==============================================================================
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, 1997
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.
---------
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 2, 1998, was approximately $165 million.
==============================================================================
2
GENESIS ENERGY, L.P.
1997 FORM 10-K ANNUAL REPORT
Table of Contents
Page
Part I ----
Item 1. Business 3
Item 2. Properties 10
Item 3. Legal Proceedings 10
Item 4. Submission of Matters to a Vote of Security Holders 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 8. Financial Statements and Supplementary Data 17
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure 17
Part III
Item 10. Directors and Executive Officers of the Registrant 17
Item 11. Executive Compensation 20
Item 12. Security Ownership of Certain Beneficial Owners and Management 22
Item 13. Certain Relationships and Related Transactions 23
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 23
3
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., (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 stations, 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 four common
carrier pipeline systems. In 1997, the gathering and marketing operations
contributed approximately 49% of the Partnership's total gross margin and the
pipeline operations contributed the remaining 51%.
Genesis currently purchases approximately 105,000 bpd of crude oil at the
wellhead from approximately 7,800 leases. Genesis utilizes its trucking fleet
of approximately 75 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.
Genesis currently transports a total of approximately 86,000 barrels per
day on its three principal 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. Additionally, Genesis owns an interstate pipeline in
the Gulf of Mexico serving Main Pass Block 64. Approximately 1.8 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). 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 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.
4
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 futures positions. By analyzing information in its
database through 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.
Year 2000
The Partnership utilizes software and technologies throughout its
operations that will be affected by the date change in the year 2000. The
General Partner has developed and initiated a plan to identify, evaluate and
ensure its systems are compliant with the requirements to process transactions
in the year 2000 and beyond. Many of the Partnership's operating and financial
systems are already compliant. The partnership's remaining operational and
financial systems are scheduled for enhancements in phases and will be compliant
by the year 2000. The Partnership is communicating with software vendors,
business partners and others with which it conducts business to obtain
assurances that the systems of those parties will be year 2000 compliant. The
General Partner does not believe that the total future cost associated with
potential year 2000 compliance issues and conversion of systems will materially
impact its results of operations.
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 will be 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
5
batteries at the
lease or production point, accurate measurement of crude oil volumes received,
avoidance of spills and effective management of pipeline deliveries. Accounting
and other administrative services include securing division orders (statements
from interest owners affirming the division of ownership in crude oil purchased
by the Partnership), providing statements of the crude oil purchased each month,
disbursing production proceeds to interest owners and calculation and payment of
production taxes on behalf of interest owners. In order to compete effectively,
the Partnership must maintain records of title and division order interests in
an accurate and timely manner for purposes of making prompt and correct payment
of crude oil production proceeds on a monthly basis, together with the correct
payment of all severance and production taxes associated with such proceeds. In
1997, 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 has agreed in a
Master Credit Support Agreement to provide certain amounts of credit support
until December 31, 1999, in the form of guarantees from time to time at the
Partnership's request. 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 Genesis 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.
Approximately 50% of the leasehold barrels were purchased from nine producers,
with one producer accounting for 29% of 1997 leasehold purchases. 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 Koch Oil Company, Scurlock Permian Oil
Company, 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
and the Main Pass System operate in areas 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
6
will be built in the same geographic areas in the near future,
provided that Genesis' pipelines continue to have available capacity to satisfy
demands of shippers and that its tariffs remain at reasonable levels.
Employees
To carry out various purchasing, gathering, transporting and marketing
activities, the General Partner employs approximately 240 employees, including
management, truck drivers and other operating personnel, division order
analysts, accountants, tax specialists, contract administrators, traders,
schedulers, marketing and credit specialists and employees involved in Genesis'
pipeline operations. None of such employees is represented by labor unions, and
the General Partner believes that the relationships with such 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. These 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.
7
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, Mississippi and Main Pass 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.
Energy Policy Act of 1992 and Subsequent Developments. In October of
1992 Congress passed the Energy Policy Act of 1992 ("Energy Policy Act"). The
Energy Policy Act is significant in that it requires FERC to promulgate
regulations establishing a simplified and generally applicable ratemaking
methodology under the ICA that will streamline FERC procedures to avoid
unnecessary costs and delays. As a fundamental part of this simplification and
streamlining of procedures, the Energy Policy Act deemed pipeline rates in
effect for the 365-day period ending on the date of enactment of the Energy
Policy Act or that were in effect on the 365th day preceding enactment and had
not been subject to complaint, protest or investigation during the 365-day
period to be "just and reasonable" under the ICA. In regard to these so-called
"grandfathered" rates, the Energy Policy Act provides that such grandfathered
rates may only be challenged under the following limited circumstances: (i) a
substantial change has occurred since enactment in either the economic
circumstances of the oil pipeline or the nature of the services which were a
basis for the rate; (ii) the complainant was contractually barred from
challenging the rate prior to enactment (in which event, following the
expiration of the contractual bar, the complainant has a very limited time
period to lodge a complaint); or (iii) the rate is unduly discriminatory or
preferential.
8
FERC responded to the requirement that it promulgate rules simplifying
and streamlining the ratemaking process in a series of three related rulemaking
proceedings, the principal provisions of which took effect on January 1, 1995.
On October 22, 1993, FERC first responded to this mandate by issuing Order No.
561, which adopts a new indexing rate methodology for petroleum pipelines.
Under the new regulations, which were effective January 1, 1995, 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 under the Energy Policy Act
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 Energy Policy Act's threshold requirement
to show that a "substantial change" has occurred in the economic circumstances
or the nature of the pipeline's services. Rate decreases are mandated under the
new regulations if the index decreases and the carrier has been collecting rates
equal to the rate ceiling. The new indexing methodology can be applied to any
existing rate, including in particular all "grandfathered" rates, but also
applies to rates under investigation. If such rate is subsequently adjusted,
the ceiling level established under the index must be likewise adjusted.
In Order No. 561, FERC emphasized that the combination of grandfathered
rates plus use of the new indexation methodology is expected to be the generally
prevailing methodology. 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. In this
regard, the carrier may not use the cost-of-service methodology to change an
existing rate unless the pipeline can demonstrate that there is 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. Similarly,
any party complaining of any existing indexed rate or challenging any indexed
rate change (other than a grandfathered rate) must provide a reasonable basis
for FERC to conclude that there may be a substantial divergence between actual
costs experienced and the rate resulting from the index such that the carrier's
rates are excessive and, therefore, unjust and unreasonable, and should be
investigated in a cost-of-service proceeding. 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.
These alternative ratemaking methodologies to FERC's indexing
methodology were finalized on October 28, 1994, when FERC issued Order Nos. 571
and 572. In Order No. 571, FERC articulated cost-of-service filing and
reporting requirements to be applicable to a pipeline's initial rates and to
situations where indexing is determined to be inappropriate. Order No. 571 also
adopted rules for the establishment of revised depreciation rates, and revised
the information required to be reported by pipelines in their FERC Form No. 6,
"Annual Report for Oil Pipelines." Order No. 572 establishes the filing
requirements and procedures that must be followed when a pipeline seeks to
charge market-based rates.
On May 10, 1996, the Court of Appeals for the District of Columbia
Circuit affirmed Order Nos. 561, 571 and 572. The Court held that by
establishing a general indexing methodology along with limited exceptions to
indexed rates, FERC had fulfilled its responsibilities under the Energy Policy
Act and reasonably balanced its dual responsibilities of ensuring just and
reasonable rates and streamlining ratemaking through generally applicable
procedures. Among other things, the Court affirmed FERC's interpretation of the
Energy Policy Act respecting challenges to grandfathered rates in the context of
rate increase filings using the indexation methodology.
Because of the novelty and uncertainty surrounding the indexing
methodology as well as the numerous untested issues associated with the trended
original cost methodology and light-handed regulation, the General Partner is
unable to predict with certainty whether, how or the extent to which FERC may
apply these methodologies to the Jay, Mississippi and Main Pass Systems, which
FERC regulates. The General Partner adopted Howell's preexisting tariffs and
rates pertaining to the Jay, Mississippi and Main Pass Systems and intends to
rely on the indexation procedures available under FERC regulations.
Nevertheless, by protest, complaint or shipper
9
challenge under the Energy Policy
Act 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, Mississippi and Main Pass
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 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.
10
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, 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 onshore and one offshore common carrier crude oil pipeline. The onshore
pipelines and related gathering systems consist of the 553-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 offshore
pipeline is located in the Gulf of Mexico. It is 5.5 miles long and extends
from Main Pass Block 64 to a connection with another pipeline. The Partnership
also owns approximately 1.8 million barrels of storage capacity associated with
the onshore pipelines. These storage capacities include approximately 200,000
barrels each on the Mississippi and Jay Systems and 1.2 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, 1997, the trucking fleet consisted of approximately 75 tractor-
trailers. The trucking fleet generally hauls the crude oil to one of the 106
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 liability thereunder, if any,
will not have a material adverse effect on the financial condition or results of
operations of the Partnership. See Note 15 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, 1997.
11
PART II
Item 5. Market for Registrant's Common Units and Related Security Holder
Matters
The following table sets forth, for the periods indicated, the high and low
sale prices per Common Unit, as reported on the New York Stock Exchange
Composite Tape, and the amount of cash distributions paid per Common Unit.
Price Range Cash
High Low Distributions<F1>
------- ------- -----------------
1997
-----
First Quarter $21.500 $20.375 $ -
Second Quarter $21.375 $18.125 $0.66
Third Quarter $20.750 $19.625 $0.50
Fourth Quarter $21.250 $16.375 $0.50
1996
----
One Month Ended December 31, 1996 $21.125 $20.250 $ -
_____________________
<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>
As of January 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, 1997, Salomon had not been required to provide any distribution support.
12
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
year ended December 31, 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.
Eleven
Year Year One Month Months
Ended Ended Ended Ended Year Ended
December 31,December 31,December 31,November 30, December 31,
1997 1996<F1> 1996 1996 1995 1994 1993
----------- ----------- ----------- ----------- ---------------------------------
(Pro forma) (Predecessor) (Predecessor)
(Unaudited)
Income Statement Data:
Revenues:
Gathering and marketing revenues $3,354,939 $4,565,834 $370,559 $3,598,107 $3,440,065 $1,830,721 $2,171,056
Pipeline revenues 17,989 16,780 1,426 - - - -
---------- ---------- -------- ---------- ---------- ---------- ----------
Total revenues 3,372,928 4,582,614 371,985 3,598,107 3,440,065 1,830,721 2,171,056
Cost of sales:
Crude cost 3,331,184 4,526,363 366,723 3,573,086 3,409,759 1,806,241 2,153,901
Field operating costs 12,107 15,092 1,290 6,744 7,152 7,778 8,046
Pipeline operating costs 6,016 4,978 463 - - - -
---------- ---------- -------- ---------- ---------- ---------- ----------
Total cost of sales 3,349,307 4,546,433 368,476 3,579,830 3,416,911 1,814,019 2,161,947
---------- ---------- -------- ---------- ---------- ---------- ----------
Gross margin 23,621 36,181 3,509 18,277 23,154 16,702 9,109
General and administrative expenses 8,557 9,470 1,363 3,316 3,658 3,858 4,111
Depreciation and amortization 6,300 6,834 518 1,396 4,815 7,530 7,947
---------- ---------- -------- ---------- ---------- ---------- ----------
Operating income 8,764 19,877 1,628 13,565 14,681 5,314 (2,949)
Interest income (expense) 1,063 56 56 294 173 (685) (1,215)
Other income (expense) 21 (74) - (83) (197) 82 122
---------- ---------- -------- ---------- ---------- ---------- ----------
Net income (loss) before minority
interests 9,848 19,859 1,684 13,776 14,657 4,711 (4,042)
Minority interests 1,968 3,970 337 - - - -
---------- ---------- -------- ---------- ---------- ---------- ----------
Net income (loss) <F2> $ 7,880 $ 15,889 $ 1,347 $ 13,776 $ 14,657 $ 4,711 $ (4,042)
========== ========== ======== ========== ========== ========== ==========
Net income per common unit-basic
and diluted $ 0.90 $ 1.81 $ 0.15 N/A N/A N/A N/A
========== ========== ======== ========== ========== ========== ==========
Balance Sheet Data (at end of period):
Current assets $ 232,202 $ 410,371 $410,371 N/A $ 279,285 $ 184,253 $ 132,957
Total assets 331,114 509,900 509,900 N/A 283,036 193,367 149,430
Long-term liabilities - - - N/A - - -
Equity of parent - - - N/A (8,437) 4,393 15,578
Minority interest 28,225 26,257 26,257 N/A - - -
Partners' capital 78,351 85,080 85,080 N/A - - -
Other Data:
Maintenance capital expenditures <F3> $ 3,785 $ 2,535 $ 106 $ 1,100 $ 17 $ 56 $ 122
EBITDA <F4> $ 15,085 $ 26,637 $ 2,146 $ 14,878 $ 19,299 $ 12,926 $ 5,120
Volumes (bpd):
Gathering and marketing:
Wellhead 104,506 116,263 120,553 83,239 83,551 89,788 90,974
Bulk and exchange 346,760 463,054 380,354 417,939 439,060 214,519 236,555
Pipeline 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 (loss) 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 (loss) (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>
13
The table below summarizes the Partnership's quarterly financial data for 1997.
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. In order to make the comparisons more meaningful, the results of
operations of the Partnership for the year ended December 31, 1997 are compared
to the pro forma results of operations for the year ended December 31, 1996.
The pro forma results of operations for the year ended December 31, 1996 are
compared to the pro forma results of operations for the year ended December 31,
1995.
Results of Operations
Selected financial data for this discussion of the results of operations
follows, in thousands.
Years Ended
December 31,
----------------------------------------
1997 1996 1995
---------- ---------- ----------
(Pro forma)
(Unaudited)
Revenues
Gathering & marketing $3,354,939 $4,565,834 $4,026,873
Pipeline $ 17,989 $ 16,780 $ 18,577
Gross margin
Gathering & marketing $ 11,648 $ 24,379 $ 26,571
Pipeline $ 11,973 $ 11,802 $ 14,055
General and administrative
expenses $ 8,557 $ 9,470 $ 9,148
Depreciation and amortization $ 6,300 $ 6,834 $ 10,146
Operating income $ 8,764 $ 19,877 $ 21,332
Interest income (expense) net $ 1,063 $ 56 $ -
The profitability of Genesis and the entities from which Genesis was formed
depends to a significant extent upon their ability to maximize gross margin. The
gross margin from gathering and marketing operations is generated by the
difference between the price of crude oil at the point of purchase and the price
of crude oil at the point of sale, minus the associated costs of aggregation and
transportation. In addition to purchasing crude oil at the wellhead, Genesis
purchases crude oil in bulk at major pipeline terminal points and enters into
exchange transactions with third parties. These bulk and exchange transactions
are characterized by large volumes and narrow profit margins on purchase and
sales transactions, and the absolute price levels for crude oil do not
necessarily bear a relationship to gross margin, although such price levels
significantly impact revenues and cost of sales. Because period-to-period
variations in revenues and cost of sales are not generally meaningful in
analyzing the variation in gross margin for gathering and marketing operations,
such changes are not addressed in the following discussion. Pipeline revenues
and gross margins are 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.
14
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, 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 has 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.
Pro Forma Year Ended December 31, 1996 Compared with Pro Forma Year Ended
December 31, 1995
Gross Margin. Gathering and marketing gross margin decreased $2.2 million
or 8% to $24.4 million for the year ended December 31, 1996, as compared to
$26.6 million for the year ended December 31, 1995. Field operating expenses
increased by $0.4 million, primarily due to higher fuel costs to operate
Genesis' fleet of tractors-trailers.
In the first half of 1996, U.S. crude oil inventories were at historically
low levels and refiner demand for prompt delivery of crude oil was strong,
leading to substantial backwardation in crude oil prices. This backwardated
market caused the sales prices received by the Partnership to increase faster
than prices paid to producers at the wellhead, which resulted in increasing
gross margins for the six months ended June 30, 1996 as compared to the six
months ended June 30, 1995. In the second half of 1996, due to increasing crude
oil inventories and reduced refiner demand for prompt delivery of crude oil, the
sales prices received by the Partnership decreased faster than the prices paid
to producers, particularly as other gathering companies continued to pay higher
producer bonuses in an effort to increase market share. As a result of the
expiration of a favorable provision in a large crude oil purchase contract with
one of the Partnership's principal customers that reduced gross margins by
approximately $1.0 million and the third and fourth quarters' unfavorable
pricing situation, pro forma gathering and marketing gross margin declined from
the first half of 1996 to the second half of 1996.
15
Pipeline gross margin decreased $2.3 million or 16% to $11.8 million for
the year ended December 31, 1996, as compared to $14.1 million for the year
ended December 31, 1995. Although increased demand for crude oil resulted in
increased gross margin in the gathering and marketing operations during the
first half of 1996, pipeline operations experienced a countercyclical decline in
gross margin during the same period. Pipeline volumes per day increased
slightly in the second half of 1996. Low U.S. crude oil inventories resulted in
reduced pipeline utilization, which resulted in a decline of 9% in pipeline
throughput during 1996 compared to 1995. Pipeline revenues for 1995 include
nine months of tank rental fees totaling $0.9 million charged to a third party
for usage of storage tanks that the Partnership owns in northwest Houston
whereas the 1996 period includes three months of tank rental fees totaling $0.3
million.
Depreciation and Amortization. Depreciation and amortization expense
decreased $3.3 million or 33% to $6.8 million for the year ended December 31,
1996, as compared to $10.1 million for the year ended December 31, 1995. Of the
reduction, $2.4 million resulted from the full amortization in 1995 of costs
capitalized from the JM Petroleum Corporation acquisition by Basis in 1991.
Liquidity and Capital Resources
Cash Flows
Net cash provided by operations was $20.2 million for the year ended
December 31, 1997. 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, and net cash
provided by operating activities was $21.5 million for the year ended December
31, 1995. The decrease during 1996 was primarily the result of an increase in
accounts receivable of $133.7 million, only partially offset by an increase of
$118.9 million in accounts payable.
Net cash used in investing activities was $5.7 million for the year ended
December 31, 1997, 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 the Predecessor was $2.0 primarily from the purchase of
26 new tractors and NYMEX seats contributed to Genesis. For the year ended
December 31, 1995, net cash provided by investing activities was $0.5 million,
primarily as a result of the sale of nonstrategic assets.
Net cash utilized in financing activities was $14.6 million in the year
ended December 31, 1997, related to the payment of distributions to 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 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 years ended
December 31, 1996 and 1995 were $2.5 million and $0.7 million, respectively.
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.
16
Working Capital and Credit Resources
Pursuant to the Master Credit Support Agreement, Salomon will provide
transitional 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 $400
million for the year ending December 31, 1998 and $300 million for the year
ending December 31, 1999 (to be reduced in each case by the amount utilized at
any one time pursuant to the Working Capital Facility and 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 three-year period, thereby increasing the cost of the credit support
provided to the Partnership under the Guaranty Facility, from a below-market
rate to a rate that may be higher than rates paid to independent financial
institutions for similar credit.
Salomon has agreed to provide to the Partnership, through March 31, 1998, a
Working Capital Facility of up to $50 million, which amount includes 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 the Partnership's
business. The total amounts outstanding at any one time under this Working
Capital Facility will correspondingly reduce the amounts available under the
Guaranty Facility. The interest rate for the Working Capital Facility is the
federal funds rate plus 5/8%. The Partnership expects to arrange for a working
capital facility through one or more third party lenders or an extension of the
Working Capital Facility with Salomon prior to the expiration of the
availability of the Working Capital Facility.
At December 31, 1997, the aggregate amount of obligations covered by
guarantees was $259 million, including $124 million in payable obligations and
$135 million in estimated crude oil purchase obligations for January 1998. No
direct cash advances or letters of credit were outstanding at year end.
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.
There can be no assurance of the availability or the terms of credit for
the Partnership. Salomon does not currently foresee any circumstances under
which it would provide guarantees or other credit support after the three-year
credit support period. 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. Prior to
December 1999, management of the Partnership intends to replace the Guaranty
Facility with a letter of credit facility with one or more third party lenders.
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 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. 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 1997, the Partnership paid total distributions per unit of $1.66 per
unit, representing distributions for the period from the Partnership's inception
in December 1996 through September 30, 1997. A distribution of $0.50 per unit,
applicable to the fourth quarter of 1997, was paid on February 13, 1998 to
holders of record on January 30, 1998.
17
Year 2000
The Partnership utilizes software and technologies throughout its
operations that will be affected by the date change in the year 2000. The
General Partner has developed and initiated a plan to identify, evaluate and
ensure its systems are compliant with the requirements to process transactions
in the year 2000 and beyond. Many of the Partnership's operating and financial
systems are already compliant. The Partnership's remaining operational and
financial systems are scheduled for enhancements in phases and will be compliant
by the year 2000. The Partnership is communicating with software vendors,
business partners and others with which it conducts business to obtain
assurances that the systems of those parties will be year 2000 compliant. The
General Partner does not believe that the total future cost associated with
potential year 2000 compliance issues and conversion of systems will materially
impact its results of operations.
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 24.
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 will review
the external financial reporting of the Partnership, will recommend engagement
of the Partnership's independent accountants, and will review 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 49 Director and Chairman of the Board
John P. vonBerg 44 Director, Chief Executive Officer and
President
Mark J. Gorman 43 Director, Chief Operating Officer and
Executive Vice President
Michael A. Peak 44 Director
Paul N. Howell 79 Director
Ronald E. Hall 66 Director
Donald H. Anderson 49 Director
Herbert I. Goodman 75 Director
J. Conley Stone 66 Director
John M. Fetzer 44 Senior Vice President, Crude Oil
Allyn R. Skelton, II 46 Chief Financial Officer
Paul A. Scoff 39 General Counsel and Secretary
Allen R. Stanley 54 Vice President, Pipeline Operations
Ben F. Runnels 57 Vice President, Trucking Operations
Kerry W. Mazoch 51 Vice President, Crude Oil Acquisitions
18
Thomas W. Jasper has served as a Director of the General Partner since
December 1996. He was appointed to the position of Treasurer of Salomon Smith
Barney Holdings Inc. and its principal subsidiaries, Salomon Brothers Inc and
Smith Barney Inc. in December 1997. Mr. Jasper is 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 was responsible for
investment banking client relationships with European and Japanese multinational
subsidiaries in the United States. In February 1994, Mr. Jasper was named
Chairman of Salomon Brothers Hong Kong Limited and Chief Operating Officer for
the Asia-Pacific region. Mr. Jasper was originally made Regional Head of
Salomon Brothers Hong Kong Limited in July 1992. His previous responsibilities
with Salomon Brothers included managing the firm's Capital Markets Services
Group and its Interest Rate Swap Group. He joined Salomon Brothers in 1982.
Mr. Jasper was with Bankers Trust Company prior to 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 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.
Ronald E. Hall has served as a Director of the General Partner since December
1996. He served as Chairman of the Board of Howell from 1995 until May 1997 and
continues to serve as a director of Howell. From 1985 to 1995, Mr. Hall held
the position of President and Chief Executive Officer of CITGO Petroleum
Corporation ("CITGO"), a refining, marketing and distribution company. Mr. Hall
served as a director of CITGO from 1990 to 1995. Mr. Hall has also served as a
director of Getty Marketing Company since 1996 and as a director of Lodestar
Logistics Corporation since 1997.
Donald H. Anderson was elected to the Board of Directors of the General
Partner in March 1997. He was Chairman, President and Chief Executive Officer
of PanEnergy Services, Inc., from December 1994 to March 1, 1997. PanEnergy
Services, Inc., a subsidiary of PanEnergy Corp., 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
19
Plantation Pipe Line Company, a common carrier liquid petroleum products
pipeline transporter. From 1976 to 1987, Mr. Stone served in a variety of
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.
Allyn R. Skelton, II, has served as Chief Financial Officer of the General
Partner since December 1996. He served as Chief Financial Officer of Howell
from 1989 until October 1996, and served as Senior Vice President of Howell from
1993 to December 1996. Previously, he held the position of Controller of Howell
from 1985 to 1989. Mr. Skelton joined Howell in 1983 as Tax Manager. Prior to
joining Howell, he held various tax and financial positions with other oil
companies.
Paul A. Scoff has served as General Counsel and Secretary of the General
Partner since December 1996. He served as Senior Counsel for Basis Petroleum,
Inc. 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 1997 its officers and directors complied with all applicable filing
requirements in a timely manner except on three occasions. A Form 3 initial
filing for J. Conley Stone was filed two days late in February 1997. No
ownership of Common Units was included on the filing. A Form 3 initial filing
for Kerry W. Mazoch was due in August 1997 and was not filed until March 1998.
No ownership was included on the filing. A Form 4 filing regarding a purchase
of Common Units was not made by Allen R. Stanley for December 1997. The
information was subsequently included on a Form 5. The filing was 20 days late.
20
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 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").
Summary Compensation Table
Annual Compensation
---------------------------------
Other Annual All Other
Salary Bonus Compensation Compensation
Name and Principal Position Year $ $ $ <F1> $
- --------------------------- ---- ------- ------ ------------ ------------
John P. vonBerg 1997 350,000 50,000 - 9,550<F2>
Chief Executive Officer 1996 29,167 - - -
and President
Mark J. Gorman 1997 212,500 37,500 - 9,550<F2>
Executive Vice President 1996 17,500 - - -
and Chief Operating Officer
John M. Fetzer 1997 200,000 37,500 - 9,550<F2>
Senior Vice President, 1996 16,667 - - -
Crude Oil
Allyn R. Skelton, II 1997 175,000 17,500 - 9,550<F2>
Chief Financial Officer 1996 14,583 - - -
Allen R. Stanley 1997 140,000 20,000 - 7,134<F3>
Vice President, Pipeline 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>
Includes $4,750 of Company-matching contributions to a defined contribution plan
and $4,800 of profit-sharing contributions to a defined contribution plan.
<F3>
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>
In 1997, the Named Officers were awarded rights under a long-term incentive plan
(the Initial Restricted Unit Plan). That plan was amended and restated in
January 1998 and no longer qualifies as a long-term incentive plan.
Accordingly, awards under the amended and restated restricted unit plan will be
included in the Summary Compensation Table for 1998. As the awards made in 1997
were effectively terminated, they are not included in the table above.
Employment Agreements
The General Partner entered into employment agreements with the following
executive officers: Mr. vonBerg, Mr. Gorman, Mr. Fetzer, Mr. Skelton, Mr.
Stanley, Mr. Runnels and Mr. Scoff. The agreements have an
21
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.
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 235,000 Common Units (the "Restricted Units") have been allocated to
approximately 30 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 December 31, 1998. The remaining rights to receive 56,000
Common Units initially available under the Restricted Unit Plan may be allocated
or issued in the future to key employees on such terms and conditions (including
vesting conditions) as the Compensation Committee of the General Partner
("Compensation Committee") shall determine.
Upon "vesting" in accordance with the terms and conditions of the
Restricted Unit Plan, Common Units allocated to a plan participant will be
issued to such participant. Units issued to participants may be newly issued
Units acquired by the General Partner from the Partnership at then prevailing
market prices or may be acquired by the General Partner in the open market. In
either case, the associated expense will be borne by the Partnership. Until
Common Units have vested and have been issued to a participant, such participant
shall not be entitled to any distributions or allocations of income or loss and
shall not have any voting or other rights in respect of such Common Units. The
participant shall receive cash awards based on the number of non-vested units
held by such participant to the extent that distributions are paid on
Subordinated OLP Units. To date, no distributions have been paid with respect
to Subordinated OLP Units. No consideration will be payable by the plan
participants upon vesting and issuance of the Common Units. The plan
participant cannot sell the Common Units until one year after the date of
vesting.
Termination without cause in violation of a written employment agreement,
or a Significant Event as defined in the Restricted Unit Plan, will result in
immediate vesting of all non-vested units and conversion to Common Units without
any restrictions.
Incentive Plan
In January 1997, the General Partner adopted the Genesis Incentive
Compensation Plan (the "Incentive Plan") and amended it in January 1998. The
Incentive Plan is designed to enhance the financial performance of the
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
22
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.
Amount and Nature
Name and Address of Beneficial Ownership Percent
Title of Class of Beneficial Owner as of January 1,1997 of Class
- ------------------------- --------------------------- ----------------------- --------
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>
The following table sets forth certain information as of February 28, 1998,
regarding the beneficial ownership of the Common Units by all directors of the
General Partner, each of the named executive officers and all directors and
executive officers as a group.
Amount and Nature of Beneficial Ownership
---------------------------------------------
Sole Voting and Shared Voting and Percent
Title of Class Name Investment Power Investment Power of Class
- --------------------- ---------------- ---------------- ---------------- --------
Genesis Energy, L.P. Thomas W. Jasper - - -
Common Unit John P. vonBerg 1,000 - *
Mark J. Gorman 3,000 - *
Michael A. Peak 409 - *
Paul N. Howell 1,200 - *
Ronald E. Hall 3,000 - *
Donald H. Anderson 1,000 - *
Herbert I. Goodman 2,000 - *
J. Conley Stone - - -
John M. Fetzer 1,500 - *
Allyn R. Skelton, II - 3,000 *
Allen R. Stanley 800 6,400 *
All directors and
executive officers
as a group (15 in
number) 13,909 9,400 *
_____________________
* Less than 1%
The above table includes shares owned by certain members of the families of
the directors or executive officers, including shares in which pecuniary
interest may be disclaimed.
23
Item 13. Certain Relationships and Related Transactions
See Note 10 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 (subject to
earlier termination commencing December 31, 1999), 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."
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 24.
(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
24
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 Allyn R.
Skelton, II
**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
*10.18 Amended and Restated Restricted Unit Plan
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.
25
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 18th 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 18, 1998
- -------------------------------- and President
John P. vonBerg (Principal Executive Officer)
/s/ Allyn R. Skelton, II Chief Financial Officer March 18, 1998
- -------------------------------- (Principal Financial and
Allyn R. Skelton, II Accounting Officer)
/s/ Thomas W. Jasper * Chairman of the Board and March 18, 1998
- -------------------------------- Director
Thomas W. Jasper
/s/ Michael A. Peak * Director March 18, 1998
- --------------------------------
Michael A. Peak
/s/ Paul N. Howell * Director March 18, 1998
- --------------------------------
Paul N. Howell
/s/ Ronald E. Hall * Director March 18, 1998
- --------------------------------
Ronald E. Hall
/s/ Mark J. Gorman * Director, Chief Operating Officer March 18, 1998
- -------------------------------- and Executive Vice President
Mark J. Gorman
* By /s/ Allyn R. Skelton, II
- --------------------------------
Allyn R. Skelton, II
(Attorney-in-fact for persons indicated)
26
GENESIS ENERGY, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
Report of Independent Public Accountants 27
Consolidated Balance Sheets, December 31, 1997 and 1996 28
Consolidated Statement of Operations for the Year Ended December 31, 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,
Statement of Operations for the Eleven Months Ended November 30, 1996
(Predecessor) and
Statement of Operations for the Year Ended December 31, 1995 (Predecessor) 29
Consolidated Statement of Cash Flows for the Year Ended
December 31, 1997 and for the One Month Ended December 31, 1996,
Statement of Cash Flows for the Eleven Months Ended November 30, 1996
(Predecessor) and
Statement of Cash Flows for the Year Ended December 31, 1995 (Predecessor) 30
Consolidated Statements of Partners' Capital for the Year Ended
December 31, 1997 and for the One Month Ended December 31, 1996,
Statement of Divisional Equity for the Eleven Months Ended
November 30, 1996 (Predecessor), and
Statement of Divisional Equity for the Year Ended December 31, 1995
(Predecessor) 31
Notes to Consolidated Financial Statements 32
27
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, 1997 and 1996 and the
related consolidated statements of operations, cash flows and partners' capital
for the year ended December 31, 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 and the year
ended December 31, 1995. 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, 1997 and 1996, and the results of its operations and its cash flows
for the year ended December 31, 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 and the year ended December 31, 1995,
in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
February 19, 1998
28
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31, December 31,
1997 1996
-------- --------
Assets
Current Assets
Cash and cash equivalents $ 11,812 $ 11,878
Accounts receivable -
Trade 209,869 336,358
Related party - 52,449
Inventories 7,033 8,290
Other 3,488 1,396
-------- --------
Total current assets 232,202 410,371
Property and Equipment, at cost 105,102 100,097
Less: Accumulated depreciation (16,464) (11,160)
-------- --------
Net property and equipment 88,638 88,937
Other Assets, net of amortization 10,274 10,592
-------- --------
Total Assets $331,114 $509,900
======== ========
Liabilities and Partners' Capital
Current Liabilities
Accounts payable -
Trade $215,159 $387,322
Related party 2,832 3,430
Accrued liabilities 6,547 7,811
-------- --------
Total current liabilities 224,538 398,563
Commitments and Contingencies (Note 15)
Minority Interests 28,225 26,257
Partners' Capital
Common unitholders, 8,625 units
issued and outstanding 76,783 83,378
General partner 1,568 1,702
-------- --------
Total partners' capital 78,351 85,080
-------- --------
Total Liabilities and Partners' Capital $331,114 $509,900
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
29
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
One Month Eleven Months
Year Ended Year Ended Ended Ended Year Ended
December 31, December 31, December 31,November 30,December 31,
1997 1996 1996 1996 1995
---------- ---------- -------- ---------- ----------
(Pro forma) (Predecessor)
(Unaudited)
REVENUES:
Gathering and marketing revenues
Unrelated parties $2,911,333 $3,101,632 $318,110 $2,194,156 $1,916,231
Related parties 443,606 1,464,202 52,449 1,403,951 1,523,834
Pipeline revenues 17,989 16,780 1,426 - -
---------- ---------- -------- ---------- ----------
Total revenues 3,372,928 4,582,614 371,985 3,598,107 3,440,065
COST OF SALES:
Crude costs, unrelated parties 3,147,694 4,179,974 363,735 3,245,123 2,729,145
Crude costs, related parties 183,490 346,389 2,988 327,963 680,614
Field operating costs 12,107 15,092 1,290 6,744 7,152
Pipeline operating costs 6,016 4,978 463 - -
---------- ---------- -------- ---------- ----------
Total cost of sales 3,349,307 4,546,433 368,476 3,579,830 3,416,911
---------- ---------- -------- ---------- ----------
GROSS MARGIN 23,621 36,181 3,509 18,277 23,154
EXPENSES:
General and administrative 8,557 9,470 1,363 3,316 3,658
Depreciation and amortization 6,300 6,834 518 1,396 4,815
---------- ---------- -------- ---------- ----------
OPERATING INCOME 8,764 19,877 1,628 13,565 14,681
OTHER INCOME (EXPENSE):
Interest, net 1,063 56 56 294 173
Other, net 21 (74) - (83) (197)
---------- ---------- -------- ---------- ----------
Income before income taxes and minority interests 9,848 19,859 1,684 13,776 14,657
Income tax provision - - - 5,167 5,530
---------- ---------- -------- ---------- ----------
Net income before minority interests 9,848 19,859 1,684 8,609 9,127
Minority interests 1,968 3,970 337 - -
---------- ---------- -------- ---------- ----------
NET INCOME $ 7,880 $ 15,889 $ 1,347 $ 8,609 $ 9,127
========== ========== ======== ========== ==========
NET INCOME PER COMMON UNIT-BASIC AND DILUTED $ 0.90 $ 1.81 $ 0.15
========== ========== ========
NUMBER OF COMMON UNITS OUTSTANDING 8,625 8,625 8,625
========== ========== ========
The accompanying notes are an integral part of these consolidated financial
statements.
30
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
One Month Eleven Months
Year Ended Ended Ended Year Ended
December 31, December 31, November 30, December 31,
1997 1996 1996 1995
--------- --------- --------- --------
(Predecessor)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 7,880 $ 1,347 $ 8,609 $ 9,127
Adjustments to reconcile net income to
net cash provided by (used in) operating
activities -
Depreciation 5,820 479 1,396 2,178
Amortization of intangible assets 480 39 - 2,637
Deferred income taxes - - (12) (500)
(Gain) loss on disposal of assets (21) - 82 (33)
Minority interests equity in earnings 1,968 337 - -
Other noncash charges 66 200 - 124
Changes in components of working capital -
Accounts receivable 178,938 (384,681) (133,676) (98,158)
Inventories 1,257 (4,944) 2,763 3,249
Other current assets (2,092) (1,260) (17) -
Accounts payable (172,761) 381,418 118,948 98,916
Accrued liabilities (1,330) 6,218 157 83
Accrued income taxes - - (851) 3,858
--------- --------- --------- --------
Net cash provided by (used in) operating activities 20,205 (847) (2,601) 21,481
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (5,848) (106) (1,100) (17)
Increase in other assets (162) - (1,203) -
Purchase of operations of Howell - (74,021) - -
Proceeds from sales of assets 348 - 270 493
--------- --------- --------- --------
Net cash (used in) provided by investing activities (5,662) (74,127) (2,033) 476
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to common unitholders (14,317) - - -
Distributions to General Partner (292) - - -
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 (to) Basis - - 4,634 (21,957)
Other - 543 - -
--------- --------- --------- --------
Net cash (used in) provided by financing activities (14,609) 79,474 4,634 (21,957)
--------- --------- --------- --------
Net (decrease) increase in cash and cash equivalents (66) 4,500 - -
Cash and cash equivalents at beginning of period 11,878 7,378 - -
--------- --------- --------- --------
Cash and cash equivalents at end of period $ 11,812 $ 11,878 $ - $ -
========= ========= ========= ========
The accompanying notes are an integral part of these consolidated financial
statements.
31
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENT OF PARTNERS'
CAPITAL/DIVISIONAL EQUITY
(In thousands)
Partners' Capital
---------------------
Common General Divisional
Unitholders Partner Equity
----------- ------- ----------
(Predecessor)
Divisional equity at December 31, 1994 $ 4,393
Net income 9,127
Net advances to Basis (21,957)
--------
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
Net income for the one month ended December 31, 1996 1,320 27
------- ------
Partners' capital at December 31, 1996 83,378 1,702
Net income for the year ended December 31, 1997 7,722 158
Cash distributions for the year ended December 31, 1997 (14,317) (292)
------- ------
Partners' capital at December 31, 1997 $76,783 $1,568
======= ======
The accompanying notes are an integral part of these consolidated financial
statements.
32
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. ("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 4.
2. Basis of Presentation
The accompanying financial statements and related notes present the
consolidated financial position as of December 31, 1997 and 1996 for GELP and
its results of operations, cash flows and changes in partners' capital for the
year ended December 31, 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, and the year ended
December 31, 1995.
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 and the year
ended December 31, 1995 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 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
23
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 105,000 barrels per day at the wellhead
principally in the southern and southwestern states and offshore in the Gulf of
Mexico. The Partnership also owns and operates three crude oil pipelines
onshore as well as one offshore pipeline. The onshore pipelines are in Texas,
Mississippi/Louisiana and Florida/Alabama. The offshore pipeline is a 5.5-mile
pipeline in the Gulf of Mexico that transports oil from Main Pass Block 64 to a
connection with another party's pipeline.
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 a maturity of three
months or less to be cash equivalents. Funds deposited with Salomon, as
discussed in Note 10, 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. Due to the
nature of the Partnership's marketing activities, a minimum level of physical
inventories is required, as determined by management, to ensure efficient and
uninterrupted operation of the gathering business. These minimum inventories
are not marked-to-market as inventories held for sale but are carried at the
lower of cost or market, using the weighted-average cost method.
Store warehouse inventories, including parts and fuel, are carried at the
lower of cost or market.
Property and Equipment
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
5 to 10 years for buildings, office equipment, furniture and fixtures and other
equipment. Maintenance and repair costs are charged against current operations.
Expenditures which materially increase value, change capacities or extend useful
lives are capitalized.
Other Assets
Goodwill of the Partnership is amortized over a period of 20 years and is
recorded net of accumulated amortization.
34
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 market fluctuations on
inventories and contractual commitments. Gains and losses on forward contracts,
swaps, options and futures contracts used to hedge future contract purchases of
unpriced domestic crude oil, where firm commitments to sell are required prior
to establishment of the purchase price, are deferred until the margin from the
underlying risk element of the hedged item is recognized in accordance with
Statement of Financial Accounting Standards (SFAS) No. 80, "Accounting for
Futures Contracts." Deferred gains and losses from hedging instruments are
included in the Consolidated Balance Sheets in accrued liabilities or accounts
receivable, respectively. Recognized gains and losses from hedging activities
are included in cost of crude in the Consolidated Statements of Operations.
Unrecognized income of $1,397,000 and $355,000 was deferred on these contracts
at December 31, 1997 and 1996, 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 differentials between its various
trading hubs and Cushing, Oklahoma, to further manage its basis exposure.
Should a hedging contract cease to serve as a hedge of inventories or
contractual commitments, the hedging instrument is accounted for under the
marked-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 cost of crude 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.
Significant Customers
A significant portion of the Partnership's revenues 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.
35
Net Income Per Common Unit
In February 1997, the Financial Accounting Standards Board issued SFAS No.
128, "Earnings Per Share", which established new accounting and reporting
standards for earnings per share. The statement was effective for the
Partnership for the year ended December 31, 1997 and resulted in the retroactive
restatement of previously reported net income per unit. However, the adoption
of this new standard had no effect on the Partnership's previously reported net
income per unit.
Basic net income per Common Unit is calculated on the number of outstanding
Common Units of 8,625,000. 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.
Adoption of Accounting Standards
In October 1996, the American Institute of Certified Public Accountants
issued Statement of Position No. 96-1, "Environmental Remediation Liabilities,"
which establishes new accounting and reporting for the recognition and
disclosure of environmental remediation liabilities. The provisions of the
statement were effective for the Partnership in 1997 and did not have a
significant effect on the Partnership's consolidated financial position or
results of operations.
In June 1997, the Financial Accounting Standards Board issued SFAS No. 130,
"Reporting Comprehensive Income", and SFAS No. 131, "Disclosures About Segments
of an Enterprise and Related Information". SFAS No. 130 establishes standards
for reporting and displaying comprehensive income and its components. SFAS No.
131 establishes standards for the way that public business enterprises report
information about operating segments and related information in interim and
annual financial statements. SFAS No. 130 and 131 are effective for periods
beginning after December 15, 1997. These two statements will not have any
effect on the Partnership's 1997 financial position or results of operations.
Management is evaluating what, if any, additional disclosures may be required
when these two statements are implemented.
4. 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 purchase price consisted of cash and Subordinated OLP Units in GCOLP.
The total purchase price was determined as follows (in thousands).
Cash $74,021
Subordinated OLP Units in GCOLP 21,174
Howell's share of cash proceeds from the public
offering of units that was retained in GCOLP 2,300
-------
Total purchase price of Howell $97,495
=======
The purchase price was allocated to the assets acquired from Howell based on
their relative fair values. The allocation was as follows (in thousands).
Property and inventory $88,094
Goodwill 9,401
-------
Total allocated $97,495
=======
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
36
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 had taken place
on the basis assumed above, nor are they necessarily indicative of the results
of future combined operations.
5. Inventories
Inventories consisted of the following (in thousands).
December 31,
------------------
1997 1996
------- ------
Crude inventories, at market $2,304 $3,548
Minimum crude inventories, at lower of cost or market 4,435 4,435
Store warehouse inventories, at lower of cost or market 294 307
------ ------
Total inventories $7,033 $8,290
====== ======
As of December 31, 1997 and 1996, the number of barrels included in minimum
crude inventories was 285,000, with approximate market values of $4,946,000 and
$7,259,000, respectively.
6. Property and Equipment
Property and equipment consisted of the following (in thousands).
December 31,
------------------
1997 1996
-------- -------
Land and buildings $ 3,569 $ 3,553
Pipelines and related assets 83,611 80,567
Vehicles and transportation equipment 8,211 8,065
Office equipment, furniture and fixtures 5,109 3,375
Other equipment 4,602 4,537
-------- --------
105,102 100,097
Less - Accumulated depreciation (16,464) (11,160)
-------- --------
Net property and equipment $ 88,638 $ 88,937
======== ========
Depreciation expense was $5,820,000 for the year ended December 31, 1997,
$479,000 for the one month ended December 31, 1996, $1,396,000 for the eleven
months ended November 30, 1996 and $2,178,000 for the year ended December 31,
1995.
7. Other Assets
Other assets consisted of the following (in thousands).
December 31,
------------------
1997 1996
-------- -------
Goodwill $ 9,401 $ 9,401
NYMEX seats 1,203 1,203
Other 189 27
------- -------
10,793 10,631
Less - Accumulated amortization (519) (39)
------- -------
Unamortized other assets $10,274 $10,592
======= =======
Amortization expense was $480,000 for the year ended December 31, 1997,
$39,000 for the one month ended December 31, 1996 and $2,637,000 for the year
ended December 31, 1995. There was no amortization expense for the eleven
months ended November 30, 1996.
8. Credit Resources and Liquidity
Pursuant to a Master Credit Support Agreement, GCOLP has established credit
facilities with Salomon (collectively, the "Credit Facilities"). GCOLP's
obligations under the Credit Facilities are secured by its receivables,
inventories, general intangibles and cash.
37
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 $400 million for the
year ending December 31, 1998 and $300 million for the year ending December 31,
1999 (to be reduced in each case by the amount utilized at any one time pursuant
to the Working Capital Facility, as described below, and 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 under the Master Credit Support Agreement as
described below). 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 from a below-market rate to a rate
that may be higher than rates paid to independent financial institutions for
similar credit. At December 31, 1997, the aggregate amount of obligations
covered by guarantees was $259 million, including $124 million in payable
obligations and $135 million of estimated crude oil purchase obligations for
January 1998.
Working Capital Facility
Salomon has agreed to provide GCOLP, through March 31, 1998, with a Working
Capital Facility of up to $50 million, which amount includes 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. The
total amounts outstanding at any one time under the Working Capital Facility
will correspondingly reduce the amounts available under the Guaranty Facility.
The interest rate for the Working Capital Facility is equal to the federal funds
rate plus 5/8%. The Partnership had no letters of credit outstanding at
December 31, 1997. No direct cash advances were outstanding at December 31,
1997. The Partnership expects to arrange for a working capital facility through
one or more third party lenders or an extension of the Working Capital Facility
with Salomon prior to the expiration of the Working Capital Facility.
Summary of Credit Facilities Terms
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. Salomon does not currently foresee any circumstances
under which it would provide guarantees or other credit support after the three-
year credit support period ending December 31, 1999. In addition, Salomon's
obligations under the Master Credit Support Agreement may be transferred or
terminated early subject to certain conditions. Prior to December 1999,
management of the Partnership intends to replace the Guaranty Facility with a
letter of credit facility with one or more third party lenders.
38
There can be no assurance of the availability or the terms of credit for
the Partnership. The General Partner believes that the Credit Facilities will
be sufficient to support the Partnership's crude oil purchasing activities and
working capital requirements. No assurance, however, can be given that the
General Partner will not 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.
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 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. 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 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.
9. Partnership Equity
Partnership equity in GELP consists of the general partner interest of 2% and
8.6 million Common Units representing limited partner interests of 98%. The
Common Units were sold to the public in an initial public offering in December
1996. The general partner interest is held by the General Partner.
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. In addition, one-
fourth of the Subordinated OLP Units may convert into Common OLP Units prior to
the end of the subordination period 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.
39
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.
10. Transactions with Related Parties
Sales, purchases and other transactions with affiliated companies, 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).
One Month Eleven
Year Ended Ended Months Ended Year Ended
December 31, December 31, November 30, December 31,
1997 1996 1996 1995
------------- ------------ ------------ ------------
(Predecessor)
Sales to affiliates $443,606 $52,449 $1,403,951 $1,523,834
Purchases from affiliates $183,490 $2,988 $327,963 $680,614
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.
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 and $376,000
in 1995.
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 $14,973,000 for the year ended December 31, 1997 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 and
approximately $1,200,000 for the year ended December 31, 1995.
40
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, 1997, the Partnership had $14.0 million in funds deposited with
Salomon under the Treasury Management Agreement. At December 31, 1996, the
Partnership had $6,053,000 in funds deposited with Basis under the Treasury
Management Agreement. Such amounts have been classified in the consolidated
balance sheets as cash and cash equivalents. For the year ended December 31,
1997, the Partnership earned interest of $833,000 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 year ended December 31, 1997 and the one month ended
December 31, 1996, the Partnership paid Salomon $730,000 and $102,000 for
guarantee fees under the Credit Facilities. The Partnership paid Basis $85,000
for interest under the Credit Facilities during 1997.
11. Supplemental Cash Flow Information
Cash received by the Partnership for interest for the year ended December 31,
1997 was $1,139,000. Payments of interest were $122,000 for the year ended
December 31, 1997.
Cash received by the Predecessor for imputed interest was $299,000 for the
eleven months ended November 30, 1996. Payments of imputed interest by the
Predecessor were $169,000 for the year ended December 31, 1995.
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 and $1,959,000 during the year ended
December 31, 1995 related to 1994.
12. 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 has its own
plans.
The plans described below represent the plans of the General Partner for
1998. Except where noted, these plans were in effect in 1997 and for the
Predecessor in 1996.
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 $474,000 for the year ended December 31, 1997. The Predecessor's
costs relating to this plan were $267,000 for the eleven months ended November
30, 1996 and $292,000 in 1995.
The General Partner also provided certain health care and survivor benefits
for its active and retired employees. In 1998, these plans will be fully-
insured. In 1997 and 1996, these benefit programs were self-insured. Both
active and retired employees contributed to such programs with retired employees
assuming a larger portion of the cost attributable to their benefits. The
expenses of the General Partner for these benefits were $1,731,000 and $200,000
in 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 and $391,000 in 1995.
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").
41
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 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 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 235,000 Common Units (the "Restricted
Units") have been allocated to approximately 30 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 December 31, 1998. The remaining rights to receive 56,000
Common Units initially available under the Restricted Unit Plan may be allocated
or issued in the future to key employees on such terms and conditions (including
vesting conditions) as the Compensation Committee of the General Partner
("Compensation Committee") shall determine.
Upon "vesting" in accordance with the terms and conditions of the
Restricted Unit Plan, Common Units allocated to a plan participant will be
issued to such participant. Units issued to participants may be newly issued
Units acquired by the General Partner from the Partnership at then prevailing
market prices or may be acquired by the General Partner in the open market. In
either case, the associated expense will be borne by the Partnership. Until
Common Units have vested and have been issued to a participant, such participant
shall not be entitled to any distributions or allocations of income or loss and
shall not have any voting or other rights in respect of such Common Units. The
participant shall receive cash awards based on the number of non-vested units
held by such participant to the extent that distributions are paid on
Subordinated OLP Units. To date, no distributions have been paid with respect
to Subordinated OLP Units. No consideration will be payable by the plan
participants upon vesting and issuance of the Common Units. The plan
participant cannot sell the Common Units until one year after the date of
vesting.
Termination without cause in violation of a written employment agreement,
or a Significant Event as defined in the Restricted Unit Plan, will result in
immediate vesting of all non-vested units and conversion to Common Units without
any restrictions.
Incentive Plan
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.
42
13. Income Taxes
The components of the provision for income taxes for the Predecessor are as
follows (in thousands).
November 30, December 31,
1996 1995
------------ ------------
Current -
Federal $4,656 $5,416
State 523 614
Total current 5,179 6,030
Deferred -
Federal (12) (500)
Total deferred (12) (500)
------ ------
Total provision $5,167 $5,530
====== ======
The components of deferred tax assets and liabilities of the Predecessor are
as follows (in thousands).
December 31,
1995
----
Current deferred tax assets -
Inventories $249
Accrued liabilities 207
----
Net current deferred tax assets 456
Noncurrent deferred tax liabilities -
Property and equipment (14)
----
Net deferred tax assets $442
====
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, December 31,
1996 1995
------------ ------------
Provision for income taxes
at the statutory rate $4,822 $5,130
State taxes, net of federal
tax benefit 340 399
Other 5 1
------ ------
Provision for income taxes $5,167 $5,530
====== ======
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.
14. Derivatives
Market Risk
Market risk represents the potential loss that can be caused by a change in
the market value of an asset or a commitment. In order to hedge its exposure to
market fluctuations, the Partnership enters into various contracts with off-
balance-sheet risk, including option contracts and swap agreements. The
Partnership does not consider its commodity futures and forward contracts to be
financial instruments since these contracts either require or permit settlement
by the delivery of the underlying commodities. 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 cost of sales.
Credit Risk
Credit risk represents the accounting loss that the Partnership would
record if counterparties failed to perform pursuant to contractual terms.
Management of credit risk involves a number of considerations, such as the
financial profile of the counterparty, the value of collateral held, if any,
specific terms and duration of the contractual agreement, and the counterparty's
sensitivity to political and macroeconomic developments.
43
The Partnership's exposure to credit risk is limited to the book value of
trade receivables included in the accompanying financial statements. The
Partnership has established various procedures to manage 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.
Fair Value and Net Gains and Losses
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, 1997, 1996 and 1995 are as follows (in thousands).
1997 1996 1995
------------------------- ------------------------ ------------------------
Net Net Net
Carrying Fair Gains Carrying Fair Gains Carrying Fair Gains
Amount Value (Losses) Amount Value (Losses) Amount Value (Losses)
-------- ----- -------- -------- ----- -------- -------- ----- --------
Option contracts written $1,356 $803 $553 $ - $ - $ - $537 $324 $213
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.
15. Commitments and Contingencies
The Partnership uses surface, vehicle and office leases in the course of its
business operations. The Partnership also leases three tanks for use in its
pipeline operations. The future minimum rental payments under all noncancelable
operating leases as of December 31, 1997, were as follows (in thousands).
1998 $956
1999 884
2000 419
2001 402
2002 402
Thereafter 1,276
------
Total minimum lease obligations $4,339
======
Total operating lease expense was as follows (in thousands).
Year ended December 31, 1997 $1,060
One month ended December 31, 1996 $ 133
Eleven months ended November 30, 1996 $ 522
Year ended December 31, 1995 $ 538
The Partnership has contractual commitments (primarily forward contracts)
arising in the ordinary course of business. At December 31, 1997, the
Partnership had commitments to purchase 17,090,000 barrels of crude oil at fixed
prices ranging from $16.50 to $22.15 per barrel extending to January 1999, and
commitments to sell 16,882,000 barrels of crude oil at fixed prices ranging from
$16.50 to $22.29 per barrel extending to January 1999. Additionally, the
Partnership had commitments to purchase 27,722,000 barrels of crude oil
extending to December 1998, and commitments to sell 15,399,000 barrels of crude
oil extending to June 1998, 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.
44
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.