crude Oil
Ross A. Benavides 45 Chief Financial Officer
Paul A. Scoff 40 General Counsel and Secretary
Allen R. Stanley 55 Vice President, Pipeline Operations
Ben F. Runnels 58 Vice President, Trucking Operations
Kerry W. Mazoch 52 Vice President, Crude Oil
Acquisitions
Thomas W. Jasper has served as a Director of the General Partner since
December 1996. Mr. Jasper is currently an advisor to Salomon Smith Barney Inc.
Prior to this he served as Treasurer of Salomon Smith Barney Holdings Inc. and
its principal subsidiaries, Salomon Brothers Inc and Smith Barney Inc. Mr.
Jasper was also a Managing Director of Salomon Smith Barney Holdings Inc.,
Salomon Brothers Inc and Smith Barney, Inc. Mr. Jasper was Treasurer of Salomon
Inc and Salomon Brothers Inc. from April 1996 to December 1997. Prior to this
appointment, he served in various capacities for Salomon Brothers Inc and its
subsidiaries, beginning in 1982.
John P. vonBerg has served as Director, Chief Executive Officer and President
of the General Partner since December 1996. He was Vice President of Crude Oil
Gathering, Domestic Supply and Trading, for Basis and its
<PAGE> 20
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 Oil Company ("Marathon") for 13 years in
various capacities, including Product Trading, Risk Management, Crude Oil
Purchases and Sales, Finance, Auditing and Operations.
Mark J. Gorman has served as Director and Executive Vice President of the
General Partner since December 1996. In October 1997 he was also elected to
Chief Operating Officer of the General Partner. 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 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.
Michael A. Peak was elected to the Board of Directors of the General Partner
in April 1997. Since 1989, Mr. Peak has been a crude oil trader with Phibro,
Inc., a wholly-owned subsidiary of Salomon Smith Barney Holdings Inc. Prior to
joining Phibro, Inc., Mr. Peak worked for Marathon for thirteen years in various
capacities, including Manager of Crude Oil Trading, Business Development for the
Gulf Coast Pipeline Division, Controller of the Gulf Coast Pipeline Division,
Natural Gas Liquids Trader and several planning positions.
Paul N. Howell has served as a Director of the General Partner since December
1996. He held the position of President of Howell from 1995 until May 1997 and
the post of Chief Executive Officer of Howell from 1955 until May 1997. Mr.
Howell served as Chairman of the Board of Howell from 1978 to 1995 and continues
to serve as a director of Howell.
Robert T. Moffett became a Director of the General Partner in February 1999,
replacing Ronald E. Hall. 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.
Donald H. Anderson was elected to the Board of Directors of the General
Partner in March 1997. He is Executive Director of Western Growth Capital, a
Denver-based venture capital fund. He was Chairman, President and Chief
Executive Officer of PanEnergy Services, Inc., from December 1994 to March 1,
1997. PanEnergy Services, Inc., now a subsidiary of Duke Energy Corporation, is
engaged in nonjurisdictional natural gas and electric marketing, natural gas
gathering and processing, and crude oil and natural gas liquids trading and
pipeline transportation. From 1989 to 1994, Mr. Anderson was President and
Chief Operating Officer and Director of Associated Natural Gas Corporation,
which merged with PanEnergy Corp. in 1994. Prior to 1989, Mr. Anderson was Vice
President of Lantern Petroleum Corporation.
Herbert I. Goodman was elected to the Board of Directors of the General
Partner in January 1997. He is the Chairman of IQ Holdings, Inc., a
manufacturer and marketer of petrochemical-based consumer products. From 1988
until 1996 he was Chairman and Chief Executive Officer of Applied Trading
Systems, Inc., a trading and consulting business. Prior to 1988, Mr. Goodman
was with Gulf Trading and Transportation Company and Gulf Oil Corporation.
Mr. J. Conley Stone was elected to the Board of Directors of the General
Partner in January 1997. From 1987 to his retirement in 1995, he served as
President, Chief Executive Officer, Chief Operating Officer and Director of
Plantation Pipe Line Company, a common carrier liquid petroleum products
pipeline transporter. From 1976 to 1987, Mr. Stone served in a variety of
executive positions with Exxon Pipeline Company.
John M. Fetzer has served as 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 served as Tax Counsel for Lyondell Petrochemical
Company ("Lyondell") from May 1997 to October 1998. Prior to
<PAGE> 12
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.
Paul A. Scoff has served as General Counsel and Secretary of the General
Partner since December 1996. He served as Senior Counsel for Basis and its
predecessor Phibro USA from June 1994 to December 1996. Prior to joining Phibro
USA, he was a Senior Attorney for The Coastal Corporation ("Coastal") from 1989
until June of 1994 where he advised the marine, refining and marketing and crude
gathering subsidiaries of Coastal. Mr. Scoff was in private practice from 1984
until he joined Coastal in 1989.
Allen R. Stanley has served as Vice President, Pipeline Operations, of the
General Partner since December 1996. He joined Howell Crude Oil Company as
Senior Vice President of Operations in February 1995 following one year of
consulting work for Howell. From 1986 to his retirement from Marathon in 1992,
he was Manager, Business Development and Joint Interest for the downstream
component. From 1976 to 1986, he served as Manager/Gulf Coast Division in
Houston, Texas for Marathon Pipe Line Company, Manager/Non-operated Joint
Interests in London for Marathon, Manager/Engineering for Oasis Oil Company and
Manager, Engineering for Marathon Pipe Line Company in Findlay, Ohio. Mr.
Stanley began his career with Marathon in 1965.
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 1998 its officers and directors complied with all applicable filing
requirements in a timely manner.
Representatives of Salomon and Howell and officers of the General Partner
will 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 $20,000.
Item 11. Executive Compensation
The Partnership and the General Partner were formed in September 1996 but
transacted no business until December 1996. Accordingly, the General Partner
paid no compensation to its directors and officers with respect to the first
eleven months of 1996 or the 1995 fiscal year. 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 1998 and 1997 and during the one month ended
December 31, 1996 to the Chief Executive Officer and each of Genesis' four other
most highly compensated executive officers (the "Named Officers").
<PAGE> 22
<TABLE>
<CAPTION>
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 $ $ $ <F1> $ <F2> $
- --------------------------- ---- ------- ------ ------------ ------------ -----------
<S> <C> <C> <C> <C> <C> <C>
John P. vonBerg 1998 350,000 - - 570,891 <F3> 9,600 <F8>
Chief Executive Officer 1997 350,000 50,000 - - 9,550 <F11>
and President 1996 29,167 - - - -
Mark J. Gorman 1998 230,000 37,500 - 570,891 <F4> 9,600 <F8>
Executive Vice President 1997 212,500 37,500 - - 9,550 <F11>
and Chief Operating Officer 1996 17,500 - - - -
John M. Fetzer 1998 200,000 37,500 - 570,891 <F5> 9,600 <F8>
Senior Vice President, 1997 200,000 37,500 - - 9,550 <F11>
Crude Oil 1996 16,667 - - - -
Kerry W. Mazoch 1998 166,000 25,000 - 231,057 <F6> 4,800 <F9>
Vice President, Crude 1997 62,250 15,000 - - 1,743 <F12>
Oil Acquisitions
Allen R. Stanley 1998 140,000 15,000 - 285,446 <F7> 9,162 <F10>
Vice President, Pipeline 1997 140,000 20,000 - - 7,134 <F13>
1996 11,667 - - - -
<FN>
<F1> 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.
<F2> Restricted units were awarded to the Named Officer on January 27, 1998.
Under the terms of the Amended and Restated Restricted Unit Plan, the award will
vest in increments of one-third annually beginning on December 8, 1998. The
vested units cannot be sold until one year after vesting. Prior to vesting,
distributions will be paid on restricted units any time distributions are paid
on the Subordinated OLP Units. After vesting, the Named Officer will receive
distributions whenever distributions are paid to the Common Unitholders.
<F3> Mr. vonBerg received an award of 29,090 restricted units. At December 31,
1998, Mr. vonBerg had 6,841 vested restricted units with a value of $98,767
(determined using closing market price of unrestricted units on December 31,
1998). He had 19,294 unvested restricted units with a value of $278,557. Mr.
vonBerg relinquished 2,855 of the units that vested in 1998 so that the value of
the units on the vesting date ($16.8125 per unit) could be used to pay federal
income taxes owed on the vested portion of the award.
<F4> Mr. Gorman received an award of 29,090 restricted units. At December 31,
1998, Mr. Gorman had 6,841 vested restricted units with a value of $98,767
(determined using closing market price of unrestricted units on December 31,
1998). He had 19,294 unvested restricted units with a value of $278,557. Mr.
Gorman relinquished 2,855 of the units that vested in 1998 so that the value of
the units on the vesting date ($16.8125 per unit) could be used to pay federal
income taxes owed on the vested portion of the award.
<F5> Mr. Fetzer received an award of 29,090 restricted units. At December 31,
1998, Mr. Fetzer had 6,841 vested restricted units with a value of $98,767
(determined using closing market price of unrestricted units on December 31,
1998). He had 19,294 unvested restricted units with a value of $278,557. Mr.
Fetzer relinquished 2,855 of the units that vested in 1998 so that the value of
the units on the vesting date ($16.8125 per unit) could be used to pay federal
income taxes owed on the vested portion of the award.
<F6> Mr. Mazoch received an award of 12,121 restricted units. At December 31,
1998, Mr. Mazoch had 2,851 vested restricted units with a value of $41,161
(determined using closing market price of unrestricted units on December 31,
1998). He had 8,081 unvested restricted units with a value of $116,669. Mr.
Mazoch relinquished 1,189 of the units that vested in 1998 so that the value of
the units on the vesting date ($16.8125 per unit) could be used to pay federal
income taxes owed on the vested portion of the award.
<F7> Mr. Stanley received an award of 14,545 restricted units. At December 31,
1998, Mr. Stanley had 4,848 vested restricted units with a value of $69,993
(determined using closing market price of unrestricted units on December 31,
1998). He had 9,697 unvested restricted units with a value of $140,000.
<F8> Includes $4,800 of Company-matching contributions to a defined
contribution plan and $4,800 of profit-sharing contributions to a defined
contribution plan.
<F9> Includes $4,800 of profit-sharing contributions to a defined contribution
plan.
<F10> Includes $4,362 of Company-matching contributions to a defined
contribution plan and $4,800 of profit-sharing contributions to a defined
contribution plan.
<F11> Includes $4,750 of Company-matching contributions to a defined
contribution plan and $4,800 of profit-sharing contributions to a defined
contribution plan.
<F12> Includes $1,743 of profit-sharing contributions to a defined contribution
plan.
<F13> Includes $3,069 of Company-matching contributions to a defined
contribution plan and $4,065 of profit-sharing contributions to a defined
contribution plan.
</FN>
</TABLE>
<PAGE> 23
Employment Agreements
The General Partner entered into employment agreements with the following
executive officers: Mr. vonBerg, Mr. Gorman, Mr. Fetzer, Mr. Stanley, Mr.
Runnels, Mr. Benavides and Mr. Scoff. The agreements, except for the agreement
with Mr. Benavides, have an initial term expiring December 31, 1999 ("Initial
Term") with one optional extension term of two years and five additional
optional extension terms of one year each ("Extension Terms"), and include the
following additional provisions: (i) an annual base salary, (ii) eligibility to
participate in the Restricted Unit Plan (including the allocation of Initial
Restricted Units) and Incentive Compensation Plan described below, (iii)
confidential information and noncompetition provisions and (iv) an involuntary
termination provision pursuant to which the executive officer will receive
severance compensation under certain circumstances. Severance compensation
applicable under the employment agreements for an involuntary termination during
the Initial Term and Extension Terms (other than a termination for cause, as
defined in the agreements) will include payment of the greater of (i) the base
salary for the balance of the applicable term, or (ii) one year's base salary
then in effect and, in addition, the executive will be entitled to receive
incentive compensation payable to the executive in accordance with the Incentive
Plan. Upon expiration or termination of the agreement, the confidential
information and noncompetition provisions will continue until the earlier of one
year after the date of termination or the remainder of the unexpired term, but
in no event for less than six months following the expiration or termination.
The only difference in Mr. Benavides' employment agreement is that the Initial
Term expires in October 2000.
Restricted Unit Plan
In January 1997, the General Partner adopted a restricted unit plan for key
employees of the General Partner that provided for the award of rights to
receive Common Units under certain restrictions including meeting thresholds
tied to Available Cash and Adjusted Operating Surplus. In January 1998, the
restricted unit plan was amended and restated, and the thresholds tied to
Available Cash and Adjusted Operating Surplus were eliminated. The discussion
that follows is based on the terms of the Amended and Restated Restricted Unit
Plan (the "Restricted Unit Plan"). Initially, rights to receive 291,000 Common
Units are available under the Restricted Unit Plan. From these Units, rights to
receive 240,000 Common Units (the "Restricted Units") have been allocated to
approximately 32 individuals, subject to the vesting conditions described below
and subject to other customary terms and conditions.
One-third of the Restricted Units allocated to each individual will vest
annually beginning in December 1998. The remaining rights to receive 51,000
Common Units initially available under the Restricted Unit Plan may be allocated
or issued in the future to key employees on such terms and conditions (including
vesting conditions) as the Compensation Committee of the General Partner
("Compensation Committee") shall determine.
Upon "vesting" in accordance with the terms and conditions of the
Restricted Unit Plan, Common Units allocated to a plan participant will be
issued to such participant. Units issued to participants may be newly issued
Units acquired by the General Partner from the Partnership at then prevailing
market prices or may be acquired by
<PAGE> 24
the General Partner in the open market. In
either case, the associated expense will be borne by the Partnership. Until
Common Units have vested and have been issued to a participant, such participant
shall not be entitled to any distributions or allocations of income or loss and
shall not have any voting or other rights in respect of such Common Units. The
participant shall receive cash awards based on the number of non-vested units
held by such participant to the extent that distributions are paid on
Subordinated OLP Units. To date, no distributions have been paid with respect
to Subordinated OLP Units. No consideration will be payable by the plan
participants upon vesting and issuance of the Common Units. The plan
participant cannot sell the Common Units until one year after the date of
vesting.
Termination without cause in violation of a written employment agreement,
or a Significant Event as defined in the Restricted Unit Plan, will result in
immediate vesting of all non-vested units and conversion to Common Units without
any restrictions.
Incentive Plan
In January 1997, the General Partner adopted the Genesis Incentive
Compensation Plan (the "Incentive Plan") and amended it in January 1998. The
Incentive Plan is designed to enhance the financial performance of the
Partnership by rewarding the executive officers and other specific key employees
for achieving annual financial performance objectives. The Incentive Plan will
be administered by the Compensation Committee. Individual participants and
payments, if any, for each calendar year will be determined by and in the
discretion of the Compensation Committee. No incentive payments will be made
with respect to any year unless (i) the aggregate MQD in the Incentive Plan year
has been distributed to each holder of Common Units, plus any arrearage thereon,
(ii) the Adjusted Operating Surplus generated during such year has equaled or
exceeded the sum of the MQD on all of the outstanding Common Units and the
related distribution on the General Partner's interest during such year and
(iii) no APIs are outstanding. In addition, incentive payments will not exceed
$375,000 with respect to any year unless (i) each holder of Subordinated OLP
Units has also received the aggregate MQD and (ii) the Adjusted Operating
Surplus generated during such year exceeded the sum of the MQD on all of the
outstanding Common Units and Subordinated OLP Units and the related distribution
on the General Partner's interest during such year. Any incentive payments will
be at the discretion of the Compensation Committee, and the General Partner will
be able to amend or change the Incentive Plan at any time.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The Partnership knows of no one who beneficially owns in excess of five
percent of the Common Units of the Partnership. As set forth below, certain
beneficial owners own interests in the General Partner of the Partnership.
<TABLE>
<CAPTION>
Amount and Nature
Name and Address of Beneficial Ownership Percent
Title of Class of Beneficial Owner as of January 1, 1997 of Class
------------------------ -------------------- --------------------- --------
<S> <C> <C> <C>
General Partner Interest Genesis Energy, L.L.C. 1 <F1> 100.00
500 Dallas, Suite 2500
Houston, TX 77002
General Partner Interest Salomon Smith Barney Holdings Inc. 1 <F1> 100.00
Seven World Trade Center
New York, NY 10048
General Partner Interest Howell Corporation 1 <F1> 100.00
1111 Fannin, Suite 1500
Houston, TX 77002
_____________________
<FN>
<F1> Salomon owns 54% of Genesis Energy, L.L.C., and Howell owns 46% of
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.
</FN>
</TABLE>
The following table sets forth certain information as of February 28, 1999,
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.
<PAGE> 25
<TABLE>
<CAPTION>
Amount and Nature of Beneficial Ownership
-------------------------------------------
Sole Voting and Shared Voting and Percent
Title of Class Name Investment Power Investment Power of Class
-------------------- --------------- ---------------- ---------------- --------
<S> <C> <C> <C> <C>
Genesis Energy, L.P. Thomas W. Jasper - - -
Common Unit John P. vonBerg 12,841 - *
Mark J. Gorman 11,841 - *
Michael A. Peak 409 - *
Paul N. Howell 1,200 - *
Robert T. Moffett - - -
Donald H. Anderson 1,000 - *
Herbert I. Goodman 2,000 - *
J. Conley Stone 1,000 - *
John M. Fetzer 11,841 - *
Kerry W. Mazoch 2,851 - *
Allen R. Stanley 10,348 6,400 *
All directors and
executive officers
as a group
(15 in number) 61,923 6,400 *
-----------------
* Less than 1%
</TABLE>
The above table includes shares owned by certain members of the families of
the directors or executive officers, including shares in which pecuniary
interest may be disclaimed.
Item 13. Certain Relationships and Related Transactions
See Note 13 to the Consolidated Financial Statements for information
regarding certain transactions between Genesis and the General Partner, Salomon,
Howell and their subsidiaries and affiliates.
Salomon and Howell own 1,163,700 and 991,300 Subordinated OLP Units,
respectively, representing a 10.58% and 9.01% limited partner interest in GCOLP.
Salomon and Howell own 54% and 46%, respectively, of the General Partner.
Through its control of the General Partner, Salomon has the ability to control
the management of the Partnership and GCOLP.
For administrative reasons, each of Basis and Howell employed through
December 31, 1996, the persons responsible for managing or operating the
Partnership. All employment costs and expenses related to such employees for
the one month ended December 31, 1996 were charged to the General Partner and
were reimbursed by the Partnership to the General Partner.
Redemption and Registration Rights Agreement. Pursuant to the Redemption and
Registration Rights Agreement, the Partnership has agreed, at the end of the
Subordination Period or upon earlier conversion of Subordinated OLP Units into
Common OLP Units, to use reasonable efforts to sell that number of Common Units
equal to the number of Common OLP Units that Salomon or Howell is requesting be
redeemed. The proceeds, net of underwriting discount or placement fees, if any,
from such sale will be used by the Operating Partnership to redeem such Common
OLP Units. The Partnership is obligated to pay the expenses incidental to
redemption requests, other than the underwriting discount or placement fees, if
any. The General Partner will have a proportionate percentage of its general
partner interest in the Operating Partnership redeemed when Common OLP Units are
redeemed in connection with the exercise of the redemption right.
Distribution Support Agreement. To further enhance the Partnership's ability
to distribute the Minimum Quarterly Distribution on the Common Units with
respect to each quarter through the quarter ending December 31, 2001, Salomon
has agreed in the Distribution Support Agreement, subject to certain
limitations, to contribute or cause to be contributed cash, if necessary, to the
Partnership in return for APIs. Salomon's obligation to purchase APIs is
limited to a maximum amount outstanding at any one time equal to $17.6 million.
The Unitholders have no independent right separate and apart from the
Partnership to enforce obligations of Salomon under the Distribution Support
Agreement. See "Cash Distribution Policy--Distribution Support."
<PAGE> 26
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 30.
(a)(3) Exhibits
3.1 Certificate of Limited Partnership of Genesis Energy,
L.P. ("Genesis") (incorporated by reference to Exhibit 3.1 to
Registration Statement, File No. 333-11545)
** 3.2 Agreement of Limited Partnership of Genesis
** 3.3 Certificate of Limited Partnership of Genesis Crude Oil,
L.P. (the "Operating Partnership")
3.4 Agreement of Limited Partnership of the Operating
Partnership (incorporated by reference to Exhibit 3.4 to
Registration Statement, File No. 333-11545)
** 10.1 Purchase & Sale and Contribution & Conveyance Agreement
dated as of December 3, 1996 among Basis Petroleum, Inc.
("Basis"), Howell Corporation ("Howell"), certain subsidiaries
of Howell, Genesis, the Operating Partnership and Genesis
Energy, L.L.C.
** 10.2 First Amendment to Purchase & Sale and Contribution &
Conveyance Agreement
** 10.3 Distribution Support Agreement among the Operating
Partnership and Salomon Inc
** 10.4 Master Credit Support Agreement among the Operating
Partnership, Salomon Inc and Basis
** 10.5 Redemption and Registration Rights Agreement among Basis,
Howell, certain Howell subsidiaries, Genesis and the Operating
Partnership
10.7 Non-competition Agreement among Genesis, the
Operating Partnership, Salomon Inc, Basis and Howell
(incorporated by reference to Exhibit 10.6 to Registration
Statement, File No. 333-11545)
** 10.8 Employment Agreement between Genesis Energy, L.L.C. and
John P. vonBerg
** 10.9 Employment Agreement between Genesis Energy, L.L.C. and
Mark J. Gorman
** 10.10 Employment Agreement between Genesis Energy, L.L.C.
and John M. Fetzer
10.11 Employment Agreement between Genesis Energy,
L.L.C. and Ross A. Benavides (incorporated by reference to
Exhibit 10.3 to Form 10-Q for the quarterly period ended
September 30, 1998)
** 10.12 Employment Agreement between Genesis Energy, L.L.C.
and Paul A. Scoff
** 10.13 Employment Agreement between Genesis Energy, L.L.C.
and Allen R. Stanley
** 10.14 Employment Agreement between Genesis Energy, L.L.C.
and Ben F. Runnels
10.15 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)
10.16 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)
10.17 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)
10.18 Amended and Restated Restricted Unit Plan
(incorporated by reference to Exhibit 10.18 to Form 10-K for
the year ended December 31, 1997)
10.19 Loan Agreement by and between Genesis Crude Oil,
L.P. and Bank One, Texas, N.A. dated as of August 14, 1998
(incorporated by reference to Exhibit 10.1 to Form 10-Q for the
quarterly period ended September 30, 1998)
<PAGE> 27
10.20 Amendment No. 1 to Loan Agreement by and between
Genesis Crude Oil, L.P. and Bank One, Texas, N.A. dated as of
August 14, 1998 (incorporated by reference to Exhibit 10.2 to
Form 10-Q for the quarterly period ended September 30, 1998)
* 10.21 Amendment No. 2 to Loan Agreement by and between
Genesis Crude Oil, L.P. and Bank One, Texas, N.A. dated as of
August 14, 1998
11.1 Statement Regarding Computation of Per Share Earnings
(See Note 3 to the Consolidated Financial Statements - "Net
Income Per Unit")
* 21.1 Subsidiaries of the Registrant
* 27 Financial Data Schedule
____________________
* Filed herewith
** Filed as an exhibit to the Partnership's Annual Report on Form 10-K for
the Year Ended December 31, 1996.
(b) Reports on Form 8-K
None.
<PAGE> 28
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 26 day of March,
1998.
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
By: GENESIS ENERGY, L.L.C., as
General Partner
By: /s/ John P. vonBerg *
-------------------------------
John P. vonBerg
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/ John P. vonBerg * Director, Chief Executive Officer March 26, 1999
- ------------------------
John P. vonBerg and President
(Principal Executive Officer)
/s/ Ross A. Benavides Chief Financial Officer March 26, 1999
- ------------------------
Ross A. Benavides (Principal Financial and
Accounting Officer)
/s/ Thomas W. Jasper * Chairman of the Board and March 26, 1999
- ------------------------
Thomas W. Jasper Director
/s/ Michael A. Peak * Director March 26, 1999
- ------------------------
Michael A. Peak
/s/ Paul N. Howell * Director March 26, 1999
- ------------------------
Paul N. Howell
/s/ Robert T. Moffett * Director March 26, 1999
- ------------------------
Robert T. Moffett
/s/ Mark J. Gorman * Director, Chief Operating Officer and March 26, 1999
- ------------------------
Mark J. Gorman Executive Vice President
* By /s/ Ross A. Benavides
------------------------
Ross A. Benavides
(Attorney-in-fact for persons indicated)
<PAGE> 29
GENESIS ENERGY, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
Report of Independent Public Accountants 31
Consolidated Balance Sheets, December 31, 1998 and 1997 32
Consolidated Statements of Operations for the Years Ended December
31, 1998 and 1997, Pro Forma Consolidated Statement of Operations
for the Year Ended December 31, 1996, Consolidated Statement of
Operations for the One Month Ended December 31, 1996, and
Statement of Operations for the Eleven Months Ended November 30,
1996 (Predecessor) 33
Consolidated Statements of Cash Flows for the Years Ended December
31, 1998 and 1997 and for the One Month Ended December 31, 1996,
and Statement of Cash Flows for the Eleven Months Ended November
30, 1996 (Predecessor) 34
Consolidated Statements of Partners' Capital for the Years Ended
December 31, 1998 and 1997 and for the One Month Ended December
31, 1996, and Statement of Divisional Equity for the Eleven
Months Ended November 30, 1996 (Predecessor), 35
Notes to Consolidated Financial Statements 36
<PAGE> 30
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, 1998 and 1997 and the
related consolidated statements of operations, cash flows and partners' capital
for the years ended December 31, 1998 and 1997 and for the one month ended
December 31, 1996. We have also audited the statements of operations, cash
flows and divisional equity of the Predecessor (as defined in Note 1 to the
consolidated financial statements) for the eleven months ended November 30,
1996. These financial statements are the responsibility of the Partnership's
management and the Predecessor's management, respectively. Our responsibility
is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Genesis Energy, L.P. as of
December 31, 1998 and 1997, and the results of its operations and its cash flows
for the years ended December 31, 1998 and 1997 and for the one month ended
December 31, 1996 and the results of the operations and the cash flows of the
Predecessor for the eleven months ended November 30, 1996, in conformity with
generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
February 18, 1999
<PAGE> 31
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31,December 31,
1998 1997
-------- --------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 7,710 $ 11,812
Accounts receivable -
Trade 167,600 209,869
Related party 4,634 -
Inventories 1,966 2,598
Other 3,306 3,488
-------- --------
Total current assets 185,216 227,767
FIXED ASSETS, at cost 119,310 109,537
Less: Accumulated depreciation (20,707) (16,464)
-------- --------
Net fixed assets 98,603 93,073
OTHER ASSETS, net of amortization 13,354 10,274
-------- --------
TOTAL ASSETS $297,173 $331,114
======== ========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable -
Trade $172,143 $215,159
Related party 6,200 2,832
Accrued liabilities 5,171 6,547
-------- --------
Total current liabilities 183,514 224,538
LONG-TERM DEBT 15,800 -
COMMITMENTS AND CONTINGENCIES (Note 20)
MINORITY INTERESTS 29,988 28,225
PARTNERS' CAPITAL
Common unitholders, 8,625 units issued;
8,604 and 8,625 units outstanding at
December 31, 1998 and 1997, respectively 66,832 76,783
General partner 1,357 1,568
-------- --------
Subtotal 68,189 78,351
Treasury units, 21 units at December 31, 1998 (318) -
-------- --------
Total partners' capital 67,871 78,351
-------- --------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $297,173 $331,114
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE> 32
<TABLE>
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
<CAPTION>
One Month Eleven Months
Year Ended Year Ended Year Ended Ended Ended
December 31, December 31, December 31, December 31, November 30,
1998 1997 1996 1996 1996
---------- ----------- ---------- ------------ ------------
(Pro forma) (Predecessor)
(Unaudited)
<S> <C> <C> <C> <C> <C>
REVENUES:
Gathering and marketing revenues
Unrelated parties $2,178,224 $2,911,333 $3,101,632 $318,110 $2,194,156
Related parties 38,718 443,606 1,464,202 52,449 1,403,951
Pipeline revenues 16,533 17,989 16,780 1,426 -
---------- ---------- ---------- -------- ----------
Total revenues 2,233,475 3,372,928 4,582,614 371,985 3,598,107
COST OF SALES:
Crude costs, unrelated parties 2,141,715 3,147,694 4,179,974 363,735 3,245,123
Crude costs, related parties 42,814 183,490 346,389 2,988 327,963
Field operating costs 12,778 12,107 15,092 1,290 6,744
Pipeline operating costs 7,971 6,016 4,978 463 -
---------- ---------- ---------- -------- ----------
Total cost of sales 2,205,278 3,349,307 4,546,433 368,476 3,579,830
---------- ---------- ---------- -------- ----------
GROSS MARGIN 28,197 23,621 36,181 3,509 18,277
EXPENSES:
General and administrative 11,468 8,557 9,470 1,363 3,316
Depreciation and amortization 7,719 6,300 6,834 518 1,396
Nonrecurring charges 373 - - - -
---------- ---------- ---------- -------- ----------
OPERATING INCOME 8,637 8,764 19,877 1,628 13,565
OTHER INCOME (EXPENSE):
Interest, net 154 1,063 56 56 294
Other, net 28 21 (74) - (83)
---------- ---------- ---------- -------- ----------
Income before income taxes and
minority interests 8,819 9,848 19,859 1,684 13,776
Income tax provision - - - - 5,167
---------- ---------- ---------- -------- ----------
Net income before minority interests 8,819 9,848 19,859 1,684 8,609
Minority interests 1,763 1,968 3,970 337 -
---------- ---------- ---------- -------- ----------
NET INCOME $ 7,056 $ 7,880 $ 15,889 $ 1,347 $ 8,609
========== ========== ========== ======== ==========
NET INCOME PER COMMON UNIT-BASIC AND DILUTED $ 0.80 $ 0.90 $ 1.81 $ 0.15
========== ========== ========== ========
WEIGHTED AVERAGE NUMBER OF COMMON
UNITS OUTSTANDING 8,606 8,625 8,625 8,625
========== ========== ========== ========
The accompanying notes are an integral part of these consolidated financial
statements.
</TABLE>
<PAGE> 33
<TABLE>
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
<CAPTION>
One Month Eleven Months
Year Ended Year Ended Ended Ended
December 31,December 31,December 31,November 30,
1998 1997 1996 1996
-------- --------- --------- ---------
(Predecessor)
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 7,056 $ 7,880 $ 1,347 $ 8,609
Adjustments to reconcile net income to net
cash provided by (used in) operating activities -
Depreciation 6,529 5,820 479 1,396
Amortization of intangible assets 1,190 480 39 -
Loss (gain) on disposal of assets 269 (21) - 82
Minority interests equity in earnings 1,763 1,968 337 -
Other noncash charges 1,503 66 200 (12)
Changes in components of working capital -
Accounts receivable 37,635 178,938 (384,681) (133,676)
Inventories 1,384 1,257 (4,944) 2,763
Other current assets 182 (2,092) (1,260) (17)
Accounts payable (39,648) (172,761) 381,418 118,948
Accrued liabilities (1,446) (1,330) 6,218 (694)
-------- --------- --------- ---------
Net cash provided by (used in) operating activities 16,417 20,205 (847) (2,601)
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (13,431) (5,848) (106) (1,100)
Increase in other assets (4,270) (162) - (1,203)
Purchase of operations of Howell - - (74,021) -
Proceeds from sales of assets 188 348 - 270
-------- --------- --------- ---------
Net cash used in investing activities (17,513) (5,662) (74,127) (2,033)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under Loan Agreement 15,800 - - -
Distributions to common unitholders (17,208) (14,317) - -
Distributions to General Partner (352) (292) - -
Purchase of treasury units (1,246) - - -
General Partner contribution at formation - - 2,941 -
Net proceeds of public offering of Common Units - - 162,975 -
Distribution to Basis at formation - - (86,985) -
Net advances from Basis - - - 4,634
Other - - 543 -
-------- --------- --------- ---------
Net cash (used in) provided by financing activities (3,006) (14,609) 79,474 4,634
-------- --------- --------- ---------
Net (decrease) increase in cash and cash equivalents (4,102) (66) 4,500 -
Cash and cash equivalents at beginning of period 11,812 11,878 7,378 -
-------- --------- --------- ---------
Cash and cash equivalents at end of period $ 7,710 $ 11,812 $ 11,878 $ -
======== ========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
</TABLE>
<PAGE> 34
<TABLE>
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS'
CAPITAL/DIVISIONAL EQUITY
(In thousands)
<CAPTION>
Partners' Capital
----------------------------------------
Common General Treasury Divisional
Unitholders Partner Units Total Equity
----------- ------- ------ -------- -------------
(Predecessor)
<S> <C> <C> <C> <C> <C>
Divisional equity at December 31, 1995 $(8,437)
Net income for eleven months ended November 30, 1996 8,609
Net advances from Basis 4,634
-------
Divisional equity at November 30, 1996 $ 4,806
=======
Initial capital based on issuance of partnership
interests (see Note 1) $ 82,058 $1,675 $ - $ 83,733
Net income for the one month ended December 31, 1996 1,320 27 - 1,347
-------- ------ ------- --------
Partners' capital at December 31, 1996 83,378 1,702 - 85,080
Net income for the year ended December 31, 1997 7,722 158 - 7,880
Cash distributions for the year ended
December 31, 1997 (14,317) (292) - (14,609)
-------- ------ ------- --------
Partners' capital at December 31, 1997 76,783 1,568 - 78,351
Net income for the year ended December 31, 1998 6,915 141 - 7,056
Cash distributions for the year ended
December 31, 1998 (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
======== ====== ======= ========
The accompanying notes are an integral part of these consolidated financial
statements.
</TABLE>
<PAGE> 35
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Formation and Offering
In December 1996, Genesis Energy, L.P. ("GELP") 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.
The operations acquired from Basis are hereafter referred to as the
"Predecessor". Unless the context otherwise requires, the term "the
Partnership" hereafter refers to GELP, its operating limited partnership and the
Predecessor.
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. See Note 6.
2. Basis of Presentation
The accompanying financial statements and related notes present the
consolidated financial position as of December 31, 1998 and 1997 for GELP and
its results of operations, cash flows and changes in partners' capital for the
years ended December 31, 1998 and 1997 and the one month ended December 31,
1996, and the results of operations, cash flows and changes in divisional equity
for the Predecessor for the eleven months ended November 30, 1996.
The accompanying financial statements of the Predecessor were prepared in
connection with the public offering of limited partner interests in the
Partnership. These financial statements include the accounts of the
Predecessor, a division of Basis, which was a wholly-owned subsidiary of
Salomon. Cash flows of the Predecessor not funded from operating activities
were funded by Basis prior to the formation of the Partnership. Changes in
divisional equity during the eleven months ended November 30, 1996, which are
not attributable to net income of the Predecessor, represent net advances to or
from Basis.
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. Federal income tax liabilities resulting from activities of the
Predecessor and Howell prior to the closing of the offering were retained by
Basis and Howell.
The unaudited pro forma Consolidated Statement of Operations for the year
ended December 31, 1996 reflects certain pro forma adjustments to the historical
results of operations of the Predecessor and Howell as if the
<PAGE> 36
Partnership had
been formed on January 1, 1996. These pro forma adjustments reflect the
inclusion of fees associated with the Master Credit Support Agreement,
incremental fees related to execution of futures contracts on the New York
Mercantile Exchange ("NYMEX") as a separate entity, and incremental general and
administrative expenses and compensation costs for the operation of the
Partnership as a separate public entity. The pro forma adjustments also include
additional depreciation and amortization expense due to the increase in property
and intangibles that resulted from applying the purchase method of accounting to
the assets acquired from Howell. The pro forma adjustments eliminate net
interest expense recorded by the Predecessor and Howell as the Partnership had
no long-term debt as of the closing of the public offering. Income tax
provisions have also been eliminated as the Partnership is not a taxable entity.
The pro forma adjustments were made based upon available information and certain
estimates and assumptions which management believes provide a reasonable basis
for presentation.
3. Summary of Significant Accounting Policies
Principles of Consolidation
The Partnership owns and operates its assets through GCOLP, an operating
limited partnership. The accompanying consolidated financial statements reflect
the combined accounts of the Partnership and the operating partnership after
elimination of intercompany transactions. All material intercompany accounts
and transactions have been eliminated.
Nature of Operations
The principal business activities of the Partnership are the purchasing,
gathering, transporting and marketing of crude oil in the United States. The
Partnership gathers approximately 114,000 barrels per day at the wellhead
principally in the southern and southwestern states. The Partnership also owns
and operates three crude oil pipelines onshore. The onshore pipelines are in
Texas, Mississippi/Louisiana and Florida/Alabama.
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. Funds deposited with Salomon, as
discussed in Note 13, are also considered cash equivalents. The Partnership has
no requirement for compensating balances or restrictions on cash.
Inventories
Crude oil inventories held for sale are valued at market. Store warehouse
inventories, including tractor and trailer parts, supplies and fuel, are carried
at the lower of cost or market.
Fixed Assets
Property and equipment are carried at cost. Depreciation of property and
equipment is provided using the straight-line method over the respective
estimated useful lives of the assets. Asset lives are 20 years for pipelines
and related assets, 3 to 7 years for vehicles and transportation equipment, and
3 to 10 years for buildings, office equipment, furniture and fixtures and other
equipment. Maintenance and repair costs are charged to expense as incurred.
Costs incurred for major replacements and upgrades are capitalized and
depreciated over the remaining useful life of the asset. Certain volumes of
crude oil are classified in fixed assets as they are necessary to ensure
efficient and uninterrupted operations of the gathering businesses. These crude
oil volumes were reclassified to fixed assets from inventories during 1998 and
are carried at their weighted average cost.
Other Assets
Other assets consist primarily of intangibles and goodwill. Intangibles
include a covenant not to compete, which is being amortized over five years.
Goodwill represents the excess of purchase price over fair value of the net
assets acquired for acquisitions accounted for as purchases and is being
amortized over a period of 20 years.
<PAGE> 37
Minority Interests
Minority interests represent the Subordinated OLP Units held by Salomon and
Howell totaling 19.59% in GCOLP and the 0.4% interest the General Partner owns
directly in GCOLP.
Environmental Liabilities
The Partnership provides for the estimated costs of environmental
contingencies when liabilities are likely to occur and reasonable estimates can
be made. Ongoing environmental compliance costs, including maintenance and
monitoring costs, are charged to expense as incurred.
Income Taxes
The Predecessor was included, through Basis, in the consolidated federal
and state income tax returns of Salomon. The Predecessor's federal and state
income taxes were provided as if the Predecessor filed its income tax return
separately from Basis. If there was taxable income, taxes were provided at the
statutory rate reduced by allowable tax credits. If there was a taxable loss, a
tax benefit was provided at the statutory rate without limitation of any loss
deduction. The tax benefit was increased by tax credits to the extent the
credits were utilized by Basis.
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.
Hedging Activities
The Partnership routinely utilizes forward contracts, swaps, options and
futures contracts in an effort to minimize the impact of crude oil price
fluctuations on inventories and contractual commitments. Gains and losses
related to these hedging activities are deferred until the transaction being
hedged has settled and its related profit or loss is recognized. Deferred gains
and losses from hedging activities are included in the Consolidated Balance
Sheets in accrued liabilities or accounts receivable, respectively. Recognized
gains and losses from hedging activities are included in crude costs in the
Consolidated Statements of Operations. Unrecognized (loss) gains of
$(1,042,000) and $1,397,000 were deferred on these contracts at December 31,
1998 and 1997, respectively.
Based on the historical correlations between the NYMEX price for West Texas
intermediate crude at Cushing, Oklahoma, and the various trading hubs at which
the Partnership trades, the Partnership's management believes the hedging
program has been effective in minimizing the overall price risk. The
Partnership continuously monitors the basis (location) differentials between its
various trading hubs and Cushing, Oklahoma, to further manage its exposure.
Should a hedging contract became ineffective or otherwise cease to serve as
a hedge, the hedging instrument is accounted for under the mark-to-market method
of accounting. Under this method, the contract is reflected at market value,
and the resulting unrealized gains and losses are recognized currently in crude
costs in the Consolidated Statements of Operations.
Revenue Recognition
Gathering and marketing revenues are recognized when title to the crude oil
is transferred to the customer. Pipeline revenues are recognized upon delivery
of the barrels to the location designated by the shipper.
Cost of Sales
Cost of sales consists of the cost of crude oil and field and pipeline
operating expenses. Field and pipeline operating expenses consist primarily of
labor costs for drivers and pipeline field personnel, truck rental costs, fuel
and maintenance, utilities, insurance and property taxes.
Net Income Per Common Unit
Basic net income per Common Unit is calculated on the weighted average
number of outstanding Common Units. The weighted average number of Common Units
outstanding was 8,605,934 and 8,625,000 for the years ended December 31, 1998
and 1997, respectively, and 8,625,000 for the one-month ended December 31, 1996.
For this purpose, the 2% General Partner interest is excluded from net income.
Diluted net income per Common Unit did not differ from basic net income per
Common Unit for any period presented.
<PAGE> 38
Reclassifications
Certain reclassifications have been made to the prior year financial
statements in order to conform to the current year presentation.
4. New Accounting Pronouncements
Statement of Financial Accounting Standards (SFAS) No. 130, "Reporting
Comprehensive Income", was issued in June 1997, with adoption required for
fiscal years beginning after December 31, 1997. SFAS No. 130 requires the
presentation of an additional income measure (termed "comprehensive income"),
which adjusts traditional net income for certain items that previously were only
reflected as direct adjustments to equity. The Partnership had no items of
comprehensive income for any of the periods presented.
SFAS No. 131, "Disclosures About Segments of an Enterprise and Related
Information", was issued in June 1997, establishing standards for the way that
public business enterprises report information about operating segments and
related information in interim and annual financial statements. The Partnership
has evaluated and assessed the reporting criteria under SFAS No. 131 and has
concluded that it operates as a single business segment based primarily on the
Partnership's overall management approach.
In November 1998, the Emerging Issues Task Force (EITF) reached a consensus
on EITF Issue 98-10, "Accounting for Energy Trading and Risk Management
Activities". This consensus, effective in the first quarter of 1999, requires
that certain energy related contracts be marked-to-market, with gains or losses
recognized in current earnings. The Partnership is in the process of
determining the extent to which its activities meet the definition in EITF Issue
98-10 of "trading" activities.
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities",
was issued in June 1998. This new standard, which the Partnership will be
required to adopt for its fiscal year 2000, will change the method of accounting
for changes in the fair value of certain derivative instruments by requiring
that an entity recognize the derivative at fair value as an asset or liability
on its balance sheet. Depending on the purpose of the derivative and the item
it is hedging, the changes in fair value of the derivative will be recognized in
current earnings or as a component of other comprehensive income in partners'
capital. The Partnership is in the process of evaluating the impact that this
statement will have on its results of operations and financial position. This
new standard could increase volatility in net income and comprehensive income.
5. Business Segment and Customer Information
As discussed in Note 4, based on its management approach, the Partnership
believes that all of its material operations revolve around the gathering and
marketing of crude oil, and it currently reports its operations, both internally
and externally, as a single business segment. A significant portion of the
Partnership's revenues in 1997 and earlier periods resulted from transactions
with Basis and other Salomon affiliates. No other customer accounted for more
than 10% of the Partnership's revenues in any period.
6. Acquisition of Howell
As discussed in Notes 1 and 2, GCOLP acquired the crude oil gathering,
marketing and pipeline operations of Howell in December 1996. This acquisition
was treated as a purchase for accounting purposes.
The results of operations of the assets acquired from Howell are included in
the consolidated statement of operations of the Partnership for the one month
ended December 31, 1996. The following unaudited pro forma information
represents the consolidated pro forma amounts assuming the acquisition of Howell
had occurred at the beginning of 1996 (in thousands, except per unit amounts).
Year Ended
December 31,
1996
-----------
Revenues $4,582,614
Net income $ 15,889
Net income per Common Unit-basic and diluted $ 1.81
The above amounts are based upon certain assumptions and estimates which the
Partnership believes are reasonable. The pro forma results do not necessarily
represent results which would have occurred if the acquisition
<PAGE> 39
had taken place
on the basis assumed above, nor are they necessarily indicative of the results
of future combined operations.
7. Inventories
Inventories consisted of the following (in thousands).
December 31,
------------------
1998 1997
------ ------
Crude oil inventories, at market $1,644 $2,304
Store warehouse inventories, at lower
of cost or market 322 294
------ ------
Total inventories $1,966 $2,598
====== ======
The Partnership has reclassified balances previously described as minimum
crude inventories from inventory to fixed assets to better reflect the true
nature of the underlying asset. The volumes associated with this asset are not
held for sale as they are required to be on hand to ensure the efficient and
uninterrupted operation of the gathering activities.
8. Fixed Assets
Fixed assets consisted of the following (in thousands).
December 31,
--------------------
1998 1997
-------- --------
Land and buildings $ 3,489 $ 3,569
Pipelines and related assets 93,796 83,611
Vehicles and transportation equipment 8,006 8,211
Office equipment, furniture and fixtures 5,281 5,109
Other 8,738 9,037
-------- --------
119,310 109,537
Less - Accumulated depreciation (20,707) (16,464)
-------- --------
Net fixed assets $ 98,603 $ 93,073
======== ========
Depreciation expense was $6,529,000 and $5,820,000 for the years ended
December 31, 1998 and 1997, respectively, $479,000 for the one month ended
December 31, 1996, and $1,396,000 for the eleven months ended November 30, 1996.
9. Other Assets
Other assets consisted of the following (in thousands).
December 31,
------------------
1998 1997
------ ------
Goodwill $ 9,401 $ 9,401
NYMEX seats 1,203 1,203
Covenant not to compete 4,393 155
Other 66 34
------- -------
15,063 10,793
Less - Accumulated amortization (1,709) (519)
------- -------
Unamortized other assets $13,354 $10,274
======= =======
Amortization expense was $1,190,000 and $480,000 for the years ended December
31, 1998 and 1997, respectively, and $39,000 for the one month ended December
31, 1996. There was no amortization expense for the eleven months ended
November 30, 1996.
10. 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.
<PAGE> 40
Guaranty Facility
Salomon is providing a Guaranty Facility through December 31, 1999 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, 1999 (to be reduced in each case by the amount of any
obligation to a third party to the extent that such third party has a prior
security interest in the collateral). GCOLP pays a guarantee fee to Salomon
which will increase over the three-year period, thereby increasing the cost of
the credit support provided to GCOLP under the Guaranty Facility. At December
31, 1998, the aggregate amount of obligations covered by guarantees was $152
million, including $89 million in payable obligations and $63 million of
estimated crude oil purchase obligations for January 1999.
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, (d) a ratio of
Consolidated Earnings before Interest, Taxes, Depreciation and Amortization to
Consolidated Fixed Charges of at least 1.75 to 1 as of the last day of each
fiscal quarter prior to December 31, 1999 and (e) a ratio of Consolidated Total
Liabilities to Consolidated Tangible Net Worth of not more than 10.0 to 1 (as
such terms are defined in the Master Credit Support Agreement).
An Event of Default could result in the termination of the Credit
Facilities at the discretion of Salomon. Significant Events of Default include
(a) a default in the payment of (i) any principal on any payment obligation
under the Credit Facilities when due or (ii) interest or fees or other amounts
within two business days of the due date, (b) the guaranty exposure amount
exceeding the maximum credit support amount for two consecutive calendar months,
(c) failure to perform or otherwise comply with any covenants contained in the
Master Credit Support Agreement if such failure continues unremedied for a
period of 30 days after written notice thereof and (d) a material
misrepresentation in connection with any loan, letter of credit or guarantee
issued under the Credit Facilities. Removal of the General Partner will result
in the termination of the Credit Facilities and the release of all of Salomon's
obligations thereunder.
There can be no assurance of the availability or the terms of credit for
the Partnership. At this time, Salomon does not intend to provide guarantees or
other credit support after the three-year credit support period expires in
December 1999. If the General Partner is removed without its consent, Salomon's
credit support obligations will terminate. In addition, Salomon's obligations
under the Master Credit Support Agreement may be transferred or terminated early
subject to certain conditions. Management of the Partnership intends to replace
the Guaranty Facility with a letter of credit facility with one or more third
party lenders prior to December 1999 and has had preliminary discussions with
banks about a replacement letter of credit facility. The General Partner may be
required to reduce or restrict the Partnership's gathering and marketing
activities because of limitations on its ability to obtain credit support and
financing for its working capital needs. The General Partner expects that the
overall cost of a replacement facility may be substantially greater than what
the Partnership is incurring under its existing Master Credit Support Agreement.
Any significant decrease in the Partnership's financial strength, regardless of
the reason for such decrease, may increase the number of transactions requiring
letters of credit or other financial support, make it more difficult for the
Partnership to obtain such letters of credit, and/or may increase the cost of
obtaining them. This situation could in turn adversely affect the Partnership's
ability to maintain or increase the level of its purchasing and marketing
activities or otherwise adversely affect the Partnership's profitability and
Available Cash.
<PAGE> 41
Working Capital Facility
Until replaced as described below, Salomon provided GCOLP with a Working
Capital Facility of up to $50 million, which amount included direct cash
advances not to exceed $35 million outstanding at any one time and letters of
credit that may be required in the ordinary course of GCOLP's business.
In August 1998, GCOLP entered into a revolving credit/loan agreement ("Loan
Agreement") with Bank One, Texas, N.A. ("Bank One") to replace the Working
Capital Facility that had been provided by Salomon. The Loan Agreement provides
for loans or letters of credit in the aggregate not to exceed the greater of $35
million or the Borrowing Base (as defined in the Loan Agreement). Loans will
bear interest at a rate chosen by GCOLP which would be one or more of the
following: (a) a Floating Base Rate (as defined in the Loan Agreement) that is
generally the prevailing prime rate less one percent; (b) a rate based on the
Federal Funds Rate plus one and one-half percent or (c) a rate based on LIBOR
plus one and one-quarter percent. The Loan Agreement provides for a revolving
period until August 14, 2000, with interest to be paid monthly. All loans
outstanding on August 14, 2000, are due at that time.
The Loan Agreement is collateralized by the accounts receivable and
inventory of GCOLP, subject to the terms of an Intercreditor Agreement between
Bank One and Salomon. There is no compensating balance requirement under the
Loan Agreement. A commitment fee of 0.35% on the available portion of the
commitment is provided for in the agreement. Material covenants and
restrictions include requirements to maintain a ratio of current assets (as
defined in the Loan Agreement) to current liabilities of at least 1:1 and to
maintain tangible net worth in GCOLP, as defined in the Loan Agreement, of not
less than $65 million.
At December 31, 1998, the Partnership had $15.8 million of loans
outstanding under the Loan Agreement. The Partnership had no letters of credit
outstanding at December 31, 1998. At December 31, 1998, $19.2 million was
available to be borrowed under the Loan Agreement.
Distributions
Generally, GCOLP will distribute 100% of its Available Cash within 45 days
after the end of each quarter to Unitholders of record and to the General
Partner. Available Cash consists generally of all of the cash receipts less
cash disbursements of GCOLP adjusted for net changes to reserves. (A full
definition of Available Cash is set forth in the Partnership Agreement.)
Distributions of Available Cash to the holders of Subordinated OLP Units are
subject to the prior rights of holders of Common Units to receive the minimum
quarterly distribution ("MQD") for each quarter during the subordination period
(which will not end earlier than December 31, 2001) and to receive any
arrearages in the distribution of the MQD on the Common Units for prior quarters
during the subordination period. MQD is $0.50 per unit.
Salomon has committed, subject to certain limitations, to provide total
cash distribution support, with respect to quarters ending on or before December
31, 2001, in an amount up to an aggregate of $17.6 million in exchange for
Additional Partnership Interests ("APIs"). Salomon's obligation to purchase
APIs will end no later than December 31, 2001, with the actual termination
subject to the levels of distributions that have been made prior to the
termination date. Any APIs purchased by Salomon are not entitled to cash
distributions or voting rights. The APIs will be redeemed if and to the extent
that Available Cash for any future quarter exceeds an amount necessary to
distribute the MQD on all Common Units and Subordinated OLP Units and to
eliminate any arrearages in the MQD on Common Units for prior periods. At
December 31, 1998, no APIs have been purchased by Salomon pursuant to the
distribution support commitment. As a result of poor domestic crude oil market
conditions, the General Partner may have to draw on the cash distribution
support form Salomon during 1999.
In addition, the Partnership Agreement authorizes the General Partner to
cause GCOLP to issue additional limited partner interests and other equity
securities, the proceeds from which could be used to provide additional funds
for acquisitions or other GCOLP needs.
11. 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.
<PAGE> 42
GELP has an approximate 80.01% general partner interest in GCOLP. The
remainder of GCOLP is held by Salomon, Howell and the General Partner. These
interests, reflected in the consolidated financial statements as minority
interests, are as follows.
Interest in
GCOLP
-----------
Subordinated limited partner interest held by:
Salomon 10.58%
Howell 9.01
General partner interest in GCOLP held by the General Partner 0.40
------
Total minority interests 19.99%
======
The Partnership will be managed by the General Partner. Common Units will
receive distributions in liquidation in preference to Subordinated OLP Units.
See Note 8 for a discussion regarding distributions.
Conversion of Subordinated OLP Units
There is no established public market for the Subordinated OLP Units. The
Subordinated OLP Units will convert into common units of GCOLP ("Common OLP
Units") upon the expiration of the subordination period. The subordination
period will not end prior to December 31, 2001 and will only end thereafter if
GCOLP satisfies certain cash distribution and earnings tests. Subordinated OLP
Units that have converted into Common OLP Units will share equally in
distributions of Available Cash with the Common Units.
Once the Subordinated OLP Units have converted into Common OLP Units,
Salomon or Howell may request that these units be redeemed. At such time,
pursuant to a Redemption and Registration Rights Agreement, GELP will use its
reasonable best efforts to sell the number of Common Units equal to the number
of Common OLP Units in GCOLP that are to be redeemed. The proceeds, net of
underwriting discount or placement fees from such sale, will be contributed to
GCOLP and used to redeem such Common OLP Units. GELP is obligated to pay the
expenses incidental to redemption requests, other than underwriting discount or
placement fees. The General Partner will have a proportionate percentage of its
general partner interest in GCOLP redeemed when Common OLP Units are redeemed in
connection with the exercise of the redemption right.
12. Nonrecurring Charge
In the second quarter of 1998, the Partnership shut-in its Main Pass
pipeline. A charge of $373,000 was recorded, consisting of $109,000 of costs
related to the shut-in and a non-cash write-down of the asset of $264,000.
13. Transactions with Related Parties
Sales, purchases and other transactions with affiliated companies, except the
guarantee fees paid to Salomon, in the opinion of management, are conducted
under terms no more or less favorable than those conducted with unaffiliated
parties. Basis was a wholly-owned subsidiary of Salomon until May 1, 1997, when
Basis was sold to Valero Energy Corporation. Basis transferred its 54% interest
in the general partner and its approximately 1.2 million Subordinated OLP Units
to Salomon in conjunction with the sale of Basis.
Sales and Purchases of Crude Oil
A summary of sales to and purchases from related parties of crude oil is as
follows (in thousands).
<TABLE>
<CAPTION>
One Month Eleven
Year Ended Year Ended Ended Months Ended
December 31, December 31, December 31, November 30,
1998 1997 1996 1996
------------ ----------- ----------- -----------
(Predecessor)
<S> <C> <C> <C> <C>
Sales to affiliates $38,718 $443,606 $52,449 $1,403,951
Purchases from affiliates $42,814 $183,490 $ 2,988 $ 327,963
</TABLE>
Clearing of Commodities Futures Transactions
The Partnership cleared a portion of its commodity futures transactions on
the NYMEX through Basis Clearing, Inc., a wholly-owned subsidiary of Basis. In
April 1997, Basis Clearing, Inc. ceased its clearing activities for the
Partnership. The Partnership paid commissions to Basis Clearing, Inc. of
$29,000.
<PAGE> 43
The Predecessor cleared its NYMEX transactions through Basis Clearing, Inc.
and Phibro Energy Clearing, Inc., a wholly-owned subsidiary of Phibro Inc., a
wholly-owned subsidiary of Salomon. The Predecessor paid commissions to these
entities of $645,000 for the eleven months ended November 30, 1996.
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 $15,428,000 and $14,973,000 for the years ended December 31,
1998 and 1997, respectively, and $703,000 for the one month ended December 31,
1996.
The Partnership entered into a Corporate Services Agreement with Basis
pursuant to which Basis, directly or through its affiliates, provided certain
administrative and support services for the benefit of the Partnership. Such
services included human resources, tax, accounting, data processing, NYMEX
transaction clearing and other similar administrative services. The Partnership
no longer receives any services under the Corporate Services Agreement. Charges
by Basis under the Corporate Services Agreement during the period in 1997 that
Basis was a related party to the Partnership were approximately $100,000 per
month. Charges by Basis under the Corporate Services Agreement were $120,000
for the one month ended December 31, 1996.
For the one month ended December 31, 1996, those persons who managed and
operated the Partnership were employees of Basis or Howell, providing services
to the General Partner under a transition services agreement. The total amount
paid for the services and the related benefit costs were $344,000 to Basis and
$359,000 to Howell.
Basis allocated certain general and administrative costs to the Predecessor
for ancillary services, insurance and office space. These costs amounted to
approximately $1,100,000 for the eleven months ended November 30, 1996.
Treasury Services
The Partnership entered into a Treasury Management Agreement with Basis.
Effective May 1, 1997, Salomon replaced Basis as a party to the Treasury
Management Agreement. Under the Treasury Management Agreement, the Partnership
invests excess cash with Salomon and earns interest at market rates. At
December 31, 1998 and 1997, the Partnership had $9.0 million and $14.0 million
in funds, respectively, deposited with Salomon under the Treasury Management
Agreement. Such amounts have been classified in the consolidated balance sheets
as cash and cash equivalents. For the years ended December 31, 1998 and 1997,
the Partnership earned interest of $288,000 and $833,000, respectively, on the
investments with Salomon. For the one month ended December 31, 1996, the
Partnership earned interest of $52,000 on these loans by the Partnership to
Basis.
Credit Facilities
As discussed in Note 8, Salomon provides Credit Facilities to the
Partnership. For the years ended December 31, 1998 and 1997 and the one month
ended December 31, 1996, the Partnership paid Salomon $578,000, $730,000 and
$102,000, respectively, for guarantee fees under the Credit Facilities. The
Partnership paid Salomon $18,000 for interest under the Credit Facilities during
1998. The Partnership paid Basis $85,000 for interest under the Credit
Facilities during 1997.
14. Supplemental Cash Flow Information
Cash received by the Partnership for interest for the years ended December
31, 1998 and 1997 was $422,000 and $1,139,000, respectively. Payments of
interest were $274,000 and $122,000 for the year ended December 31, 1998 and
1997, respectively.
Cash received by the Predecessor for imputed interest was $299,000 for the
eleven months ended November 30, 1996.
Cash paid for state income taxes and the imputed cash payments made by the
Predecessor for federal income taxes totaled $6,030,000 during the eleven months
ended November 30, 1996 related to 1995.
<PAGE> 44
15. Employee Benefit Plans
The Partnership does not directly employ any of the persons responsible for
managing or operating the Partnership. Beginning January 1, 1997, employees of
the General Partner provide those services and are covered by various retirement
and other benefit plans. The General Partner's employees participated in the
plans of Basis in 1997. Beginning in 1998, the General Partner maintained its
own plans.
In order to encourage long-term savings and to provide additional funds for
retirement to its employees, the General Partner sponsors a profit-sharing and
retirement savings plan. Under this plan, the General Partner's matching
contribution is calculated as the lesser of 50% of each employee's annual pretax
contribution or 3% of each employee's total compensation. The General Partner
also made a profit-sharing contribution of at least 3% of each eligible
employee's total compensation. The General Partner's costs relating to this
plan were $619,000 and $474,000 for the years ended December 31, 1998 and 1997,
respectively. The Predecessor's costs relating to this plan were $267,000 for
the eleven months ended November 30, 1996.
The General Partner also provided certain health care and survivor benefits
for its active employees. In 1998, these plans were fully-insured. In 1997 and
1996, these benefit programs were self-insured. In 1999, these plans will be
self-insured. The expenses of the General Partner for these benefits were
$1,338,000, $1,731,000 and $200,000 in 1998, 1997 and for the one month ended
December 31, 1996, respectively. Expenses allocated to the Predecessor for
these benefits were $369,000 for the eleven months ended November 30, 1996.
The General Partner also adopted two new plans in January 1997 and amended
these plans in January 1998. These plans are a restricted unit plan
("Restricted Unit Plan") for key employees of the General Partner and the
Genesis Incentive Compensation Plan ("Incentive Plan").
Restricted Unit Plan
In January 1997, the General Partner adopted a restricted unit plan for key
employees of the General Partner that provided for the award of rights to
receive Common Units under certain restrictions, including meeting thresholds
tied to Available Cash and Adjusted Operating Surplus. Initially, rights to
receive 291,000 Common Units were available under the restricted unit plan with
rights to receive 194,000 Common Units allocated to approximately 30
individuals. The restricted units would vest upon the conversion of
Subordinated OLP Units to Common OLP Units. In the event of early conversion of
a portion of the Subordinated OLP Units into Common OLP Units, the restricted
units would vest in the same proportion. The Partnership recorded no
compensation expense related to the restricted unit plan in 1997 due to
uncertainty as to whether the necessary vesting conditions would be met.
Likewise, the restricted units were not considered in diluted net income per
common unit in 1997 as none of the vesting conditions had been met in any
period.
In January 1998, the restricted unit plan was amended and restated, and the
thresholds tied to Available Cash and Adjusted Operating Surplus were
eliminated. The discussion that follows is based on the terms of the Amended
and Restated Restricted Unit Plan (the "Restricted Unit Plan"). Initially,
rights to receive 291,000 Common Units are available under the Restricted Unit
Plan. From these Units, rights to receive 240,000 Common Units (the "Restricted
Units") have been allocated to approximately 32 individuals, subject to the
vesting conditions described below and subject to other customary terms and
conditions. The remaining rights to receive 51,000 Common Units initially
available under the Restricted Unit Plan may be allocated or issued in the
future to key employees on such terms and conditions (including vesting
conditions) as the Compensation Committee of the General Partner ("Compensation
Committee") shall determine.
Upon "vesting" in accordance with the terms and conditions of the
Restricted Unit Plan, Common Units allocated to a plan participant will be
issued to such participant. Units issued to participants may be newly issued
Units acquired by the General Partner from the Partnership at then prevailing
market prices or may be acquired by the General Partner in the open market. In
1998, one-third of the Restricted Units allocated to each individual vested and
the units issued were acquired on the open market. In either case, the
associated expense will be borne by the Partnership. Until Common Units have
vested and have been issued to a participant, such participant shall not be
entitled to any distributions or allocations of income or loss and shall not
have any voting or other rights in respect of such Common Units. The
participant shall receive cash awards based on the number of non-vested units
held by such participant to the extent that distributions are paid on
Subordinated OLP Units. To date, no distributions have been paid with respect
to Subordinated OLP Units. No consideration will be payable by the
<PAGE> 45
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 1998, the Partnership recorded expense of $1,617,000 related to the
Restricted Units.
Incentive Plan
The Incentive Plan is designed to enhance the financial performance of the
Partnership by rewarding the executive officers and other specific key employees
for achieving annual financial performance objectives. The Incentive Plan will
be administered by the Compensation Committee. Individual participants and
payments, if any, for each calendar year will be determined by and in the
discretion of the Compensation Committee. No incentive payment will be made
with respect to any year unless (i) the aggregate MQD in the Incentive Plan year
has been distributed to each holder of Common Units, plus any arrearage thereon,
(ii) the Adjusted Operating Surplus generated during such year has equaled or
exceeded the sum of the MQD on all of the outstanding Common Units and the
related distribution on the General Partner's interest during such year and
(iii) no APIs are outstanding. In addition, incentive payments will not exceed
$375,000 with respect to any year unless (i) each holder of Subordinated OLP
Units has also received the aggregate MQD and (ii) the Adjusted Operating
Surplus generated during such year exceed the sum of the MQD on all of the
outstanding Common Units and Subordinated OLP Units and the related distribution
on the General Partner's interest during such year. Any incentive payments will
be at the discretion of the Compensation Committee, and the General Partner will
be able to amend or change the Incentive Plan at any time. No incentive
payments have been made under the Incentive Plan, although the Compensation
Committee has awarded performance bonuses.
16. Income Taxes
The components of the provision for income taxes for the Predecessor are as
follows (in thousands).
November 30,
1996
-------------
Current -
Federal $4,656
State 523
Total current 5,179
Deferred -
Federal (12)
------
Total deferred (12)
------
Total provision $5,167
======
A reconciliation of income taxes computed at the federal statutory rate to
income taxes computed at the Predecessor's effective tax rate is as follows (in
thousands).
November 30,
1996
-------------
Provision for income taxes at
the statutory rate $4,822
State taxes, net of federal
tax benefit 340
Other 5
------
Provision for income taxes $5,167
======
Net operating loss carryforwards have not been utilized as a reduction
against the Predecessor's future tax liability. Rather, as the losses were
utilized on the consolidated tax return, the benefit has been reflected as a
contribution from Basis in the Predecessor's equity in the year of benefit.
17. 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.
<PAGE> 46
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.
18. 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.
19. 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, 1998, 1997 and 1996 are as follows (in thousands).
<TABLE>
<CAPTION>
1998 1997 1996
----------------------- ----------------------- ----------------------
Net Net Net
Carrying Fair Gains Carrying Fair Gains Carrying Fair Gains
Amount Value (Losses) Amount Value (Losses) Amount Value (Losses)
-------- ----- -------- -------- ----- -------- -------- ----- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Option contracts written $ - $ - $ - $1,356 $803 $553 $ - $ - $ -
</TABLE>
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.
20. Commitments and Contingencies
The Partnership uses surface, vehicle and office leases in the course of its
business operations. The Partnership also leases a segment of pipeline and four
tanks for use in its pipeline operations. The future minimum rental payments
under all noncancelable operating leases as of December 31, 1998, were as
follows (in thousands).
1999 $1,152
2000 687
2001 670
2002 670
2003 459
2004 and thereafter 863
------
Total minimum lease obligations $4,501
======
Total operating lease expense was as follows (in thousands).
Year ended December 31, 1998 $1,921
Year ended December 31, 1997 $1,060
One month ended December 31, 1996 $ 133
Eleven months ended November 30, 1996 $ 522
<PAGE> 47
The Partnership has contractual commitments (primarily forward contracts)
arising in the ordinary course of business. At December 31, 1998, the
Partnership had commitments to purchase 19,840,000 barrels of crude oil at fixed
prices ranging from $9.60 to $17.46 per barrel extending to February 2000, and
commitments to sell 19,893,000 barrels of crude oil at fixed prices ranging from
$9.65 to $20.25 per barrel extending to January 2000. Additionally, the
Partnership had commitments to purchase 15,610,000 barrels of crude oil
extending to December 1999, and commitments to sell 14,427,000 barrels of crude
oil extending to October 1999, 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.
The Partnership is subject to lawsuits in the normal course of business and
examinations by tax and other regulatory authorities. Such matters presently
pending are not expected to have a material adverse effect on the financial
position, results of operations or cash flows of the Partnership.
As part of the formation of the Partnership, Basis and Howell agreed to each
retain liability and responsibility for the defense of any future lawsuits
arising out of activities conducted by Basis and Howell prior to the formation
of the Partnership and have also agreed to cooperate in the defense of such
lawsuits.
<PAGE> 48
EXHIBIT 10.21
AMENDMENT NO. 2 TO LOAN AGREEMENT
THIS AMENDMENT NO. 2 TO LOAN AGREEMENT ("Amendment No. 2")
made and entered into as of the 31st day of December, 1998, by
and between GENESIS CRUDE OIL, L.P. ("Borrower") with offices and
place of business at 500 Dallas, Houston, Texas 77002 and BANK
ONE, TEXAS, N.A., a national banking corporation, with offices at
910 Travis, Houston, Texas 77002 ("Lender").
WHEREAS, Borrower and Lender entered into that certain Loan
Agreement dated as of August 14, 1998, as amended (the "Loan
Agreement"); and
WHEREAS, Borrower and Lender wish to amend certain terms of
the Loan Agreement as provided for herein.
NOW, THEREFORE, in consideration of the premises and the
mutual covenants and agreements contained herein, Borrower and
Lender agree as follows:
Section 1. Amendment to Loan Agreement
1.1 The definitions of "Base Inventory" and "Base Inventory
Value" are hereby added to Section 1.2 of the Loan Agreement and
read as follows.
"(4A) "Base Inventory" means those quantities of crude
oil owned by Borrower and located in the United States that
are reflected in Property and Equipment on the Borrower's
balance sheet."
"(4B) "Base Inventory Value" means Base Inventory
valued at the lesser of (i) the cost of such inventory to
Borrower and (ii) the fair market value of such inventory as
of the relevant Reporting Date."
1.2 The definition of "Current Ratio" is hereby amended to read
as follows.
"(18) "Current Ratio" shall mean current assets plus
Base Inventory Value, divided by current liabilities,
excluding amounts owed pursuant to the Revolving Line of
Credit."
1.3 The definition of "Eligible Inventory" is hereby amended to
read as follows.
"(22A) "Eligible Inventory" means all crude oil owned
by Borrower and located in the United States that is held or
designated for sale to third parties, valued for purposes of
each Borrowing Base Report at the lesser of (i) the cost of
such inventory to Borrower and (ii) the fair market value of
such inventory as of the relevant Reporting Date. Eligible
Inventory includes Base Inventory Value."
Section 2. Representations and Warranties
The Borrower represents and warrants to the Lender that:
2.1 All of the representations and warranties set forth in the
Loan Agreement are true and correct as of the date of this
Amendment No. 2 as if made on the date hereof, and the Borrower
is as of the date hereof in compliance with all of the
affirmative and negative covenants in the Loan Agreement, as
amended by this Amendment No. 2.
2.2 The Borrower is duly authorized and empowered to create and
issue and to execute and deliver each of the documents listed in
Section 3.1 hereof (the "Amendment Documents"), and all other
instruments referred to or mentioned herein to which Borrower is
a party, and all corporate action requisite for the due creation,
issuance, execution and delivery of the Amendment Documents has
been duly and effectively taken. The Amendment Documents to
which Borrower is a party when executed and delivered will be
valid and binding obligations of the Borrower enforceable in
accordance with their terms (subject to any applicable
bankruptcy, insolvency or other laws generally affecting the
enforcement of creditors' rights and to the extent specific
remedies may be limited by equitable principles). The Amendment
Documents do not violate any provisions of the Borrower's
corporate charter or bylaws, or any contract, agreement, law or
regulation to which the Borrower is subject, and the same do not
require the consent or approval of any regulatory authority or
governmental body of the United States or any state.
Section 3. Conditions Precedent
3.1 It is a condition precedent to the execution and performance
by Lender of this Amendment No. 1, that the Lender shall have
received copies of the following closing documentation, all in
form and substance satisfactory to Lender and executed by the
Borrower where necessary.
(1) This Amendment No. 2;
(2) The Notice of Final Agreement; and
(3) Such other documentation as Lender may require.
Section 4. Sundry Provisions
4.1 This Amendment No. 2 shall be deemed to be a contract made
under and shall be construed in accordance with and governed by
the laws of the state of Texas.
4.2 All terms and provisions of the Loan Agreement not
specifically amended hereby shall remain in full force and
effect.
4.3 All capitalized terms not otherwise defined herein shall
have the meaning given them in the Loan Agreement.
IN WITNESS WHEREOF, the parties hereto have caused this
instrument to be duly executed in multiple counterparts, each of
which is an original instrument for all purposes, all as of the
day and year first above written.
GENESIS CRUDE OIL, L.P.
By: Genesis Energy, L.L.C., its
General Partner
By: /s/ Ross A. Benavides
----------------------
Ross A. Benavides
Chief Financial Officer
BANK ONE, TEXAS, N.A.
By: /s/ Kenneth J. Fatur
---------------------
Kenneth J. Fatur
Vice President
EXHIBIT 21.1
GENESIS ENERGY, L.P.
Subsidiaries of the Registrant
Genesis Crude Oil, L.P. - Delaware limited partnership (80.01%
general partner interest owned by Genesis Energy, L.P.)
Genesis Pipeline Texas, L.P. - Delaware limited partnership (100%
limited partner interest owned by Genesis Crude Oil, L.P.)
Genesis Pipeline USA, L.P. - Delaware limited partnership (100%
limited partner interest owned by Genesis Crude Oil, L.P.)
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS FINANCIAL INFORMATION EXTRACTED FROM THE ANNUAL REPORT ON
FORM 10-K OF GENESIS ENERGY, L.P. AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE
TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 7,710
<SECURITIES> 0
<RECEIVABLES> 172,234
<ALLOWANCES> 0
<INVENTORY> 1,966
<CURRENT-ASSETS> 185,216
<PP&E> 119,310
<DEPRECIATION> 20,707
<TOTAL-ASSETS> 297,173
<CURRENT-LIABILITIES> 183,514
<BONDS> 15,800
0
0
<COMMON> 0<F1>
<OTHER-SE> 0
<TOTAL-LIABILITY-AND-EQUITY> 297,173<F2>
<SALES> 2,216,942
<TOTAL-REVENUES> 2,233,475
<CGS> 2,184,529
<TOTAL-COSTS> 2,212,997<F3>
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 8,819
<INCOME-TAX> 0
<INCOME-CONTINUING> 7,056<F4>
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 7,056
<EPS-PRIMARY> 0<F5>
<EPS-DILUTED> 0<F6>
<FN>
<F1>GENESIS ENERGY, L.P. IS A MASTER LIMITED PARTNERSHIP AND THEREFORE HAS NO
COMMON STOCK OUTSTANDING.
<F2>GENESIS ENERGY, L.P. IS A MASTER LIMITED PARTNERSHIP. ITS BALANCE SHEET
INCLUDES MINORITY INTERESTS IN ITS SUBSIDIARY, GENESIS CRUDE OIL, L.P. OF
$29,988 AND PARTNERS' CAPITAL CONSISTING OF THE CAPITAL OF THE COMMON
UNITHOLDERS OF $66,832, THE CAPITAL OF THE GENERAL PARTNER OF $1,357 AND
TREASURY UNITS OF $318.
<F3>TOTAL COSTS INCLUDES DEPRECIATION AND AMORTIZATION OF $7,719.
<F4>THE MINORITY INTERESTS IN NET INCOME OF GENESIS ENERGY, L.P. IS $1,763.
<F5>BASIC NET INCOME PER COMMON UNIT IS $0.80.
<F6>DILUTED NET INCOME PER COMMON UNIT IS $0.80.
</FN>
</TABLE>
