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, 2002
OR
- -------TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission file number 1-12295
GENESIS ENERGY, L.P.
(Exact name of registrant as specified in its charter)
Delaware 76-0513049
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
500 Dallas, Suite 2500, Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 860-2500
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
------------------- ---------------------
Common Units American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes |X| No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
|X|
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Securities Exchange Act of 1934).
-------
Aggregate market value of the Common Units held by non-affiliates of the
Registrant, based on closing prices in the daily composite list for transactions
on the American Stock Exchange on June 28, 2002, was approximately $32,861,250.
At March 3, 2003, 8,625,000 Common Units were outstanding.
2
GENESIS ENERGY, L.P.
2002 FORM 10-K ANNUAL REPORT
Table of Contents
Page
Part I
Item 1. Business....................................................... 3
Item 2. Properties..................................................... 10
Item 3. Legal Proceedings.............................................. 11
Item 4. Submission of Matters to a Vote of Security Holders............ 11
Part II
Item 5. Market for Registrant's Common Units and Related Security
Holder Matters................................................. 11
Item 6. Selected Financial Data........................................ 12
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations...................................... 13
Item 7a. Quantitative and Qualitative Disclosures about Market Risk..... 32
Item 8. Financial Statements and Supplementary Data.................... 32
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure....................................... 32
Part III
Item 10. Directors and Executive Officers of the Registrant............. 33
Item 11. Executive Compensation......................................... 34
Item 12. Security Ownership of Certain Beneficial Owners and Management. 36
Item 13. Certain Relationships and Related Transactions................. 37
Item 14. Controls and Procedures........................................ 37
Part IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K 38
CERTIFICATIONS ........................................................... 41
3
PART I
Item 1. Business
General
Genesis Energy, L.P., a Delaware limited partnership, was formed in
December 1996. We conduct our operations through our affiliated limited
partnership, Genesis Crude Oil, L.P. and its subsidiary partnerships
(collectively, the "Partnership" or "Genesis"). We are an independent gatherer
and marketer of crude oil. Our operations are concentrated in Texas, Louisiana,
Alabama, Florida, Mississippi and New Mexico. In our gathering and marketing
business, we are principally engaged in the purchase and aggregation of crude
oil at the wellhead for resale at various points along the crude oil
distribution chain, which extends from the wellhead to aggregation at terminal
facilities, refineries and other end markets (the "Distribution Chain"). Our
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 customers at favorable prices.
We utilize our trucking fleet of 74 leased tractor-trailers and our gathering
lines to transport crude oil. We also transport purchased crude oil on trucks,
barges and pipelines owned and operated by third parties. In the fourth quarter
of 2002, we purchased an average of approximately 63,000 barrels per day of
crude oil at the wellhead.
We also make bulk purchases of crude oil at pipeline and terminal
facilities. When opportunities arise to increase margin or to acquire a grade of
crude oil that more nearly matches the specifications for crude oil we are
obligated to deliver, we may exchange crude oil with third parties through
exchange or buy/sell agreements. These purchases were significantly reduced in
2002 compared to prior years. In the fourth quarter of 2002, our bulk and
exchange transactions averaged 20,000 barrels per day, down from 260,000 barrels
per day in the fourth quarter of 2001. The reduction is attributable primarily
to credit requirements for these transactions as discussed below.
In addition to our gathering and marketing business, our operations
include transportation of crude oil at regulated published tariffs on our three
common carrier pipeline systems. We transported a total of approximately 77,000
barrels per day on our three common carrier crude oil pipeline systems and
related gathering lines during the fourth quarter of 2002. These systems are the
Texas System, the Jay System extending between Florida and Alabama, and the
Mississippi System extending between Mississippi and Louisiana. These pipeline
systems have numerous points where the crude oil owned by the shipper can be
injected into the pipeline for delivery to or transfer to connecting pipelines.
Genesis earns a tariff for the transportation services, with the tariff rate per
barrel of crude oil varying with the distance from injection point to delivery
point.
Genesis Energy, Inc. (the "General Partner"), a Delaware
corporation, serves as the sole general partner of Genesis Energy, L.P.,
Genesis Crude Oil,L.P. (GCOLP) and GCOLP's subsidiary partnerships, Genesis
Pipeline Texas, L.P.and Genesis Pipeline USA, L.P. The General Partner is owned
by Denbury Gathering & Marketing, Inc., a subsidiary of Denbury Resources Inc.
Denbury acquired the General Partner from Salomon Smith Barney Holdings Inc.
and Salomon Brothers Holding Company Inc. in May 2002.
Business Overview
In our gathering and marketing business, we seek to purchase and sell
crude oil at points along the Distribution Chain where gross margins can be
achieved. We generally purchase crude oil at prevailing prices from producers at
the wellhead under short-term contracts and then transport the crude oil along
the Distribution Chain for sale to or exchange with customers. Our margins from
our 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
and the cost of supplying credit in the form of letters of credit or guaranties.
We generally enter 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, we may exchange one grade of
crude oil for another to maximize margins or meet contract delivery
requirements.
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. Generally, as we purchase crude oil, we simultaneously
establish a margin by selling crude oil for physical delivery to third party
users, such as independent refiners or major oil companies. Through these
transactions, we seek to maintain a position that is substantially balanced
between crude oil purchases, on the one
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hand, and sales or future delivery obligations, on the other hand. It is our
policy not to acquire and hold crude oil, futures contracts or other
derivative products for the purpose of speculating on crude oil price changes.
Oil prices rose in the latter half of 2002 such that the NYMEX price
for WTI was $31.20 at December 31, 2002. International factors such as the
strike by oil workers in Venezuela and the potential for war with Iraq as well
as domestic influences such as the supply of crude oil in the United States have
contributed to the price increase. An increase in the market price of crude oil
does not impact us to the extent many people expect. When market prices for oil
increase, we must pay more for crude oil, but we normally are able to sell it
for more. To the extent we have crude oil inventories, we can be impacted by
market-price changes.
Most of our contracts for the purchase and sale of crude oil have
components in the pricing provisions such that the price paid or received is
adjusted for changes in the market price for crude oil. Typically the pricing in
a contract to purchase crude oil will consist of the market price component and
a bonus, which is generally a fixed amount ranging from a few cents to several
dollars. Typically the pricing in a contract to sell crude oil will consist of
the market price component and a bonus that is not fixed, but instead is based
on another market factor. This floating bonus is usually the price quoted by
Platt's for WTI "P-Plus". Because the bonus for purchases of crude oil is fixed
and P-Plus floats in the sales contracts, the margin on an individual
transaction can vary from month-to-month depending on changes in the P-Plus
component.
P-Plus does not necessarily move in correlation with the price of oil
in the market. P-Plus is affected by numerous factors such as future
expectations for changes in crude oil prices, such that crude oil prices can be
rising, but P-Plus can be decreasing.
Some purchase contracts and sale contracts also include a component for
grade differentials. The grade refers to the type of crude oil. Crude oils from
different wells and areas can have different chemical compositions. These
different grades of crude oil will appeal to different customers depending on
the processing capabilities of the refineries who ultimately receive the oil.
When we set a fixed bonus, we take into consideration the typical grade
differences in the market.. If we then sell the oil under a contract with a
floating grade differential in the formula, and that grade differential
fluctuates, we can then experience an increase or decrease in our gross margin
from that oil purchase and sale. This volatility in grade differentials adds
volatility to our gross margins.
The purchase and sales contracts are primarily "Evergreen" contracts
which means they continue from month to month unless one of the parties to the
contract gives 30-days notice of cancellation. In order to change the pricing in
a fixed bonus contract, we would have to give 30-days notice that we want to
cancel and renegotiate the contract. This notice time requirement, therefore,
means that at least a month will pass before the fixed bonus can be reduced to
correspond with a decrease in the P-Plus component of the related sales
contract. In this case our margin would be reduced until such a change is made.
Because of the volatility of P-Plus and grade differentials, it is not practical
to renegotiate every purchase contract for every change in P-Plus or a grade
differential. So margins from the sale of the crude oil can be volatile as a
result of these timing differences.
Through the pipeline systems we own and operate, our pipeline
subsidiaries transport crude oil for our gathering and marketing subsidiary and
other shippers pursuant to tariff rates regulated by the Federal Energy
Regulatory Commission ("FERC") or the Texas Railroad Commission. Accordingly, we
offer 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 are a function of the
level of throughput and the distance from the point where the crude oil was
injected into the pipeline and the delivery point. We also can earn revenue from
pipeline loss allowance volumes. In exchange for bearing the risk of pipeline
volumetric losses from whatever source, we deduct volumetric pipeline loss
allowances and crude quality deductions. Such allowances and deductions are
offset by measurement gains and losses. When the allowances exceed measurement
losses, the net pipeline loss allowance volumes are earned and recognized as
income and inventory available to sell valued at the market price for the crude
oil. Until the volumes are sold, they are held as inventory at the lower of cost
or market value. When the volumes are sold, any difference between the carrying
amount and the sale price is recognized as additional revenue.
The margins from the Partnership's pipeline operations are generated by
the difference between the regulated published tariff, pipeline loss allowance
revenues and the fixed and variable costs of operating and maintaining the
pipeline.
5
Producer Services
Crude oil purchasers who buy from producers compete on the basis of
competitive prices and quality of services. Through our team of crude oil
purchasing representatives, we maintain relationships with more than 600
producers. We believe that our ability to offer high-quality field and
administrative services to producers is a key factor in our ability to maintain
volumes of purchased crude oil and to obtain new volumes. High-quality field
services include efficient gathering capabilities, availability of trucks,
willingness to construct gathering pipelines where economically justified,
timely pickup of crude oil from tank batteries at the lease or production point,
accurate measurement of crude oil volumes received, avoidance of spills and
effective management of pipeline deliveries. Accounting and other administrative
services include securing division orders (statements from interest owners
affirming the division of ownership in crude oil purchased by the Partnership),
providing statements of the crude oil purchased each month, disbursing
production proceeds to interest owners and calculation and payment of production
taxes on behalf of interest owners. In order to compete effectively, we must
maintain records of title and division order interests in an accurate and timely
manner to make 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 2002, we distributed payments to
approximately 15,000 interest owners.
Credit
Our credit standing is a major consideration for parties with whom we
do business. At times, in connection with our crude oil purchases or exchanges,
we are 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.
When we market crude oil, we must determine the amount, if any, of the
line of credit to be extended to any given customer. Since typical sales
transactions can involve tens of thousands of barrels of crude oil, the risk of
nonpayment and nonperformance by customers is a major consideration in our
business. We believe that our sales are made to creditworthy entities or
entities with adequate credit support. We have not experienced any nonpayment or
nonperformance by our customers during 2001 or 2002.
Over the last year there have been an unusual number of business
failures and very large restatements by small as well as large companies in the
energy industry. Because the energy industry is very credit intensive, these
failures and restatements have focused attention on the credit risks of
companies in the energy industry by credit rating agencies, producers and
counterparties.
This focus on credit has affected requests for credit from producers.
While we have seen some increase in requests for credit support from producers,
we have been relatively successful in obtaining open credit from most producers.
When credit support has been required, we have generally been successful in
adjusting the price we pay to purchase the crude oil to reflect the cost to us
of providing letters of credit.
Credit review and analysis are also integral to our leasehold
purchases. Payment for all or substantially all of the monthly leasehold
production is sometimes made to the operator of the lease, who is responsible
for the correct payment and distribution of such production proceeds to the
proper parties. In these situations, we must determine whether the operator has
sufficient financial resources to make such payments and distributions and to
indemnify and defend us in the event any third party should bring a protest,
action or complaint in connection with the distribution of production proceeds
by the operator.
Competition
In the various business activities described above, we are in
competition with a number of major oil companies and smaller entities. There is
intense competition for leasehold purchases of crude oil. The number and
location of our pipeline systems and trucking facilities give us access to
domestic crude oil production throughout our area of operations. We purchase
leasehold barrels from more than 600 producers. In the fourth quarter of 2002,
approximately 38 percent of the leasehold barrels were purchased from ten
producers, with Denbury representing eight percent of total leasehold-barrel
purchases.
We have considerable flexibility in marketing the volumes of crude oil
that we purchase, without dependence on any single customer or transportation or
storage facility. Our largest competitors in the purchase of leasehold crude oil
production are Plains All American Pipeline, L.P., EOTT Energy Partners, L.P.,
Shell Trading Company, GulfMark Energy, Inc. and TEPPCO Partners, L.P.
Additionally, we compete with many regional or
6
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, availability of
trade credit and capabilities of risk management systems.
Our most significant competitors in our pipeline operations are
primarily common carrier and proprietary pipelines owned and operated by major
oil companies, large independent pipeline companies and other companies in the
areas where the Mississippi and Texas Systems deliver crude oil. The Jay System
operates in an area not currently served by pipeline competitors. Competition
among common carrier pipelines is based primarily on posted tariffs, quality of
customer service and proximity to refineries and connecting pipelines. We
believe 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 our pipelines will be built in the same
geographic areas in the near future, provided that our pipelines continue to
have available capacity to satisfy demands of shippers and that our tariffs
remain at competitive levels.
Employees
To carry out various purchasing, gathering, transporting and marketing
activities, the General Partner employed, at February 14, 2003, approximately
230 employees, including management, truck drivers and other operating
personnel, division order analysts, accountants, tax specialists, contract
administrators, schedulers, marketing and credit specialists and employees
involved in our pipeline operations. None of the employees are represented by
labor unions, and we believe that relationships with our employees are good.
Regulation
Sarbanes-Oxley Act of 2002
In July 2002, the Sarbanes-Oxley Act of 2002 was signed into law to
protect investors by improving the accuracy and reliability of corporate
disclosures made pursuant to securities laws. The Securities and Exchange
Commission is required to issue rules to adopt and implement the provision of
Sarbanes-Oxley. The SEC has issued some final rules. Rules that are effective
now that affect us are requirements for certifications by our Chief Executive
Officer and Chief Financial Officer in our quarterly and annual filings with the
SEC; disclosures regarding controls and procedures, disclosures regarding
critical accounting estimates and policies and requirements to make filings with
the SEC available on our website. Additional rules that will become effective
during 2003 include disclosures regarding audit committee financial experts and
charters, disclosure of our Code of Ethics for the CEO and senior financial
officers, disclosures regarding contractual obligations and off-balance sheet
arrangements and transactions, and requirements for filing earnings press
releases with the SEC. Additionally, we will be required to include in our Form
10-K for 2003 a certification on internal accounting controls and a report from
our auditors regarding that certification.
Pipeline Tariff Regulation
The interstate common carrier pipeline operations of the Jay and
Mississippi systems are subject to rate regulation by FERC under the Interstate
Commerce Act ("ICA"). FERC regulations require that oil pipeline rates be posted
publicly and that the rates be "just and reasonable" and not unduly
discriminatory.
Effective January 1, 1995, FERC promulgated rules simplifying and
streamlining the ratemaking process. Previously established rates were
"grandfathered", limiting the challenges that could be made to existing tariff
rates. Rates of interstate oil pipelines are currently regulated by the FERC
primarily through an index methodology, whereby a pipeline is allowed to change
its rates based on the change in year to year in an index. Under the
regulations, we are able to change our rates within prescribed ceiling levels
that are tied to the Producer Price Index for Finished Goods. 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.
Alternatively, FERC allows for rate changes under three other
methods--a cost-of-service methodology, competitive market showings
("Market-Based Rates"), or agreements between shippers and the oil pipeline
company that the rate is acceptable ("Settlement Rates"). The pipeline tariff
rates on our Mississippi and Jay Systems are either rates that were
grandfathered and have been changed under the index methodology or Settlement
Rates. None of our tariffs have been subjected to a protest or complaint by any
shipper or other interested party.
7
Our intrastate common carrier pipeline operations 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, 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 ours and has not investigated the rates or
practices of such carriers in the absence of shipper complaints, which have been
few and almost invariably have been settled informally. In 2002 we increased the
tariffs on our Texas System due to higher costs to operate and maintain the
pipeline. Although no assurance can be given that the tariffs we charge would
ultimately be upheld if challenged, we believe that the tariffs now in effect
can be sustained.
Environmental Regulations
We are subject to federal and state laws and regulations relating to
the protection of the environment. At the federal level such laws include the
Clean Air Act; the Clean Water Act; the Resource Conservation and Recovery Act;
the Comprehensive Environmental Response, Compensation, and Liability Act; and
the National Environmental Policy Act. Failure to comply with these laws and
regulations may result in the assessment of administrative, civil and criminal
penalties or in the imposition of injunctive relief. Although compliance with
such laws has not had a significant effect on our business, such compliance in
the future could prove to be costly, and there can be no assurance that we will
not incur such costs in material amounts.
The Clean Air Act regulates, among other things, the emission of
volatile organic compounds in order to minimize the creation of ozone. Such
emissions may occur from the handling or storage of crude oil. The required
levels of emission control are established in state air quality control
implementation plans. Both federal and state laws impose substantial penalties
for violation of these applicable requirements. We believe that we are in
substantial compliance with applicable clean air requirements.
The Clean Water Act controls 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 and certain onshore facilities near or crossing
waterways 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. We believe that we are in substantial compliance
with the Clean Water Act and OPA.
We have developed an Integrated Contingency Plan (ICP) to satisfy
components of the OPA, as amended in the Clean Water Act. The ICP also satisfies
regulations of the federal Department of Transportation, the federal
Occupational Safety and Health Act ("OSHA") and state regulations. This plan
meets regulatory requirements as to notification, procedures, response actions,
response teams, response resources and spill impact considerations in the event
of an oil spill.
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 may invoke the requirements of the federal statute, or state
counterparts, which impose substantial penalties for violation of applicable
standards.
The Comprehensive Environmental Response, Compensation, and Liability
Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons that are considered to have contributed to the release of a "hazardous
substance" into the environment. Such persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. Persons who are or were responsible for releases of hazardous substances
under CERCLA may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources, and it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances released
into the environment. In the ordinary course of our operations, substances may
be generated or handled which fall within the definition of
8
"hazardous substances." Although we have applied operating and disposal
practices that werestandard in the industry at the time, hydrocarbons or other
waste may have been disposed of or released on or under the property owned or
leased by us or under locations where such wastes have been taken for disposal.
Further, we may own or operate properties that in the past were operated by
third parties whose operations were not under our control. Those properties and
any wastes that may have been disposed of or released on them may be subject to
CERCLA, RCRA and analogous state laws, and we potentially could be required to
remediate such properties.
Under the National Environmental Policy Act ("NEPA"), a federal agency,
in conjunction with a permit holder, 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.
We are subject to similar state and local environmental laws and
regulations that may also address additional environmental considerations of
particular concern to a state.
On December 20, 1999, we had a spill of crude oil from our Mississippi
System. Approximately 8,000 barrels of oil spilled from the pipeline near
Summerland, Mississippi, and entered a creek and river nearby. The spill was
cleaned up, with ongoing monitoring and reduced clean-up activity expected to
continue for an undetermined period of time. The oil spill is covered by
insurance and the financial impact to us for the cost of the clean-up has not
been material.
During 2002, we reached agreement in principal with the US
Environmental Protection Agency (EPA) and the Mississippi Department of
Environmental Quality (MDEQ) for the payment of fines under federal and state
environmental laws with respect to this 1999 spill. Based on the discussions
leading to this agreement in principal, we have recorded accrued liabilities
totaling of $3.0 million during 2001 and 2002. While we are pleased with the
progress we have made toward resolving the uncertainty of this environmental
liability during 2002, no assurance can be made that we will reach final
agreement with the federal and Mississippi governments or the specific terms of
a final agreement if one is reached.
Safety Regulations
Our 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. 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.
On March 31, 2001, the Department of Transportation promulgated
Integrity Management Plan (IMP) regulations. The IMP regulations require that we
perform baseline assessments of all pipelines that could affect a High
Consequence Area. The integrity of these pipelines must be assessed by internal
inspection, pressure test, or equivalent alternative new technology. A High
Consequence Area (HCA) is defined as (a) a commercially navigable waterway; (b)
an urbanized area that contains 50,000 or more people and has a density of at
least 1,000 people per square mile; (c) other populated areas that contain a
concentrated population, such as an incorporated or unincorporated city, town or
village; and (d) an area of the environment that has been designated as
unusually sensitive to oil spills. Due to the proximity of all of our pipelines
to water crossings and populated areas, we have designated all of our pipelines
as affecting HCAs.
The IMP regulation required us to prepare an Integrity Management Plan
that details the risk assessment factors, the overall risk rating for each
segment of pipe, a schedule for completing the integrity assessment, the methods
to assess pipeline integrity, and an explanation of the assessment methods
selected. The risk factors to be
9
considered include proximity to population areas, waterways and sensitive
areas, known pipe and coating conditions, leak history, pipe material and
manufacturer, cathodic protection adequacy, operating pressure levels and
external damage potential. The IMP regulations require that the baseline
assessment be completed within seven years of March 31, 2002, with 50% of the
mileage assessed in the first three and one-half years. Reassessment is then
required every five years. As testing is complete, we are required to take
prompt remedial action to address all integrity issues raised by the assessment.
No assurance can be given that the cost of testing and the required
rehabilitation identified will not be material costs to Genesis that may not be
fully recoverable by tariff increases.
In addition to the IMP, we have developed a Risk Management Plan as
part of the IMP. This plan is intended to minimize the offsite consequences of
catastrophic spills. As part of this program, we have developed a mapping
program. This mapping program will identify HCAs and unusually sensitive areas
(USAs) along the pipeline right-of-ways in addition to mapping of shorelines to
characterize the potential on waterways of a spill of crude oil.
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. We do
not anticipate any significant problems in complying with applicable state laws
and regulations in those states in which we operate.
Our crude oil pipelines are also subject to the requirements of the
Office of Pipeline Safety of the federal Department of Transportation
regulations requiring qualification of all pipeline personnel. The Operator
Qualification (OQ) program required operators to develop and submit a written
program by April, 2001. The regulations also require all pipeline operators to
develop a training program for pipeline personnel and qualify them on individual
covered tasks at the operator's pipeline facilities by October 2002. The intent
of the OQ regulations is to ensure a qualified workforce by pipeline operators
and contractors when performing covered tasks on the pipeline and its
facilities, thereby reducing the probability and consequences of incidents
caused by human error.
Our crude oil operations are also subject to the requirements of the
Federal Occupational Safety and Health Act ("OSHA") and comparable state
statutes. We believe that our crude oil pipelines and trucking operations have
been operated in substantial compliance with OSHA requirements, including
general industry standards, record keeping requirements and monitoring of
occupational exposure to regulated substances. Various other federal and state
regulations require that we train all employees in pipeline and trucking
operations in HAZCOM and disclose information about the hazardous materials used
in our operations. Certain information must be reported to employees, government
agencies and local citizens upon request.
In general, we expect to increase our expenditures in the future to
comply with higher industry and regulatory safety standards such as those
described above. While the total amount of increased expenditures cannot be
accurately estimated at this time, we anticipate that we will expend a total of
approximately $9.6 million in 2003 and 2004 for testing and rehabilitation under
the IMP.
We operate our fleet of leased trucks as a private carrier. Although a
private carrier that transports property in interstate commerce is not required
to obtain operating authority from the ICC, the carrier is subject to certain
motor carrier safety regulations issued by the DOT. The trucking regulations
cover, among other things, driver operations, maintaining log books, truck
manifest preparations, the placement of safety placards on the trucks and
trailer vehicles, drug testing, safety of operation and equipment, and many
other aspects of truck operations. We are also subject to OSHA with respect to
its trucking operations. We are subject to federal EPA regulations for the
development of a written Spill Prevention Control and Countermeasure (SPCC)
Plan. All trucking facilities have a current SPCC Plan and employees have
received training on the SPCC Plan and regulations. Annually, trucking employees
receive training regarding the transportation of hazardous materials.
Commodities regulation
Our price risk management operations are subject to constraints imposed
under the Commodity Exchange Act and the rules of the NYMEX. The futures and
options contracts that are traded on the NYMEX are subject to strict regulation
by the Commodity Futures Trading Commission.
Information Regarding Forward-Looking Information
The statements in this Annual Report on Form 10-K that are not
historical information may be forward looking statements within the meaning of
Section 27a of the Securities Act of 1933 and Section 21E of the Securities
10
Exchange Act of 1934. Although we believe that our expectations regarding future
events are based on reasonable assumptions, no assurance can be made that our
goals will be achieved or that expectations regarding future developments will
prove to be correct. Important factors that could cause actual results to differ
materially from the expectations reflected in the forward looking statements
herein include, but are not limited to, the following:
o changes in regulations;
o our success in obtaining additional lease barrels;
o changes in crude oil production volumes (both world-wide and in
areas in which we have operations);
o developments relating to possible acquisitions, dispositions or
business combination opportunities;
o volatility of crude oil prices, P-Plus and grade differentials;
o the success of the risk management activities;
o credit requirements by the counterparties;
o the cost of obtaining liability and property insurance at a
reasonable cost;
o acts of sabotage, terrorism or other similar acts causing damage
greater than our insurance coverage limits;
o our ability in the future to generate sufficient amounts of
Available Cash to permit the payment to unitholders of a quarterly
distribution;
o any additional requirements for testing or changes in the
Mississippi pipeline system as a result of the oil spill that
occurred there in December 1999;
o any fines and penalties federal and state regulatory agencies may
impose in connection with the oil spill that would not be
reimbursed by insurance;
o the costs of testing under the IMP and any rehabilitation required
as a result of that testing;
o estimated timing and amount of future capital expenditures;
o our success in increasing tariff rates on our common carrier
pipelines;
o results of current or threatened litigation; and
o conditions of capital markets and equity markets during the
periods covered by the forward looking statements.
All previous and subsequent written or oral forward looking statements
attributable to us, or persons acting on the Partnership's behalf, are expressly
qualified in their entirety by the foregoing cautionary statements.
Item 2. Properties
We own and operate three common carrier crude oil pipeline systems. The
pipelines and related gathering systems consist of the 623-mile Texas system,
the 103-mile Jay System extending between Florida and Alabama, and the 219-mile
Mississippi System extending between Mississippi and Louisiana.
The Texas system includes 338 miles of pipe that has been temporary idled.
The segments that have been temporary idled are Groesbeck to Hearne, Bryan to
Satsuma (in northwest Houston), and Satsuma to Cullen Junction (south Houston).
We entered into a joint tariff with Teppco Crude Pipeline Company L.P. to
transfer oil to their custody near Satsuma and receive it back from them at
Cullen Junction.
We own approximately 800,000 barrels of storage capacity associated with
the Texas pipeline system. Additionally, we lease approximately 200,000 barrels
of storage capacity for the Texas System.
We own 200,000 barrels of storage capacity on our Mississippi System, with
the tankage spread across the system. The Jay system has 200,000 barrels of
storage capacity, primarily at Jay station.
In addition to transporting crude oil by pipeline, the Partnership
transports crude oil through a fleet of leased tractors and trailers. At
December 31, 2002, the trucking fleet consisted of 74 tractor-trailers. The
trucking fleet generally hauls the crude oil to one of the approximately 97
pipeline injection stations owned or leased by the Partnership.
We lease approximately 27,000 square feet of office space in Houston,
Texas, for our corporate office. This lease expires in 2005.
11
Item 3. Legal Proceedings
We are involved from time to time in various claims, lawsuits and
administrative proceedings incidental to our business. In our opinion, the
ultimate outcome, if any, is not expected to have a material adverse effect on
the financial condition or results of operations of the Partnership. See Note 20
of Notes to Consolidated Financial Statements.
Item 4. Submission of Matters to a Vote of Security Holders
None.
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 and the amount of cash distributions paid per Common
Unit.
Price Range Cash
High Low Distributions(1)
2002 ---------- --------- ----------------
----
First Quarter..... $ 3.94 $ 2.31 $ -
Second Quarter.... $ 4.20 $ 1.80 $ -
Third Quarter..... $ 5.75 $ 2.00 $ -
Fourth Quarter.... $ 5.00 $ 4.05 $ 0.20 (2)
2001
----
First Quarter..... $ 6.10 $ 3.50 $ 0.20
Second Quarter.... $ 6.00 $ 4.15 $ 0.20
Third Quarter..... $ 6.92 $ 4.20 $ 0.20
Fourth Quarter.... $ 7.00 $ 2.33 $ 0.20
- ---------------------
<FN>
(1) Cash distributions are shown in the quarter paid and are based on the
prior quarter's activities.
(2) A special distribution of $0.20 per unit was paid on December 16, 2002
to mitigate potential taxable income allocations to Unitholders.
</FN>
At December 31, 2002, there were 8,625,000 Common Units outstanding. As of
December 31, 2002, there were approximately 10,000 record holders and beneficial
owners (held in street name) of the Partnership's Common Units. The Partnership
will distribute 100% of its Available Cash as defined in the Partnership
Agreement within 45 days after the end of each quarter to Unitholders of record
and to the General Partner. Available Cash consists generally of all of the cash
receipts less cash disbursements of the Partnership adjusted for net changes to
reserves. The full definition of Available Cash is set forth in the Partnership
Agreement and amendments thereto, which is filed as an exhibit hereto.
In the fourth quarter of 2000, the Partnership was restructured pursuant to
a vote of the Common Unitholders. As a result of this restructuring, the target
Minimum Quarterly Distribution ("MQD") was reduced from $0.50 per Common Unit to
$0.20 per Common Unit beginning with the distribution for the fourth quarter of
2000.
In 2001, we announced that we would not pay a distribution for the fourth
quarter of 2001, which would normally have been paid in February 2002. We did
not pay regular distributions for 2002. The payment of distributions in the
future is dependent upon our ability to generate sufficient Available Cash and
whether we would violate covenants in our credit agreement by making such
distributions. Should distributions resume, the distribution per common unit
will be based upon the Available Cash generated for that quarter, which may be
less than $0.20 per unit. See Management's Discussion and Analysis of Financial
Condition and Results of Operations - Distributions.
Copies of our press releases and our filings with the SEC are available on
our website. Our website is www.genesiscrudeoil.com.
12
Item 6. Selected Financial Data
The table below includes selected financial data for the Partnership for
the years ended December 31, 2002, 2001, 2000, 1999 and 1998 (in thousands,
except per unit and volume data).
Year Ended December 31,
------------------------------------------------------------------------------
2002 2001 2000 1999 1998
------------- ------------- ------------- -------------- --------------
Income Statement Data:
Revenues:
Gathering & marketing revenues. $ 891,595 $ 3,326,003 $ 4,309,614 $ 2,144,646 $ 2,216,942
Pipeline revenues.............. 20,211 14,195 14,940 16,366 16,533
------------- ------------- ------------- -------------- --------------
Total revenues............... 911,806 3,340,198 4,324,554 2,161,012 2,233,475
Cost of sales:
Crude cost..................... 859,312 3,293,836 4,281,567 2,118,318 2,184,529
Field operating costs.......... 16,451 15,649 13,673 11,669 12,778
Pipeline operating costs....... 12,928 10,897 8,652 8,161 7,971
------------- ------------- ------------- -------------- --------------
Total cost of sales.......... 888,691 3,320,382 4,303,892 2,138,148 2,205,278
------------- ------------- ------------- -------------- --------------
Gross margin...................... 23,115 19,816 20,662 22,864 28,197
General and administrative expenses 8,289 11,691 10,942 11,649 11,468
Depreciation and amortization..... 5,813 7,546 8,032 8,220 7,719
Impairment of long-lived assets... - 45,061 - - -
Other operating charges........... 1,500 1,500 1,387 - 373
------------- ------------- ------------- -------------- --------------
Operating income (loss)........... 7,513 (45,982) 301 2,995 8,637
Interest income (expense), net.... (1,035) (527) (1,010) (929) 154
Change in fair value of derivatives (2,094) 2,259 - - -
Other income (expense)............ 708 167 1,148 849 28
------------- ------------- ------------- -------------- --------------
Income (loss) before minority
interest and cumulative effect
of change in accounting principle 5,092 (44,083) 439 2,915 8,819
Minority interests................ - (4) 258 583 1,763
------------- ------------- ------------- -------------- --------------
Income (loss) before cumulative
effect of change in accounting
principle....................... 5,092 (44,079) 181 2,332 7,056
Cumulative effect of change in
accounting principle, net of
minority interest effect - 467 - - -
------------- ------------- ------------- -------------- --------------
Net income (loss)................. $ 5,092 $ (43,612) $ 181 $ 2,332 $ 7,056
============= ============= ============= ============== ==============
Net income (loss) per common unit-
basic and diluted:
Income (loss) before cumulative
effect of change in accounting
principle.................... $ 0.58 $ (5.01) $ 0.02 $ 0.27 $ 0.80
Cumulative effect of change in
accounting principle - 0.05 - - -
------------- ------------ ------------- -------------- --------------
Net income (loss).............. $ 0.58 $ (4.96) $ 0.02 $ 0.27 $ 0.80
============= ============ ============= ============== ==============
Cash distributions per common unit: $ 0.20 $ 0.80 $ 2.28 $ 2.00 $ 2.00
Balance Sheet Data (at end of period):
Current assets.................... $ 92,830 $ 182,100 $ 350,604 $ 274,717 $ 185,216
Total assets...................... 137,537 230,113 449,343 380,592 297,173
Long-term liabilities............. 5,500 13,900 - 3,900 15,800
Minority interests................ 515 515 520 30,571 29,988
Partners' capital................. 35,302 32,009 82,615 53,585 67,871
Other Data:
Maintenance capital expenditures.. $ 4,211 $ 1,882 $ 1,685 $ 1,682 $ 1,509
Volumes (bpd):
Gathering and marketing:
Wellhead..................... 63,911 84,677 99,602 93,397 114,400
Bulk and exchange............ 37,002 270,845 297,776 242,992 325,468
Pipeline ...................... 75,869 84,686 86,458 94,048 85,594
13
The table below summarizes the Partnership's quarterly financial data for
2002 and 2001 (in thousands, except per unit data).
2002 Quarters
---------------------------------------------------------------
First Second Third Fourth
------------ ------------ ------------ ------------
Revenues................................. $ 239,239 $ 240,769 $ 209,916 $ 221,882
Gross margin............................. $ 5,438 $ 6,222 $ 6,268 $ 5,187
Operating income......................... $ 1,927 $ 2,543 $ 1,296 $ 1,747
Net income............................... $ 1,314 $ 2,106 $ 103 $ 1,569
Net income per Common Unit-basic
and diluted............................ $ 0.15 $ 0.24 $ 0.01 $ 0.18
2001 Quarters
---------------------------------------------------------------
First Second Third Fourth
------------ ------------ ------------ ------------
Revenues................................. $ 930,293 $ 920,879 $ 821,647 $ 667,379
Gross margin............................. $ 4,625 $ 5,791 $ 6,261 $ 3,139
Operating income (loss).................. $ 1 $ 922 $ 1,429 $ (48,334)
Net income (loss) before cumulative
effect of change in accounting
principle.............................. $ 3,404 $ 2,500 $ (267) $ (49,720)
Cumulative effect of change in accounting
principle, net of minority interest
effect................................. $ 467 $ - $ - $ -
Net income............................... $ 3,871 $ 2,500 $ (267) $ (49,720)
Net income (loss) before cumulative
effect of change in accounting
principle per Common Unit - basic and
diluted................................ $ 0.39 $ 0.28 $ (0.03) $ (5.65)
Net income (loss) per Common Unit -
basic and diluted $ 0.44 $ 0.28 $ (0.03) $ (5.65)
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Included in Management's Discussion and Analysis are the following
sections:
o Highlights of 2002
o Outlook for 2003 and Beyond
o Liquidity and Capital Resources
o Results of Operations
o Other Matters
o New Accounting Pronouncements
o Critical Accounting Policies
Highlights of 2002
We believe that the most important event of 2002 was the sale of our
General Partner by Salomon to a subsidiary of Denbury Resources Inc. ("Denbury")
on May 14, 2002. Genesis owns and operates a 219-mile pipeline system in
Mississippi adjacent to several of Denbury's existing and prospective oil
fields. Denbury is the largest oil and natural gas operator in the state of
Mississippi. There may be mutual benefits to Denbury and Genesis due to this
common production and transportation area. Because of this relationship, we may
obtain certain commitments for increased crude oil volumes, while Denbury may
obtain the certainty of transportation for its oil production at competitive
market rates. As Denbury continues to acquire and develop old oil fields using
carbon dioxide (CO2) based tertiary recovery operations, Denbury would expect to
add crude oil gathering and CO2 supply infrastructure to these fields. We may be
able to provide or acquire this infrastructure and provide support to
14
Denbury's development of these fields. Further, as the fields are developed over
time, it may create increased demand for our crude oil transportation
services.
During 2002, average daily throughput on the Mississippi System where
Denbury is a significant source of production near the pipeline increased from
approximately 6,000 barrels per day during May, 2002, the month Denbury acquired
our general partner, to approximately 9,900 barrels per day during December. We
expect this trend of increased throughput on these segments of the system to
continue. However, we can make no assurances that such increased throughput will
continue or predict that it will increase at this rate.
As a result of its acquisition by Denbury, the General Partner, Genesis
Energy, Inc. ("Genesis") amended Section 11.2 of the Second Amended and Restated
Agreement of Limited Partnership of Genesis Energy, L.P. ("the Partnership
Agreement") to broaden the right of the Common Unitholders to remove the general
partner of Genesis Energy, L.P. ("GELP"). Prior to this amendment, the general
partner could only be removed for cause and with approval by holders of
two-thirds or more of the outstanding limited partner interests in GELP. As
amended, the Partnership Agreement provides that, with the approval of at least
a majority of the limited partners in GELP, the general partner also may be
removed without cause. Any limited partner interests held by the general partner
and its affiliates are to be excluded from such a vote.
The amendment further provides that if it is proposed that the removal
is without cause and an affiliate of Denbury is the general partner to be
removed and not proposed as a successor, then any action for removal must also
provide for Denbury to be granted an option effective upon its removal to
purchase GELP's Mississippi pipeline system at a price that is 110 percent of
its fair market value at that time. Fair value is to be determined by agreement
of two independent appraisers, one chosen by the successor general partner and
the other by Denbury or if they are unable to agree, the mid-point of the values
determined by them.
The amendment was negotiated on behalf of GELP by the audit committee
of the board of directors of Genesis. Upon determination of its fairness,
including obtaining an opinion from the investment banking firm of the GulfStar
Group as to the amendment's fairness to the Common Unitholders of GELP, and an
opinion from Delaware legal counsel as to the form of the amendment, the audit
committee recommended approval of the amendment to the board of directors of
Genesis.
During 2002, we reached agreement in principal with the US
Environmental Protection Agency (EPA) and the Mississippi Department of
Environmental Quality (MDEQ) for the payment of fines under federal and state
environmental laws with respect to the Leaf River Spill in December, 1999. See
"Other Matters Crude Oil Spill". Based on the discussions leading to this
agreement in principal, we have recorded accrued liabilities totaling of $3.0
million during 2001 and 2002. While we are pleased with the progress we have
made toward resolving the uncertainty of this environmental liability during
2002, no assurance can be made that we will reach final agreement with the
federal and Mississippi governments or the specific terms of a final agreement
if one is reached.
We successfully completed a major transformation of our gathering and
marketing business model during 2002. The primary driver compelling us to change
our gathering and marketing business model was the December 31, 2001 replacement
of the $300 million Guaranty Facility from Salomon with a $130 million credit
facility with Citicorp North America, Inc. See Note 8 to Consolidated Financial
Statements and Credit Resources and Liquidity. As a result of this change, we
reduced credit support from a daily average of $174.5 million in Salomon
guarantees in 2001 to a daily average of $30.2 million in letters of credit from
Citicorp. We also reduced the direct cost of trade credit by half from $1.2
million in 2001 to $0.6 million in 2002. To achieve this result, we reduced our
average bulk and exchange volumes by 86 percent and our average wellhead volumes
by 25 percent from the 2001 levels. We also actively redirected the focus of our
lease gathering business to eliminate all volumes that required letters of
credit but did not generate sufficient gross margin to support the cost of such
credit support. As a result of these and other changes, gathering and marketing
gross margin per barrel increased from $0.13 in 2001 to $0.43 in 2002.
The financial performance of the gathering and marketing business
exceeded our expectations under the new business model. We were pleased to be
able to generate gross margin from the gathering and marketing business in 2002
that was 96 percent of the gross margin generated in 2001 while reducing volumes
by 72 percent and credit support by 83 percent. We also were able to make
permanent reductions to general and administrative expenses of $1.0 million by
this change to our business model.
As a result of the changes in our business activities described above,
we were able to reduce inventory volumes at some locations that had been
purchased in prior periods at prices significantly less than the prices at
15
the time we sold those volumes. These volumes had been necessary to ensure
efficient and uninterrupted operations in our gathering and marketing
activities. Prices for crude oil rose significantly during 2002 as is evidenced
by the increase in the price of West Texas Intermediate crude oil (WTI) on the
New York Mercantile Exchange (NYMEX), which rose from $20.24 at December 31,
2001 to $31.20 at December 31, 2002. By reducing this inventory in a period of
increasing prices we recognized $0.9 million of increased gross margin from the
sale of this crude oil.
During 2002, we took several steps to improve the profitability of our
pipeline operations. Our strategy involved three key initiatives. First, we
evaluated our pipeline systems to determine which segments, if any, should be
sold, idled or abandoned to reduce cost or risk of operation. Second, we
increased our tariffs wherever feasible to achieve an acceptable risk adjusted
rate of return. Third, we adjusted our pipeline loss allowances to levels
consistent with our peers.
We idled or abandoned 338 miles of pipeline on the Texas System during
2002. We expect to sell, idle or abandon more of the Texas System during 2003.
While we have made progress evaluating strategic opportunities with respect to
the Texas and Jay Systems, these projects are still in progress and we have no
substantial information to report at this time.
We increased most tariffs on the Texas System by 80 percent effective
May 1, 2002. We were pleased that this tariff increase did not result in a
significant decrease in volumes on the system. For the Jay System we increased
tariffs by 37 percent effective August 1, 2002. For all three systems we
increased the pipeline loss allowance that we charge our shippers for assuming
the operational risk of volumetric losses from 0.05% to 0.2% effective September
1, 2002. This adjustment placed us in line with most of our peers in the liquids
pipeline transportation business. This change is important to us since it
reduces the risk of incurring economic loss from operational anomalies and
creates some opportunity to profit from operating the pipeline in an effective
manner.
We developed and implemented a plan during 2002 to place the
Mississippi System in condition to handle increased throughput expected from
production increases in the area. We implemented operational changes that will
allow us to operate much of this pipeline at significantly reduced pressures and
will allow us to monitor and evaluate activity on the system in a more effective
manner. We also completed the work necessary to restore the segment idled as a
result of the 1999 Leaf River Spill. We expect to complete testing and restart
this segment early in 2003. Financial results for 2002 were negatively impacted
by the effects of SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities" (as amended and interpreted). With the significant reduction
in our bulk and exchange activities at December 31, 2001, combined with a review
of existing contracts, we determined that we had only one contract meeting the
requirement for treatment as a derivative contract under SFAS No. 133 at
December 31, 2002. As a result, the fair value of the net asset for derivatives
decreased by $2.1 million.
During 2002, we did not make a regular quarterly distribution. In
December 2001, we obtained a credit facility from Citicorp North America to
replace our Guaranty facility and our Credit Agreement with BNP Paribas. See
Note 9. This facility, however, includes a provision that does not allow us to
pay a distribution for any quarter unless the Borrowing Base under the facility
exceeded the usage under the facility for every day of the quarter by at least
$20 million plus the total amount of the distribution. For the first and second
quarters of 2002, we did not pay distributions as the excess of the Borrowing
Base over the usage was less than the required amount. During the third and
fourth quarters of 2002, we met the test and were not restricted from making a
distribution under the credit facility. However, we did not make a regular
quarterly distribution for these periods because of reserves established for
future needs of the Partnership. Such future needs include, but are not limited
to the payment of fines imposed by regulatory agencies for the December 1999
crude oil spill and future expenditures that will be required for pipeline
management integrity programs required by federal regulations.
Because some of the Partnership's Unitholders were allocated taxable
income for 2002, we did make a special distribution in the amount of $0.20 per
unit on December 16, 2002 to Unitholders of record as of December 2, 2002. The
amount of taxable income allocated to each unitholder varied, depending on the
timing of the unit purchases and the amount of each unitholder's basis in their
units. The distribution was made to mitigate the burden of incurring a tax
liability without receiving a cash distribution.
More detailed discussion of the financial results for 2002 can be found
below in "Liquidity and Capital Resources" and "Results of Operations". More
detailed discussion of the expectations for restoring the distribution can be
found below in "Outlook for 2003 and Beyond."
16
Outlook for 2003 and Beyond
Gathering and Marketing Operations
The key drivers affecting our gathering and marketing gross margin
include production volumes, volatility of P+ margins, volatility of grade
differentials, inventory management, and credit costs.
A significant factor affecting our gathering and marketing gross
margins is changes in the domestic production of crude oil. Short-term and
long-term price trends impact the amount of capital that producers have
available to maintain existing production and to invest in developing crude
reserves, which in turn impacts the amount of crude oil that is available to be
gathered and marketed by us and our competitors. The volatility in prices over
the last four years makes it very difficult to estimate the volume of crude oil
available to purchase. We expect to continue to be subject to volatility and
long-term declines in the availability of crude oil production for purchase by
us.
Oil prices rose in the latter half of 2002 such that the NYMEX price
for WTI was $31.20 at December 31, 2002. International factors such as the
strike by oil workers in Venezuela and the potential for war with Iraq as well
as domestic influences such as the supply of crude oil in the United States have
contributed to the price increase. An increase in the market price of crude oil
does not impact us to the extent many people expect. When market prices for oil
increase, we must pay more for crude oil, but we normally are able to sell it
for more.
Most of our contracts for the purchase and sale of crude oil have
components in the pricing provisions such that the price paid or received is
adjusted for changes in the market price for crude oil. Often the pricing in a
contract to purchase crude oil will consist of the market price component and a
bonus, which is generally a fixed amount ranging from a few cents to several
dollars. Typically the pricing in a contract to sell crude oil will consist of
the market price component and a bonus that is not fixed, but instead is based
on another market factor. This floating bonus is usually the price quoted by
Platt's for WTI "P-Plus". Because the bonus for purchases of crude oil is fixed
and P-Plus floats in the sales contracts, the margin on an individual
transaction can vary from month-to-month depending on changes in the P-Plus
component.
P-Plus does not necessarily move in correlation with the price of oil
in the market. P-Plus is affected by numerous factors such as future
expectations for changes in crude oil prices, such that crude oil prices can be
rising, but P-Plus can be decreasing. The table below shows the average P-Plus
and the average posted price for West Texas Intermediate (WTI) as posted by Koch
Supply & Trading, L.P. for each month in 2002.
Month Average P-Plus WTI Posting
----- -------------- -----------
January $2.7900 $16.5161
February $2.7440 $17.6071
March $2.8520 $21.3306
April $2.8940 $22.9500
May $3.1005 $23.7903
June $3.9100 $22.4500
July $3.0010 $23.7500
August $3.3330 $24.9516
September $3.9860 $26.4750
October $3.2310 $25.6613
November $3.3740 $23.0917
December $3.9130 $26.2177
As can be seen from this table, changes in P-Plus do not necessarily
correspond to changes in the market price of oil. This unpredictable volatility
in P-Plus can create volatility in our earnings.
A few purchase contracts and some sale contracts also include a
component for grade differentials. The grade refers to the type of crude oil.
Crude oils from different wells and areas can have different chemical
compositions. These different grades of crude oil will appeal to different
customers depending on the processing capabilities of the refineries who
ultimately process the oil. We may buy oil under a contract where we considered
the typical grade differences in the market when we set the fixed bonus. If we
then sell the oil under a contract with a floating grade differential in the
formula, and that grade differential fluctuates, then we can experience an
increase or decrease in our gross margin from that oil purchase and sale. The
table below shows the grade differential
17
between West Texas Intermediate grade crude oil and West Texas Sour grade
crude oil for each month of 2002 and the differential between West Texas
Intermediate grade crude oil and Light Louisiana Sweet grade crude oil for each
month of 2002.
WTI/WTS WTI/LLS
Month Differential Differential
----- ------------ ------------
January $(1.834) $ 0.260
February $(1.544) $ 0.353
March $(1.231) $ 0.432
April $(1.254) $ 0.358
May $(1.049) $ 0.493
June $(1.352) $(0.581)
July $(1.016) $ 0.175
August $(0.812) $ 0.098
September $(1.257) $(0.370)
October $(1.666) $(0.167)
November $(1.408) $ 0.186
December $(2.243) $(0.008)
As can be seen from this table, the WTI/WTS market differential varied
from $0.812 in August to $2.243 per barrel in December, 2002. The WTI/LLS market
differential varied from a negative $0.581 in June to a positive $0.493 in May
2002. This volatility in grade differentials can affect the volatility of our
gathering and marketing gross margins.
The purchase and sales contracts are primarily "Evergreen" contracts
which means they continue from month to month unless one of the parties to the
contract gives 30-days notice of cancellation. In order to change the pricing in
a fixed bonus contract, we would have to give 30-days notice that we want to
cancel and renegotiate the contract. This notice time requirement, therefore,
means that at least a month will pass before the fixed bonus can be reduced to
correspond with a decrease in the P-Plus component of the related sales
contract. In this case our margin would be reduced until such a change is made.
Because of the volatility of P-Plus, it is not practical to renegotiate every
purchase contract for every change in P-Plus. So margins from the sale of the
crude oil can be volatile as a result of these timing differences.
Another factor that can contribute to volatility in our earnings is
inventory management. Generally contracts for the purchase of crude oil will
state that we will buy all of the production for the month from a particular
well. We generally aggregate the volumes purchased from numerous wells and
deliver it into a pipeline where we sell the crude oil to a third party. While
oil producers can make estimates of the volume of oil that their wells will
produce in a month, they cannot state absolutely how much oil will be produced.
Our sales contracts typically state a specific volume to be sold. Consequently,
if a well produces more than expected we will purchase volumes in a month that
we have not contracted to sell. These volumes are then held as inventory and are
sold in a later month. Should the market price of crude oil fluctuate while we
have these inventory volumes, we may have to record a loss in our financial
statements should the market price fall below the cost of the inventory. Should
market prices rise, then we will experience a gain when we sell the unexpected
volume of inventory in a later month at higher prices.
We believe we have successfully changed our business model for our
gathering and marketing activities to consume less credit support and working
capital. We expect this business to continue to perform well during 2003,
although not as well as in 2002. Both volumes and margins are expected to be
lower during 2003 as this business is likely to be subject to volatility and
increased trade credit costs. Additionally, this business may be constrained by
the need for trade credit if crude oil prices increase above current levels.
During 2003, we expect gathering and marketing gross margins to decline due to
an expected decrease in the volume of crude oil to be gathered during 2003.
Pipeline Operations
As discussed above in "Highlights of 2002", volumes on our pipeline
systems declined in 2002. Additionally, operating and maintenance costs
increased. For 2003, we expect that volumes may decline in some areas our
pipelines serve, but overall average volumes to transport will likely increase
from 2002 levels. We also
18
expect to expend funds on additional testing under the integrity management
regulations and other large maintenance projects.
Volumes on our Texas System averaged 51,987 barrels per day in 2002. We
expect that these volumes will decline in 2003 slightly, however the effect of
the volume decline on tariff revenues for the year should be mitigated as the
increase in tariffs that took effect in May 2002 will be in effect for all of
2003. In 2003, we expect to test the Webster to Texas City segment as well as
the Cullen Junction to Webster sections under the integrity management
regulations. See discussion of the integrity management regulations in Safety
Regulation under in "Item 1. This testing in 2003 is expected to add over $0.3
million to routine operating and maintenance expenses. The results of the
testing will likely result in upgrades to the pipeline which we have estimated
will cost approximately $3.3 million. Additional discussion of expectations for
capital expenditures for the Texas System can be found in Capital Expenditures
in "Liquidity and Capital Resources" below.
In 2002, we stopped using segments of the Texas System from Bryan to
Satsuma and from Satsuma to Cullen Junction. In September, we entered into a
joint tariff agreement with Teppco Crude Pipeline Company, L.P. for Teppco to
transport oil from Satsuma to Cullen Junction. During 2003, we plan to idle
these segments that are no longer in use. To idle a segment of pipeline, we must
purge the crude oil in the line and replace it with inert gas. This process will
add maintenance costs that we estimate to total less than $0.1 million.
We are currently reviewing strategic opportunities for the Texas
System. While the tariff increases in 2002 have improved the outlook for this
system, we continue to examine opportunities for every part of the system to
determine if each segment should be sold, abandoned or invested in for further
growth. As part of this examination, we must consider the ability to increase
tariffs, which involves reviewing the alternatives available to shippers to move
the oil on other pipelines or by truck, production and drilling in the area
around the pipeline, the costs to test and improve our pipeline under integrity
management regulations, and other maintenance and capital expenditure
expectations.
The Mississippi System is best analyzed in three segments. The first
segment is the portion of the pipeline that begins in Soso, MS and extends to
Gwinville, MS where the spill occurred in 1999. We spent $0.6 million in 2002
upgrading the pipeline from Soso to Gwinville. We expect this segment of the
pipeline to be fully operational during the first half of 2003. The second
segment from Gwinville to Liberty has also been improved to handle the increased
volumes produced by Denbury and transported on the pipeline. Volumes on this
segment have risen from a low of 3,300 barrels per day in February to almost
10,000 barrels per day in December 2002. In order to handle this higher volume,
we have made capital expenditures for tank, station and pipeline improvements
and we will need to make more. See Capital Expenditures under "Liquidity and
Capital Resources" below.
The third segment of the pipeline from Liberty to near Baton Rouge, LA
has been out of service since February 1, 2002 while a connecting carrier
performs maintenance on its pipeline. The connecting carrier expects to complete
their maintenance activities in the second quarter of 2003. At that time we will
need to determine if there are sufficient volumes available to be transported on
this segment of pipeline to justify the costs to perform the integrity testing
and possible upgrading that may be identified in that testing. In 2002, this
segment of pipeline contributed $0.1 million to pipeline revenues. In 2001, this
segment contributed $1.5 million to pipeline revenues.
As discussed above, Denbury is the largest oil and natural gas producer
in Mississippi. Our Mississippi pipeline is adjacent to several of Denbury's
existing and prospective oil fields. There may be mutual benefits to Denbury and
us due to this common production and transportation area. Because of this
relationship, we may be able to obtain certain commitments for increased crude
oil volumes, while Denbury may obtain the certainty of transportation for its
oil production at competitive market rates. As Denbury continues to acquire and
develop old oil fields using carbon dioxide (CO2) based tertiary recovery
operations, Denbury would expect to add crude oil gathering and CO2 supply
infrastructure to these fields. Further, as the fields are developed over time,
it may create increased demand for our crude oil transportation services.
We believe that the highest and best use of the Jay pipeline system in
Florida/Alabama would be to convert it to natural gas service. We have entered
into strategic alliances with parties in the region to explore this opportunity.
Part of the process will involve finding alternative methods for us to continue
to provide crude oil transportation services in the area. While we believe this
initiative has long-term potential, it is not expected to have a substantial
impact on us during 2003 or 2004.
19
Pipeline gross margins should decline slightly in 2003. We expect to
obtain the benefit of the 2002 tariff increases for the full year 2003 as well
as continued increases to throughput. Offsetting these revenue increases will be
increased costs for maintenance, insurance and safety.
General and Administrative Expenses
General and administrative expenses are expected to remain stable.
Offsetting permanent cost reductions from the changed business model will be a
one-time adjustment for replacing the Citicorp Agreement with a new bank
facility with Fleet National Bank as agent, and cost increases for insurance and
other costs to comply with SEC regulations mandated by the Sarbanes-Oxley Act.
Capital Expenditures
An important factor affecting our outlook is capital expenditures. In
our 2001 Form 10-K, we indicated that we may need to increase capital
expenditures as a result of complying with IMP regulations and other regulatory
requirements. Based on our preliminary experience with the IMP program during
2002, we have established a capital budget of $6.7 million for 2003. For 2004,
we expect to make capital expenditures of $8.4 million. After 2004, capital
expenditures are expected to return to a normal pattern of approximately $2.0
million per year.
Access to Capital
In the first quarter of 2003, we replaced the credit facility from
Citicorp North America, Inc. ("Citicorp Agreement") with a three-year $65
million revolving loan and letter of credit facility with Fleet National Bank as
agent ("Fleet Agreement"). The Fleet Agreement has terms similar to the terms in
the Citicorp Agreement. The details of those terms are described more fully
below in "Liquidity and Capital Resources". The main differences from the
Citicorp Agreement are as follows: (a) the new facility permits us to make
acquisitions of assets that are used in our existing business; (b) the new
facility does not have the $3.0 million limitation on capital expenditures per
year and (c) the new facility includes a restriction on our ability to make
distributions that requires a difference of $10 million between the borrowing
base and utilization of the facility plus distributions, as measured once each
month. In the Citicorp Agreement, the borrowing base had to exceed utilization
(working capital borrowings plus outstanding letters of credit) plus the amount
of the distribution by $20 million every day of the quarter in order for us to
make a distribution.
As a result of the replacement of the Citicorp Agreement, the
unamortized fees paid in December 2001 to obtain the Citicorp Agreement will be
charged to expense in the first quarter of 2003. The amount of fees to be
charged to expense is $0.6 million.
Our outlook will also be impacted by our access to capital for growth.
In March 2003, we entered into the $65 million three-year revolving credit
facility led by Fleet Bank to replace our existing facility. The combination of
obtaining this new facility and our relationship with Denbury should improve our
ability to grow the business. However, based on our experience in obtaining this
facility, we believe that it will be important for us to further strengthen our
balance sheet and improve our financial metrics to be able to improve our access
to significant capital for growth.
Distribution Expectations
As a master limited partnership, the key consideration of our
Unitholders is the amount of our distribution, its reliability and the prospects
for distribution growth. As stated above, we made no regular distribution during
2002. We made no distribution with respect to the first two quarters of 2002
because of a restrictive covenant in our credit facility with Citicorp. We made
no regular distribution for the third and fourth quarters as we added to
reserves for the future needs of the Partnership. We did make a special
distribution to our Unitholders in December 2002, to mitigate the burden of
incurring a tax liability without receiving a cash distribution. During 2002 we
generated $11.8 million of Available Cash before reserves, required debt
payments and the special distribution. During 2003, we expect Available Cash
before distributions to be less.
We expect to resume regular quarterly distributions during 2003 with an
anticipated first quarter distribution of at least $0.05 per unit on May 15,
2003, to unitholders of record as of April 30, 2003. Based on the need for
larger than normal capital expenditures to comply with the pipeline regulations
during 2003 and 2004 and the need to strengthen our balance sheet to improve our
access to capital for growth, and considering the restrictive covenant in our
new credit facility, we do not expect to restore the regular distribution to the
targeted minimum
20
quarterly distribution amount of $0.20 per quarter for the next year or two.
However, if we exceed our expectations for improving the performance of the
business, if our capital projects cost less than we currently estimate, or if
our access to capital allows us to make accretive acquisitions, we may be able
to restore the targeted minimum quarterly distribution sooner.
Liquidity and Capital Resources
Cash Flows
During 2002, we generated cash flows from operating activities of $7.4
million as compared to $16.8 million for 2001. In 2002, we reduced our current
liabilities by $87.5 million while our current assets declined by $89.3 million.
In 2001, we reduced our current liabilities by $159.3 million while our current
assets declined by $168.5 million. Factors related to the timing of cash
receipts and payments related to the bulk and exchange business were the primary
reasons for the fluctuation in our current assets and liabilities in these
periods.
Cash flows used in investing activities in 2002 were $2.0 million as
compared to $1.4 million in 2001. In 2002 we expended $4.2 million for property
and equipment additions. These expenditures included replacement of pipe in
Mississippi and Texas and upgrades to pipeline stations in Mississippi to handle
larger volumes of crude oil throughput, including building new tanks. Offsetting
these expenditures in 2002, were sales of surplus assets from which we received
$2.2 million. In early 2002, we sold our two seats on the NYMEX for $1.7
million. These seats had become surplus assets when the business model was
changed to reduce bulk and exchange activities, reducing the level of NYMEX
activity that Genesis would need. We also received $0.5 million from the sale of
excess land with a building.
In 2001, we expended $1.9 million for property and equipment, primarily
in the pipeline operations. We received $0.5 million from the sale of tractors
and trailers that were no longer needed as the fleet was replaced with new
equipment leased from Ryder Transportation Inc.
Net cash expended for financing activities was $10.2 million in 2002 as
compared to $15.1 million in 2001. In 2002 we reduced long-term debt outstanding
at year end by $8.4 million from the balance at December 31, 2001. We also paid
a special distribution of $0.20 per unit in December 2002, which utilized $1.8
million of cash. In 2001, we reduced debt by $8.1 million from the balance at
December 31, 2000, and paid four quarterly distributions in the amount of $0.20
per unit each, which utilized $7.0 million of cash.
Capital Expenditures
As discussed above, we expended $4.2 million in 2002 for property and
equipment. We spent $1.8 million for capital expenditures on the Mississippi
Pipeline System, $1.6 million on the Texas Pipeline System, and $0.8 million for
computer hardware, software, communication and other technological equipment
used for pipeline and trucking operations. The $1.8 million spent for the
Mississippi Pipeline System was for two purposes. First, we made improvements to
the pipeline from Soso to Gwinville where the crude oil spill had occurred in
December 1999 to restore this segment to service. This project was part of the
IMP program discussed below. Second, we improved the pipeline from Gwinville to
Liberty to be able to handle increased volumes on that segment by adding tankage
and making other improvements to station equipment. In Texas, we upgraded the
West Columbia segment of the pipeline and improved station equipment.
Complying with Department of Transportation Pipeline Integrity
Management Program (IMP) regulations has been and will be a significant driver
in determining the amount and timing of our capital expenditure requirements. On
March 31, 2001, the Department of Transportation promulgated the IMP
regulations. The IMP regulations require that we perform baseline assessments of
all pipelines that could affect a High Consequence Area. The integrity of these
pipelines must be assessed by internal inspection, pressure test, or equivalent
alternative new technology. A High Consequence Area (HCA) is defined as (a) a
commercially navigable waterway; (b) an urbanized area that contains 50,000 or
more people and has a density of at least 1,000 people per square mile; (c)
other populated areas that contain a concentrated population, such as an
incorporated or unincorporated city, town or village; and (d) an area of the
environment that has been designated as unusually sensitive to oil spills. Due
to the proximity of all of our pipelines to water crossings and populated areas,
we have designated all of our pipelines as affecting HCAs. In accordance with
the IMP regulations, we prepared a written Integrity Management Plan by March
31, 2002, that details our plans for testing and assessing each segment of the
pipeline. The IMP regulations require that the baseline assessment be completed
within seven years of March 31, 2002, with 50% of the mileage
21
assessed in the first three and one-half years. Reassessment is then
required every five years. We expect to spend $1.0 million in 2003 and $0.1
million in 2004 for pipeline integrity testing that will be charged to pipeline
operating expense as incurred. As testing is complete, we are required to take
prompt remedial action to address all integrity issues raised by the assessment.
The rehabilitation action required as a result of the assessment and
testing is expected to impact our capital expenditure program by requiring us to
make improvements to our pipeline. This creates a difficult budgeting and
planning challenge as we cannot predict the results of pipeline testing until
they are completed. Based on estimated improvements required from assessments
made during 2002, we have estimated capital expenditures to be made during the
IMP assessment period from 2002 through 2009. These capital expenditure
projections are based on very preliminary data regarding the cost of
rehabilitation. Such capital expenditure projections will be updated as improved
data is obtained. During 2002, $1.7 million of the $4.2 million in capital
expenditures were for rehabilitation of the Mississippi and Texas Pipeline
Systems. Based on actual experience during 2002 applied to our written IMP plan,
we expect to spend significant amounts in 2003 and 2004 for capital
expenditures.
In 2003, we estimate our capital expenditures will be approximately
$8.0 million. We expect $4.1 million of the $8.0 million will be spent for
capital improvements to our pipeline systems as result of the IMP assessments.
Of the remaining $3.9 million in capital expenditures, substantially all of it
will be spent on other pipeline improvements such as tankage, equipment
upgrades, and corrosion control.
In 2004, we expect the level of capital expenditures to be
approximately $8.3 million with $4.6 million for pipeline integrity improvements
and the balance of $3.5 million for tankage and other improvements. At the end
of 2004, we expect that we will have incurred most of the significant costs
related to the IMP regulatory compliance and expect to only spend $1.8 million
in 2005 for capital items, with $1.2 million related to IMP. Expenditures in
years after 2006 should remain in the $1.5 million to $2.5 million level as the
expected integrity improvements should not be as great on the segments of the
pipelines with the lower 50% risk.
Capital Resources
In December 2001, we entered into a two-year $130 million Senior
Secured Revolving Credit Facility ("Citicorp Agreement") with Citicorp to
provide letters of credit and working capital borrowings. In May 2002, we
elected, under the terms of the Citicorp Agreement, to amend the Citicorp
Agreement to reduce the maximum facility amount to $80 million. The Citicorp
Agreement contains a sublimit for working capital loans of $25 million with the
remainder available for letters of credit to support crude oil purchases.
In March 2003, we replaced our Citicorp Agreement with a $65 million
three-year credit facility with a group of banks with Fleet National Bank as
agent ("Fleet Agreement"). The Fleet Agreement also has a sublimit for working
capital loans in the amount of $25 million, with the remainder of the facility
available for letters of credit.
The key terms of the Fleet Agreement are as follows:
o Letter of credit fees are based on the Applicable Usage Level
("AUL") and will range from 2.00% to 3.00%. During the first six
months of the facility, the rate will be 2.50%. The AUL is a
function of the facility usage to the borrowing base on that day.
o The interest rate on working capital borrowings is also based on the
AUL and allows for loans based on the prime rate or the LIBOR rate
at our option. The interest rate on prime rate loans can range from
the prime rate plus 1.00% to the prime rate plus 2.00%. The interest
rate for LIBOR-based loans can range from the LIBOR rate plus 2.00%
to the LIBOR rate plus 3.00%. During the first six months of the
facility, the rate will be the Libor rate plus 2.50%.
o We will pay a commitment fee on the unused portion of the $65
million commitment. This commitment fee is also based on the AUL and
will range from 0.375% to 0.50%. During the first six months of the
facility, the commitment fee will be 0.50%.
o The amount that we may have outstanding cumulatively in working
capital borrowings and letters of credit is subject to a Borrowing
Base calculation. The Borrowing Base (as defined in the Fleet
Agreement) generally includes our cash balances, net accounts
receivable and inventory, less deductions for certain accounts
payable, and is calculated monthly.
22
o Collateral under the Fleet Agreement consists of our accounts
receivable, inventory, cash accounts, margin accounts and property
and equipment.
o The Fleet Agreement contains covenants requiring a Current Ratio (as
defined in the Fleet Agreement), a Leverage Ratio (as defined in the
Fleet Agreement), a Cash Flow Coverage Ratio (as defined in the
Fleet Agreement), a Funded Indebtedness to Capitalization Ratio (as
defined in the Fleet Agreement), Minimum EBITDA, and limitations on
distributions to Unitholders.
Under the Citicorp Agreement, distributions to Unitholders and the
General Partner could only be made if the Borrowing Base exceeded the usage
(working capital borrowings plus outstanding letters of credit) under the
Citicorp Agreement for every day of the quarter by at least $20 million plus the
distribution. Under the Fleet Agreement, this provision is changed to require
that the Borrowing Base exceed the usage under the Fleet Agreement by at least
$10 million plus the distribution measured once each month. See additional
discussion below under "Distributions".
At December 31, 2002, we had $5.5 million outstanding under the
Citicorp Agreement. Due to the revolving nature of loans under the Citicorp
Agreement, additional borrowings and periodic repayments and re-borrowings may
be made until the maturity date of December 31, 2003. At December 31, 2002, we
had letters of credit outstanding under the Citicorp Agreement totaling $26.3
million, comprised of $13.8 million and $12.5 million for crude oil purchases
related to December 2002 and January 2003, respectively.
As a result of our decision to reduce the level of bulk and exchange
transactions, credit support in the form of letters of credit has been less in
2002 than it was in 2001. However, any significant decrease in our financial
strength, regardless of the reason for such decrease, may increase the number of
transactions requiring letters of credit, which could restrict our gathering and
marketing activities due to the limitations of the Fleet Agreement and Borrowing
Base. This situation could in turn adversely affect our ability to maintain or
increase the level of our purchasing and marketing activities or otherwise
adversely affect our profitability and Available Cash.
Working Capital
Our balance sheet reflects negative working capital of $3.5 million.
The majority of this difference can be attributed to the accrual for the fines
and penalties that we expect to pay to state and federal regulators related to
the December 1999 Mississippi oil spill. That accrual is $3.0 million. As we
have a working capital sublimit under the Fleet Agreement of $25 million and
have only borrowed $5.5 million at December 31, 2002, we have the ability to
borrow the funds to make the necessary payments.
Contractual Obligation and Commercial Commitments
In addition to the Citicorp Agreement discussed above, we have
contractual obligations under operating leases as well as commitments to
purchase crude oil. The table below summarizes these obligations and commitments
at December 31, 2002 (in thousands).
Payments Due by Period
-----------------------------------------------------------------------
Less than 1 - 3 4 - 5 After 5
Contractual Cash Obligations Total 1 Year Years Years Years
---------------------------- ------------ ------------ ----------- ------------ ------------
Operating Leases......... $ 15,630 $ 4,128 $ 7,057 $ 1,927 $ 2,518
Unconditional Purchase
Obligations (1) 139,852 138,918 934 - -
------------ ------------ ----------- ------------ ------------
Total Contractual Cash
Obligations $ 155,482 $ 143,046 $ 7,991 $ 1,927 $ 2,518
============ ============ =========== ============ ============
<FN>
(1) The unconditional purchase obligations included above are
contracts to purchase crude oil, generally at market-based
prices. For purposes of this table, market prices at December
31, 2002, were used to value the obligations, such that actual
obligations may differ from the amounts included above.
</FN>
Distributions
The Partnership Agreement for Genesis Energy, L.P. provides that we
will distribute 100% of our Available Cash within 45 days after the end of each
quarter to Unitholders of record and to the General Partner. Available
23
Cash consists generally of all of our cash receipts less cash disbursements
adjusted for net changes to reserves. (A full definition of Available Cash is
set forth in the Partnership Agreement.) The Partnership Agreement indicates
that the target minimum quarterly distribution ("MQD") for each quarter is $0.20
per unit.
Under the terms of the Citicorp Agreement, we could not pay a
distribution for any quarter unless the Borrowing Base exceeded the usage under
the Citicorp Agreement (working capital loans plus outstanding letters of
credit) for every day of the quarter by at least $20 million plus the total
amount of the distribution.
For the first and second quarters of 2002, we did not pay a
distribution as the excess of the Borrowing Base over the usage dropped below
the required total. During the third quarter of 2002, we met this test and thus
were not restricted from making a distribution under the Citicorp Agreement.
However, we did not make a distribution for the third quarter of 2002 because of
a reserve established for future needs of the Partnership. These reserves
exceeded Available Cash for the third quarter of 2002. Similarly, we did not
make a regular distribution for the fourth quarter of 2002 as reserves again
exceeded Available Cash. Such future needs of the Partnership include, but are
not limited to, the fines that are being imposed in connection with the crude
oil spill that occurred on the Mississippi System in December 1999 and future
expenditures that will be required for pipeline integrity management programs
required by federal regulations that are described above under "Capital
Expenditures".
Available cash before reserves for the year ended December 31, 2002, is
as follows (in thousands):
Net income................................................... $ 5,092
Depreciation and amortization................................ 5,813
Increase to environmental accrual............................ 1,500
Change in fair value of derivatives.......................... 2,094
Net gain from asset sales.................................... 1,535
Maintenance capital expenditures............................. (4,211)
-----------
Available Cash before reserves............................... $ 11,823
Special distribution paid in December 2002................... (1,760)
Reduction of debt required in 2002 as a result of asset sales (2,171)
-----------
Remaining Available Cash before reserves..................... $ 7,892
===========
As discussed above in Outlook for 2003 and Beyond above, we expect to
resume regular quarterly distributions during 2003 of at least $0.05 per unit.
Any decision to restore the distribution to the targeted minimum quarterly
distribution will take into account our ability to sustain the distribution on
an ongoing basis with cash generated by our existing asset base, capital
requirements needed to maintain and optimize the performance of our asset base,
and our ability to finance our existing capital requirements and accretive
acquisitions.
For each of the first three quarters of 2001, the Partnership paid a
distribution to the Common Unitholders and the General Partner of $0.20 per
unit.
Some of the Partnership's Unitholders were allocated taxable income for
2002. The amount of taxable income allocated to each unitholder varied,
depending on the timing of unit purchases and the amount of each unitholder's
tax basis in their units. In order to mitigate the burden of incurring a tax
liability without receiving a cash distribution, we made a special distribution
in the amount of $0.20 per unit on December 16, 2002 to Unitholders of record as
of December 2, 2002.
Industry Credit Market Disruptions
Over the last eighteen months there have been an unusual number of
business failures and large financial restatements by small as well as large
companies in the energy industry. Because the energy industry is very credit
intensive, these failures and restatements have focused attention on the credit
risks of companies in the energy industry by credit rating agencies, producers
and counterparties.
This focus on credit has affected us in two ways - requests for credit
from producers and extension of credit to counterparties. While we have seen
some increase in requests for credit support from producers (primarily in the
first quarter of 2002), we have been relatively successful in obtaining open
credit from most producers.
Because we are an aggregator of crude oil, sales of crude oil tend to
be large volume transactions. In transacting business with our counterparties,
we must decide how much credit to extend to each counterparty, as well as the
form and amount of financial assurance to obtain from counterparties when credit
is not extended.
24
We have modified our credit arrangements with certain counterparties that
have been adversely affected by recent financial difficulties in the energy
industry.
Our accounts receivable settle monthly and collection delays generally
relate only to discrepancies or disputes as to the appropriate price, volume or
quality of crude oil delivered. Of the $80.7 million aggregate receivables on
our consolidated balance sheet at December 31, 2002, approximately $79.9
million, or 99%, were less than 30 days past the invoice date.
FERC Notice of Proposed Rulemaking
On August 1, 2002, the Federal Energy Regulatory Commission ("FERC")
issued a Notice of Proposed Rulemaking that, if adopted, would amend its Uniform
System of Accounts for public utilities, natural gas companies and oil pipeline
companies by requiring specific written documentation concerning the management
of funds from a FERC-regulated subsidiary by a non-FERC-regulated parent. Under
the proposed rule, as a condition for participating in a cash management or
money pool arrangement, the FERC-regulated entity would be required to maintain
a minimum proprietary capital balance (stockholder's equity) of 30 percent, and
the FERC-regulated entity and its parent would be required to maintain
investment grade credit ratings. If either of these conditions is not met, the
FERC-regulated entity would not be eligible to participate in the cash
management or money pool arrangement. This proposed rule was subject to a
comment period of 15 days after its publication in the Federal Register. A
significant number of comments were received by the FERC. Hearings have been
held by the FERC and industry organizations have submitted suggestions of
changes to the proposed rule. At this time, it is unclear when, or if, the rule
will be enacted. We believe that, if enacted as proposed, this rule may affect
the manner in which we manage our cash; however, we are unable to predict the
full impact of this proposed regulation on our business.
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. Selected financial data for this discussion of the results of
operations follows, in thousands.
Years Ended December 31,
-----------------------------------------------
2002 2001 2000
------------ ----------- ------------
Revenues
Gathering & marketing....................... $ 891,595 $ 3,326,003 $ 4,309,614
Pipeline.................................... $ 20,211 $ 14,195 $ 14,940
Gross margin
Gathering & marketing....................... $ 15,832 $ 16,518 $ 14,374
Pipeline.................................... $ 7,283 $ 3,298 $ 6,288
General and administrative expenses............. $ 8,289 $ 11,691 $ 10,942
Depreciation and amortization................... $ 5,813 $ 7,546 $ 8,032
Impairment of long-lived assets................. $ - $ 45,061 $ -
Other operating charges......................... $ 1,500 $ 1,500 $ 1,387
Operating income (loss)......................... $ 7,513 $ (45,982) $ 301
Interest income (expense), net.................. $ (1,035) $ (527) $ (1,010)
Change in fair value of derivatives............. $ (2,094) $ 2,259 $ -
Cumulative effect of adoption of FAS 133........ $ - $ 467 $ -
Net gain on disposal of surplus assets.......... $ 708 $ 167 $ 1,148
25
Our profitability depends to a significant extent upon our ability to
maximize gross margin. Gross margins from gathering and marketing operations are
a function of volumes purchased and the difference between the price of crude
oil at the point of purchase and the price of crude oil at the point of sale,
minus the associated costs of aggregation and transportation. The absolute price
levels for crude oil do not necessarily bear a relationship to gross margin as
absolute price levels normally impact revenues and cost of sales by equivalent
amounts. Because period-to-period variations in revenues and cost of sales are
not generally meaningful in analyzing the variation in gross margin for
gathering and marketing operations, such changes are not addressed in the
following discussion.
In our gathering and marketing business, we seek to purchase and sell crude
oil at points along the Distribution Chain where we can achieve positive gross
margins. We generally purchase crude oil at prevailing prices from producers at
the wellhead under short-term contracts. We then transport the crude along the
Distribution Chain for sale to or exchange with customers. Additionally, we
enter into exchange transactions with third parties. We generally enter into
exchange transactions only when the cost of the exchange is less than the
alternate cost we would incur in transporting or storing the crude oil. In
addition, we often exchange one grade of crude oil for another to maximize
margins or meet contract delivery requirements. Prior to the first quarter of
2002, we purchased crude oil in bulk at major pipeline terminal points. These
bulk and exchange transactions were characterized by large volumes and narrow
profit margins on purchases and sales.
Generally, as we purchase crude oil, we simultaneously establish a margin
by selling crude oil for physical delivery to third party users, such as
independent refiners or major oil companies. Through these transactions, we seek
to maintain a position that is substantially balanced between crude oil
purchases, on the one hand, and sales or future delivery obligations, on the
other hand. It is our policy not to hold crude oil, futures contracts or other
derivative products for the purpose of speculating on crude oil price changes.
Year Ended December 31, 2002 Compared with Year Ended December 31, 2001
Gross margin. Gathering and marketing gross margins decreased $0.7
million or 4% to $15.8 million for the year ended December 31, 2002, as compared
to $16.5 million for the year ended December 31, 2001.
The factors affecting gross margin were:
o an increase in gross margin of $22.4 million due to an increase in the
average difference between the price of crude oil at the point of
purchase and the price of crude oil at the point of sale;
o a 72 percent decrease in wellhead, bulk and exchange purchase volumes
between 2001 and 2002, resulting in a decrease in gross margin of
$23.9 million;
o a decrease of $0.7 million in credit costs primarily due to the
reduction in bulk and exchange transactions;
o a $0.9 million increase in gross margin in the 2002 period as a result
of the sale of crude oil that is no longer needed to ensure efficient
and uninterrupted operations; and
o an increase of $0.8 million in field operating costs, primarily from a
$0.4 million increase in payroll and benefits, a $0.3 million increase
in repair costs, and a $0.1 million increase in insurance costs. The
increased payroll-related costs and fuel costs can be attributed to an
approximate 12 percent increase in the miles driven in our trucks. The
increase in repair costs is attributable primarily to repairs at truck
unloading stations. The increased insurance costs reflect a
combination of changes in the insurance market and the Partnership's
loss history.
As discussed previously, we changed our business model in 2002 to
substantially eliminate our bulk and exchange activity due to the relatively low
margins and high credit requirements for these transactions. Additionally, we
reviewed our wellhead purchase contracts to determine whether margins under
those contracts would support higher credit costs. In some cases, contracts were
cancelled. These volume reductions were the primary reasons gathering and
marketing volumes decreased by 72%.
Pipeline gross margin increased $4.0 million or 121% to $7.3 million
for the year ended December 31, 2002, as compared to $3.3 million for the year
ended December 31, 2001. The factors affecting pipeline gross margin were:
26
o an increase in revenues from sales of pipeline loss allowance barrels
of $2.3 million primarily as a result of revising pipeline tariffs to
increase the amount of the pipeline loss allowance imposed on
shippers, and the recognition of pipeline loss allowance volumes,
measurement gains net of measurement losses, and crude quality
deductions as inventory;
o an increase of 43 percent in the average tariff on shipments resulting
in an increase in revenue of $5.1 million;
o a decrease in throughput of 10 percent between the two years,
resulting in a revenue decrease of $1.4 million; and
o an increase in pipeline operating costs of $2.0 million in 2002
primarily due to greater expenditures for personnel and benefits, for
maintenance of right-of-ways including clearing of tree canopies and
costs associated with residential and commercial development around
our pipelines, for testing under the pipeline integrity management
regulations, for tank and station maintenance projects, for safety,
training and related projects, for liability and property damage
insurance, and for other operating costs, offset by reduced power
costs and lower costs for remote monitoring and control. Personnel and
benefits costs increased $0.3 million primarily as a result of
additions to the operations staff in Mississippi and costs associated
with work vehicles for the new staff added $0.1 million. Costs
associated with maintenance of right of ways and testing under
pipeline integrity regulations increased a combined $0.3 million. Tank
and station maintenance expenses increased $0.2 million. In 2002, we
increased safety training for our pipeline operations personnel at a
cost of $0.2 million. Additionally we undertook a project to add
Global Positioning Satellite information to our pipeline maps as
required pursuant to pipeline safety regulations. Expenses incurred on
this project in 2002 totaled $0.5 million. Insurance costs increased
by $0.4 million due to the combination of insurance market conditions
and our loss history. Other operating costs, including corrosion
control and tank rentals, increased by $0.5 million. Power costs were
lower by $0.2 million due to electricity deregulation in Texas. Our
remote monitoring and control costs were lower by $0.3 million as we
completed the transition in early 2002 from a more expensive service.
General and administrative expenses. General and administrative
expenses decreased $3.4 million in 2002 from the 2001 level. Changes in
personnel costs primarily due to the elimination of bulk and exchange activities
reduced generaland administrative expenses $2.3 million, and charges from our
bonus program were $0.8 million less in 2002. The remaining decrease of $0.3
million is attributable to decreases in expenses for legal, tax and other
professional services, offset by small increases in administrative insurance
costs and contract labor costs.
Depreciation and amortization. Depreciation and amortization expense
decreased $1.7 million in 2002 from the 2001 level. As a result of the
impairment of the pipeline assets in 2001, the value to be depreciated was
reduced.
Other operating charge. In 2002, we reached an agreement in principle
with the federal and state regulatory authorities regarding the fines we would
pay related to the spill that occurred in December 1999 in Mississippi. The cost
to us under the agreement is expected to be $3.0 million. In the fourth quarter
of 2001 we accrued $1.5 million for this potential fine and in the third quarter
of 2002 another $1.5 million was accrued.
Interest income (expense), net. In 2002, the Partnership had an
increase in its net interest expense of $0.5 million. In 2001, the Partnership
paid commitment fees on the unused portion of its $25 million facility with BNP
Paribas. In the 2002 period, the Partnership paid commitment fees on the unused
portion of the Credit Agreement with Citicorp. From January 1, 2002, until May
3, 2002, that facility maximum was $130 million. At May 3, 2002, the Credit
Agreement was reduced to a maximum of $80 million. The larger amount of the
credit facility resulted in substantially higher commitment fees in 2002.
Change in fair value of derivatives. As a result of the significant
reduction in our bulk and exchange activities at December 31, 2001, and a review
of contracts existing at December 31, 2002, we determined that substantially all
of our contracts do not meet the requirement for treatment as derivative
contracts under SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" (as amended and interpreted). The contracts were designated as
normal purchases and sales under the provisions for that treatment in SFAS No.
133. As a result, the fair value of the Partnership's net asset for derivatives
decreased by $2.1 million for the nine months ended September 30, 2002.
27
At December 31, 2002, the only contracts qualifying as a derivative
under SFAS No. 133 were a cash flow hedge of inventory. The change in the fair
value of these contracts at December 31, 2002 was a loss of $39,000, which is
reflected as a reduction of consolidated comprehensive income. The consolidated
balance sheet includes $39,000 in other current liabilities as a result of
recording the fair value of derivatives.
The fair value of our derivative contracts at December 31, 2002, was
determined using the sources for fair value as shown in the table below (in
thousands).
Fair Value of Contracts at Period-End
Maturity Maturity Maturity in
less than 3-6 Excess of Total
Source of Fair Value 3 Months Months 6 Months Fair Value
-------------------- -------- ------ -------- ----------
Prices actively quoted................. $ 39 $ - $ - $ 39
Prices provided by other external sources
- - - -
Prices based on models and other
valuation methods.................... - - - -
--------- ------ -------- ----------
Total.................................. $ 39 $ - $ - $ 39
========= ====== ======== ==========
Net gain on disposal of surplus assets. In 2002, we disposed of our
seats on the NYMEX for $1.7 million, resulting in a gain of $0.5 million. The
changes we made in our business model to reduce our bulk and exchange activities
eliminated our reasons for owning the NYMEX seats. Additionally, in 2002, we
sold surplus land and a building and surplus used vehicles resulting in
additional cumulative net gains of $0.2 million. In 2000, we made the decision
to lease our tractor/trailer fleet from Ryder Transportation Services. The
majority of the existing fleet was sold in 2000 and 2001. Cash proceeds of $0.4
million and a gain of $0.1 million in 2001 were realized in 2001 from this sale.
Year Ended December 31, 2001 Compared with Year Ended December 31, 2000
Gross margin. Gathering and marketing gross margins increased $2.1
million or 15% to $16.5 million for the year ended December 31, 2001, as
compared to $14.4 million for the year ended December 31, 2000.
The factors affecting gross margin were:
o a 23 percent increase in the average difference between the price of
crude oil at the point of purchase and the price of crude oil at the
point of sale, which increased gross margin by $6.3 million;
o a decrease of 11% percent in wellhead, bulk and exchange purchase
volumes between 2000 and 2001, resulting in a decrease in gross margin
of $3.3 million;
o a decrease of $0.5 million in credit costs primarily due to a 15
percent decrease in the average absolute price level of crude oil and
the decrease in purchase volumes; and
o an increase of $2.0 million in field operating costs, primarily from a
$2.2 million increase in rental costs due to the replacement of the
tractor/trailer fleet with a leased fleet in the fourth quarter of
2000, a $0.2 million increase in payroll and benefits, and a $0.1
million increase in insurance costs, offset by $0.5 million decrease
in repair costs. The increased payroll-related costs and fuel costs
can be attributed to an approximate 4% increase in the number of
barrels transported by the Partnership in trucks. The increased
insurance costs reflect a combination of changes in the insurance
market and the Partnership's loss history. The decline in repair costs
is attributable to the change to the use of leased vehicles under a
full-service maintenance lease.
In addition, gross margin in 2000 included an unrealized loss on
written option contracts of $0.6 million.
In the latter half of 2001, Genesis began making changes to its
business operations to prepare for the change from the $300 million Guaranty
Facility with Salomon to a smaller letter of credit facility. These changes
resulted in a substantial decrease in the Partnership's bulk and exchange
activity due to the relatively low margins and high credit requirements on these
transactions. Additionally, the Partnership began reviewing its wellhead
purchase
28
contracts to determine whether margins under those contracts would support
higher credit costs. In some cases, contracts were cancelled. These volume
reductions were the primary reasons gathering and marketing volumes decreased by
11%. See "Outlook" below for additional discussion of these changes to business
operations.
Pipeline gross margin decreased $3.0 million or 48% to $3.3 million for
the year ended December 31, 2001, as compared to $6.3 million for the year ended
December 31, 2000. Pipeline revenues declined $0.4 million as a result of small
declines in throughput and average tariffs. Revenues from sales of pipeline loss
allowance barrels decreased $0.4 million as a result of lower crude prices.
Pipeline operating costs were $2.2 million higher in the 2001 period primarily
due to a $1.3 million increase in maintenance costs, a $0.3 million increase in
insurance costs, a $0.2 million increase in payroll and related benefits and a
$0.4 increase in general operating costs. The increased insurance costs reflect
the combination of changes in the insurance market and the Partnership's loss
history.
General and administrative expenses. General and administrative
expenses increased $0.7 million in 2001 from the 2000 level. In 2001, the
Partnership's costs for professional services and contract labor increased $0.7
million, primarily as a result of the proposed sale of the general partner and
related legal and consulting costs. See "Termination of Proposed General Partner
Sale" below. Also contributing to the increase in general and administrative
costs was a $0.4 million increase in salaries and benefits and $0.7 million of
severance costs incurred as a result of a reduction in personnel. The number of
personnel was reduced to reflect the reduced bulk purchases planned by the
Partnership, as well as the overall decline in operating income. Offsetting the
increases that total $1.8 million was a reduction in expenses of $1.1 million
related to the Restricted Unit Plan.
Depreciation and amortization. Depreciation and amortization expense
decreased $0.5 million in 2001 from the 2000 level. This decrease is primarily
attributable to the sale in the last quarter of 2000 of the Partnership's
tractor/trailer fleet, thereby reducing depreciation, combined with the
completion of depreciation on assets of the Partnership that had reached the end
of their depreciable lives.
Impairment of long-lived assets. As a result of declining revenues and
significant increases in costs for operations and maintenance combined with
regulatory changes requiring additional testing for pipeline integrity, the
Partnership determined that its estimated undiscounted future cash inflows from
the pipeline assets is less than the carrying value of those assets. As a
result, the Partnership wrote the assets down to their estimated fair value in
accordance with Statement of Financial Accounting Standard No. 121, "Accounting
for the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of"
(FAS 121). An impairment charge of $45.0 million was recorded, with $38.0
million recorded to accumulated depreciation of the pipeline assets and $7.0
million recorded to accumulated amortization of goodwill.
Other operating charge. In 2001, the Partnership recorded a charge of
$1.5 million related to environmental matters, including the Mississippi spill
that occurred in December 1999. In 2000, other operating charges included $1.4
million of costs related to the restructuring of the Partnership in December
2000. This $1.4 million of costs consisted primarily of legal and accounting
fees, financial advisor fees, proxy solicitation expenses and the costs to print
and mail a proxy statement to Common Unitholders.
Interest income (expense), net. In 2001, the Partnership had a decrease
in its net interest expense of $0.5 million. Interest expense decreased $0.6
million and interest income decreased $0.1 million. Average daily debt
outstanding declined by $6.8 million, resulting in the decrease in interest
expense. Interest income decreased primarily as a result of lower interest
rates.
Change in fair value of derivatives. The Partnership utilizes crude oil
futures contracts and other financial derivatives to reduce its exposure to
unfavorable changes in crude oil prices. On January 1, 2001, the Partnership
adopted the provisions of SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities", which established new accounting and reporting
guidelines for derivative instruments and hedging activities. SFAS No. 133
established accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset or liability
measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met.
Under SFAS No. 133, the Partnership marks to fair value all of its
derivative instruments at each period end with changes in fair value being
recorded as unrealized gains or losses. Such unrealized gains or losses will
change, based on prevailing market prices, at each balance sheet date prior to
the period in which the transaction actually occurs. In general, SFAS No. 133
requires that at the date of initial adoption, the difference between the fair
value
29
of derivative instruments and the previous carrying amount of those
derivatives be recorded in net income or other comprehensive income, as
appropriate, as the cumulative effect of a change in accounting principle.
On January 1, 2001, recognition of the Partnership's derivatives
resulted in a gain of $0.5 million, which was recognized in the consolidated
statement of operations as the cumulative effect of adopting SFAS No. 133.
Certain derivative contracts related to written option contracts had been
recorded on the balance sheet at fair value at December 31, 2000, so no
adjustment was necessary for those contracts upon adoption of SFAS No. 133.
Net gain on disposal of surplus assets. In 2000, management of the
General Partner made the decision to lease its tractor/trailer fleet from Ryder
Transportation Services. The majority of the existing fleet was sold, resulting
in cash proceeds of $0.4 million and a gain of $0.1 million in 2001 and proceeds
of $1.8 million and a net gain of $1.0 million in 2000. The Partnership sold
additional surplus assets, which resulted in proceeds of $0.1 million and a gain
of $0.1 million in 2000.
Other Matters
Crude Oil Contamination
The Partnership was named one of the defendants in a complaint filed on
January 11, 2001, in the 125th District Court of Harris County, Texas, cause No.
2001-01176. Pennzoil-Quaker State Company ("PQS") seeks property damages, loss
of use and business interruption suffered as a result of a fire and explosion
that occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on
January 18, 2000. PQS claims the fire and explosion was caused, in part, by
Genesis selling to PQS crude oil that was contaminated with organic chlorides.
We believe that the suit is without merit and intend to vigorously defend
ourselves in this matter. We believe that any potential liability will be
covered by insurance.
PQS is also a defendant in five suits brought by neighbors living in
the vicinity of the PQS Shreveport, Louisiana refinery in the First Judicial
District Court, Caddo Parish, Louisiana, cause nos. 455,647-A. 455,658-B,
455,655-A, 456,574-A, and 458,379-C. PQS has brought third party demand against
Genesis and others for indemnity with respect to the fire and explosion of
January 18, 2000. We believe that the demand against Genesis is without merit
and intend to vigorously defend ourselves in this matter. We believe that any
potential liability will substantially be covered by insurance.
Insurance
We maintain insurance of various types that we consider adequate to
cover our operations and properties. The insurance policies are subject to
deductibles that we consider reasonable. The policies do not cover every
potential risk associated with operating our assets, including the potential for
a loss of significant revenues. Consistent with the coverage available in the
industry, our policies provide limited pollution coverage, with broader coverage
for sudden and accidental pollution events. Additionally, as a result of the
events of September 11, the cost of insurance available to the industry has
risen significantly, and insurers have excluded or reduced coverage for losses
due to acts of terrorism and sabotage.
Since September 11, 2001, warnings have been issued by various agencies
of the United States Government to advise owners and operators of energy assets
that those assets may be a future target of terrorist organizations. Any future
terrorist attacks on our assets, or assets of our customers or competitors could
have a material adverse affect on our business.
We believe that we are adequately insured for public liability and
property damage to others as a result of our operations. However, no assurances
can be given that an event not fully insured or indemnified against will not
materially and adversely affect our operations and financial condition.
Additionally, no assurance can be given that we will be able to maintain
insurance in the future at rates that we consider reasonable.
New Accounting Pronouncements
SFAS 143
In June, 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." This statement requires entities to record the fair
value of a liability for legal obligations associated with the retirement
obligations of tangible long-lived assets in the period in which it is incurred.
When the liability is initially recorded, a corresponding increase in the
carrying amount of the related long-lived asset would be recorded. Over time,
30
accretion of the liability is recognized each period, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss on settlement The standard is effective for Genesis on
January 1, 2003.
With respect to our pipelines, federal regulations will require us to
purge the crude oil from our pipelines when the pipelines are retired. Our right
of way agreements do not require us to remove pipe or otherwise perform
remediation upon taking the pipelines out of service. Many of our truck unload
stations are on leased sites that require that we remove our improvements upon
expiration of the lease term. For our pipelines, we expect that we will be
unable to reasonably estimate and record liabilities for the majority of our
obligations that fall under the provisions of this statement because we cannot
reasonably estimate when such obligations would be settled. For the truck unload
stations, the site leases have provisions such that the lease continues until
one of the parties gives notice that it wishes to end the lease. At this time we
cannot reasonably estimate when such notice would be given and when the
obligations to remove our improvements would be settled. We will record asset
retirement obligations in the period in which we determine the settlement dates.
SFAS 145
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt" and an amendment of that statement, SFAS No. 64,
"Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." SFAS No.
145 also rescinds SFAS No. 44, "Accounting for Intangible Assets of Motor
Carriers." SFAS No. 145 also amends SFAS No. 13, "Accounting for Leases," to
eliminate an inconsistency between the required accounting for sale-leaseback
transactions and the required accounting for certain lease modifications that
have economic effects that are similar to sale-leaseback transactions. SFAS No.
145 also amends other existing authoritative pronouncements to make various
technical corrections, clarify meanings, or describe their applicability under
changed conditions. The provisions related to the rescission of SFAS No. 4 shall
be applied in fiscal years beginning after May 15, 2002. The provisions related
to SFAS No. 13 shall be effective for transactions occurring after May 15, 2002.
All other provisions shall be effective for financial statements issued on or
after May 15, 2002, with early application encouraged. The adoption of this
statement did not have a material effect on our results of operations.
SFAS 146
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities," which addresses accounting for
restructuring and similar costs. SFAS No. 146 supersedes previous accounting
guidance, principally EITF Issue No. 94-3. We will adopt the provisions of SFAS
No. 146 for restructuring activities initiated after December 31, 2002. SFAS No.
146 requires that the liability for costs associated with an exit or disposal
activity be recognized when the liability is incurred. Under Issue No. 94-3, a
liability for an exit cost was recognized at the date of commitment to an exit
plan. SFAS No. 146 also establishes that the liability should initially be
measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the
timing of recognizing future restructuring costs as well as the amounts
recognized. The impact that SFAS No. 146 will have on our consolidated financial
statements will depend on the circumstances of any specific exit or disposal
activity.
Interpretation No. 45
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others". This interpretation of SFAS No. 5, 57 and
107, and rescission of FASB Interpretation No. 34 elaborates on the disclosures
to be made by a guarantor in its interim and annual financial statements about
its obligations under certain guarantees that it has issued. It also clarifies
that a guarantor is required to recognize, at the inception of a guarantee, a
liability for the fair value of the obligation undertaken in issuing the
guarantee. The initial recognition and initial measurement provisions of this
interpretation are applicable on a prospective basis to guarantees issued or
modified after December 31, 2002. The disclosure requirements in this
interpretation are effective for financial statements of interim or annual
periods after December 15, 2002.
31
SFAS 148
In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation-Transition and Disclosure," which provides alternative
methods of transition from a voluntary change to the fair value based method of
accounting for stock-based employee compensation. In addition, SFAS No. 148
amends the disclosure requirements of SFAS No. 123 in both annual and interim
financial statements. SFAS No. 148 is effective for financial statements for
fiscal years ending after December 15, 2002, and financial reports containing
condensed financial statements for interim periods beginning after December 15,
2002. At this time, there are no outstanding grants of Partnership units under
our Restricted Unit Plan (see Note 15). Therefore, we do not believe that the
adoption of this statement will have a material effect on either our financial
position, results of operations, cash flows or disclosure requirements.
Critical Accounting Policies and Estimates
The preparation of consolidated financial statements in conformity with
accounting principles generally accepted in the United States requires us 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. Although we believe these
estimates are reasonable, actual results could differ from those estimates. The
critical accounting policies and estimates that we have identified are discussed
below.
Depreciation, Amortization and Impairment of Long-Lived Assets
We calculate depreciation and amortization based on useful lives
estimated at the time the assets are placed in service. Events in future
periods, however, can cause us to change our estimates, thus impacting the
future calculation of depreciation and amortization.
When events or changes in circumstances indicate that the carrying
amount of an asset may not be recoverable, we compare the carrying value of the
fixed asset to the estimated undiscounted future cash flows from that asset.
Should the undiscounted future cash flows be less than the carrying value, we
record an impairment charge to reflect the asset at fair value. Fair value is
determined by discounting the future estimated cash flows. Determination as to
whether and how much an asset is impaired involves numerous management
estimates. Impairment reviews and calculations are based on assumptions that are
consistent with our business plans.
In 2001, we recorded an impairment charge to our pipeline assets and
goodwill totaling $45.1 million. Additionally we adjusted the remaining useful
lives of our pipeline assets to be consistent with the determination of the
period of time when we would expect future estimated cash flows from the assets.
Revenue and Expense Accruals
We routinely make accruals for both revenues and expenses due to the
timing of compiling billing information, receiving third party information and
reconciling our records with those of third parties. Additionally the provisions
of SFAS No. 133, require estimates to be made of the effectiveness of
derivatives as hedges and the fair value of derivatives. The actual results of
the transactions involving the derivative instruments will most likely differ
from the estimates. We base these estimates on information obtained from third
parties and our internal records. We believe our estimates for revenue and
expense items are reasonable, but there can be no assurance that actual amounts
will not vary from estimated amounts.
Liability and Contingency Accruals
We accrue reserves for contingent liabilities including, but not
limited to, environmental remediation and potential legal claims. When our
assessment indicates that it is probable that a liability has occurred and the
amount of the liability can be reasonably estimated, accruals are made. Our
estimates are based on all known facts at the time and our assessment of the
ultimate outcome, including consultation with external experts and counsel..
These estimates are revised as additional information is obtained or resolution
is achieved.
In 2001, we recorded an estimate of $1.5 million for the potential
liability for fines related to the crude oil spill in December 1999, from our
Mississippi pipeline system. Based on new information obtained in meetings with
regulators, this estimate was increased to a total of $3.0 million in 2002.
32
Item 7a. Quantitative and Qualitative Disclosures about Market Risk
Our primary price risk relates to the effect of crude oil price
fluctuations on our inventories and the fluctuations each month in grade and
location differentials and their affect on future contractual commitments. We
utilize NYMEX commodity based futures contracts and forward contracts to hedge
its exposure to these market price fluctuations. We believe the hedging program
has been effective in minimizing overall price risk. At December 31, 2002, we
used futures contracts exclusively in its hedging program with the latest
contract being settled in February 2003. Information about these contracts is
contained in the table set forth below.
Sell (Short) Buy (Long)
Contracts Contracts
Crude Oil Inventory ----------- ------------
Volume (1,000 bbls)............................. 128
Carrying value (in thousands)................... $ 3,612
Fair value (in thousands)....................... $ 4,163
Commodity Future Contracts:
Contract volumes (1,000 bbls)................... 96
Weighted average price per bbl..................$ 30.79
Contract value (in thousands)...................$ 432
Mark-to-market change (in thousands)............$ (39)
-----------
Market settlement value (in thousands)..........$ 393
===========
The table above presents notional amounts in barrels, the weighted average
contract price, total contract amount in U.S. dollars and the market settlement
value amount in U.S. dollars. The market settlement value was determined by
using the notional amount in barrels multiplied by the December 31, 2002 closing
prices of the applicable NYMEX futures contract adjusted for location and grade
differentials, as necessary.
Item 8. Financial Statements and Supplementary Data
The information required hereunder is included in this report as set forth
in the "Index to Consolidated Financial Statements" on page 43.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosures
On May 2, 2002, the Board of Directors and its audit committee dismissed
Arthur Andersen LLP as our independent public accountants and engaged Deloitte &
Touche LLP to serve as our independent auditors for the fiscal year ending
December 31, 2002.
Arthur Andersen's report on our consolidated financial statements for the
fiscal years ended December 31, 2001 and December 31, 2000, did not contain any
adverse opinion or disclaimer of opinion, nor were they qualified or modified as
to uncertainty or audit scope. In addition, there were no modifications as to
accounting principles except that the most recent audit report of Andersen
contained an explanatory paragraph with respect to the change in the method of
accounting for derivative instruments effective January 1, 2001, as required by
the Financial Accounting Standards Board.
During the fiscal years ended December 31, 2001 and December 31, 2000, and
through the date of the Board of Director's decision, there were no
disagreements with Arthur Andersen on any matter of accounting principle or
practice, financial statement disclosure, or auditing scope or procedure which,
if not resolved to Arthur Andersen's satisfaction, would have caused them to
make reference to the subject matter in connection with their reports on our
consolidated financial statements for such years; and there were no reportable
events, as described in Item 304(a)(1)(v) of Regulation S-K.
During the fiscal years ended December 31, 2001 and December 31, 2000, and
through the date of the Board of Director's decision, we did not consult
Deloitte & Touche LLP with respect to the application of accounting
33
principles to a specified transaction, with completed or proposed, or the type
of audit opinion that might be rendered on our consolidated financial
statements, or any other matters or reportable events described in Items
304(a)(2)(i) and (ii) or Regulation S-K.
Part III
Item 10. Directors and Executive Officers of the Registrant
We do 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 consists of eight persons.
Four of the directors, including the Chairman of the Board, are executives of
Denbury. Our Chief Exceutive Officer serves on the Board of Directors. The three
remaining directors are independent of Genesis and Denbury or any of its
affiliates.
The Board of Directors of the General Partner has established a committee
(the "Audit Committee") consisting of the independent directors. The committee
has the authority to review, at the request of the General Partner, specific
matters as to which the General Partner believes there may be a conflict of
interest in order to determine if the resolution of such conflict is fair and
reasonable to the Partnership. In addition, the committee reviews our external
financial reporting, recommends engagement of our independent accountants, and
reviews the adequacy of our 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 executive officers serve at the
discretion of the General Partner.
Name Age Position
- ------------------------------ --- ---------------------------------------
Gareth Roberts................ 50 Director and Chairman of the Board
Mark J. Gorman................ 48 Director, Chief Executive Officer
and President
Ronald T. Evans............... 40 Director
Herbert I. Goodman............ 80 Director
Susan O. Rheney............... 43 Director
Phil Rykhoek.................. 46 Director
J. Conley Stone............... 71 Director
Mark A. Worthey............... 45 Director
Ross A. Benavides............. 49 Chief Financial Officer, General Counsel
and Secretary
Kerry W. Mazoch............... 56 Vice President, Crude Oil Acquisitions
Karen N. Pape................. 45 Vice President and Controller
Gareth Roberts has served as a Director and Chairman of the Board of
the General Partner since May 2002. Mr. Roberts is President, Chief Executive
Officer and a director of Denbury Resources Inc. and has served in those
capacities since 1992. Mr. Roberts also serves on the board of directors of
Belden & Blake Corporation.
Mark J. Gorman has served as a Director of the General Partner since
December 1996 and as President and Chief Executive Officer since October 1999.
From December 1996 to October 1999 he served as Executive Vice President and as
Chief Operating Officer from October 1997 to October 1999. He was President of
Howell Crude Oil Company, a wholly-owned subsidiary of Howell Corporation, from
September 1992 to December 1996.
Ronald T. Evans has served as a director of the General Partner since
May 2002. Mr. Evans is Vice President of Reservoir Engineering of Denbury and
has served in that capacity since September 1999. Before joining Denbury, Mr.
Evans was employed in a similar capacity with Matador Petroleum Corporation for
three years and employed by Enserch Exploration, Inc. for twelve years in
various positions.
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. During 2001, he served as
the Chief Executive Officer of PEPEX.NET, LLC, which provides electronic trading
solutions to the international oil industry. From 1988 until 1996 he was
Chairman and Chief Executive Officer of Applied Trading Systems, Inc., a trading
and consulting business.
34
Susan O. Rheney became a Director of the General Partner in March 2002.
Ms. Rheney is a private investor and formerly was a principal of The Sterling
Group, L.P., a private financial and investment organization from 1992 to 2000.
Ms. Rheney is a director of Texas Petrochemical Holdings, Inc., where she serves
on the audit and finance committees, American Plumbing and Mechanical, Inc.,
where she serves on the audit and compensation committees and Mail-Well, Inc.
Phil Rykhoek has served as a director of the General Partner since May
2002. Mr. Rykhoek is Chief Financial Officer, Vice President, Secretary and
Treasurer of Denbury, and has served in those capacities since 1995.
J. Conley Stone was elected to the Board of Directors of the General
Partner in January 1997. From 1987 to his retirement in 1995, he served as
President, Chief Executive Officer, Chief Operating Officer and Director of
Plantation Pipe Line Company, a common carrier liquid petroleum products
pipeline transporter.
Mark A. Worthey has served as a director of the General Partner since
May 2002. Mr. Worthey is Vice President, Operations for Denbury and has been
with Denbury since September 1992.
Ross A. Benavides has served as Chief Financial Officer of the General
Partner since October 1998. He has served as General Counsel and Secretary since
December 1999. He served as Tax Counsel for Lyondell Petrochemical Company
("Lyondell") from May 1997 to October 1998. Prior to joining Lyondell, he was
Vice President of Basis Petroleum 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.
Karen N. Pape was named Vice President and Controller of the General
Partner effective in March 2002. Ms. Pape has served as Controller and as
Director of Finance and Administration of the General Partner since December
1996. From 1990 to 1996, she was Vice President and Controller of Howell
Corporation.
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 was required for those persons, we believe that during 2002 its
officers and directors complied with all applicable filing requirements in a
timely manner.
The three independent directors receive an annual fee of $30,000. The
Audit Committee Chairman receives an annual fee of $4,000 and all members of the
Audit Committee receive $1,500 for attendance at committee meetings. Beginning
in 2003, Denbury will receive $120,000 from the Partnership for providing four
of its executives as directors. Mr. Gorman does not receive a fee for his
service as a director.
Item 11. Executive Compensation
Under the terms of the Partnership Agreement, we are 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 2002, 2001, and 2000 to the Chief
Executive Officer and each of our three other executive officers (the "Named
Officers").
35
Summary Compensation Table
Long-Term
Annual Compensation Compensation
Awards
Other Annual Restricted All Other
Salary Bonus Compensation Stock Awards Compensation
Name and Principal Position Year $ $ $ (1) $ $
- ------------------------------- ---- --------- ------- ------------ ------------ -----------
Mark J. Gorman 2002 270,000 5,193 - - 11,500 (2)
Chief Executive Officer 2001 270,000 56,814 - - 10,200 (3)
and President 2000 270,000 50,000 - - 10,200 (3)
Ross A. Benavides 2002 180,000 3,462 - - 11,500 (2)
Chief Financial Officer, 2001 175,000 54,785 - - 10,200 (3)
General Counsel and 2000 150,000 50,000 - - 9,173 (4)
Secretary
Kerry W. Mazoch 2002 170,000 3,270 - - 11,478 (5)
Vice President, Crude 2001 169,000 30,720 - - 10,200 (3)
Oil Acquisitions 2000 166,000 30,000 - - 10,080 (6)
Karen N. Pape 2002 136,000 2,616 - - 10,118 (7)
Vice President and
Controller
<FN>
(1) 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.
(2) Includes $5,500 of Company-matching contributions to a defined
contribution plan and $6,000 of profit-sharing contributions to a
defined contribution plan.
(3) Includes $5,100 of Company-matching contributions to a defined
contribution plan and $5,100 of profit-sharing contributions to a
defined contribution plan.
(4) Includes $4,587 of Company-matching contributions to a defined
contribution plan and $4,586 of profit-sharing contributions to a
defined contribution plan.
(5) Includes $5,500 of Company-matching contributions to a defined
contribution plan and $5,978 of profit-sharing contributions to a
defined contribution plan.
(6) Includes $4,980 of Company matching contributions to a defined
contribution plan and $5,100 of profit-sharing contributions to a
defined contribution plan.
(7) Includes $5,059 of Company-matching contributions to a defined
contribution plan and $5,059 of profit-sharing contributions to a
defined contribution plan.
</FN>
Employment and Severance Agreements
The Partnership has severance agreements with Mr. Gorman, Mr.
Benavides, Mr. Mazoch and Ms. Pape that expire May 14, 2003.
The severance agreements with Mr. Gorman, Mr. Benavides, Mr. Mazoch and
Ms. Pape provide that in the event of a Changed Circumstance (as defined in the
severance agreement) or a Changed Circumstance within one year of a Change in
Control (as defined as a sale of substantially all of the Partnership's assets
or a change in the ownership of fifty percent or more of the General Partner),
the officer shall be entitled to: (i) a lump sum payment of one year of annual
salary, (ii) immediate vesting of any unvested awards under the Restricted Unit
Plan and (iii) payment of any incentive compensation payable to the executive in
accordance with the Incentive Plan.
36
Restricted Unit Plan
In January 1997, the General Partner adopted a restricted unit plan for
key employees of the General Partner that provided for the award of rights to
receive Common Units under certain restrictions including meeting thresholds
tied to Available Cash and Adjusted Operating Surplus. In January 1998, the
restricted unit plan was amended and restated, and the thresholds tied to
Available Cash and Adjusted Operating Surplus were eliminated. The discussion
that follows is based on the terms of the Amended and Restated Restricted Unit
Plan (the "Restricted Unit Plan"). Initially, rights to receive 291,000 Common
Units are available under the Restricted Unit Plan. From these Units, rights to
receive 261,000 Common Units (the "Restricted Units") were allocated to
approximately 34 individuals, subject to the vesting conditions described below
and subject to other customary terms and conditions.
One-third of the Restricted Units allocated to each individual vested
annually beginning in December 1998. The remaining rights to receive 30,000
Common Units initially available under the Restricted Unit Plan may be allocated
or issued in the future to key employees on such terms and conditions (including
vesting conditions) as the Compensation Committee of the General Partner
("Compensation Committee") shall determine.
Upon "vesting" in accordance with the terms and conditions of the
Restricted Unit Plan, Common Units allocated to a plan participant will be
issued to such participant. Units issued to participants may be newly issued
Units acquired by the General Partner from the Partnership at then prevailing
market prices or may be acquired by the General Partner in the open market. In
either case, the associated expense will be borne by the Partnership. Until
Common Units have vested and have been issued to a participant, such participant
shall not be entitled to any distributions or allocations of income or loss and
shall not have any voting or other rights in respect of such Common Units. No
consideration will be payable by the plan participants upon vesting and issuance
of the Common Units. The plan participant cannot sell the Common Units until one
year after the date of vesting.
Termination without cause in violation of a written employment
agreement, or a Significant Event as defined in the Restricted Unit Plan, will
result in immediate vesting of all non-vested units and conversion to Common
Units without any restrictions.
Bonus Plan
In February 2001, the Compensation Committee of the Board of Directors
of the General Partner approved a Bonus Plan (the "Bonus Plan") for all
employees of the General Partner. The Bonus Plan is designed to enhance the
financial performance of the Partnership by rewarding employees for achieving
financial performance objectives. The Bonus Plan will be administered by the
Compensation Committee. Under this plan, amounts will be allocated for the
payment of bonuses to employees each time GCOLP earns $1.5 million of Available
Cash. The amount allocated to the bonus pool increases for each $1.5 million
earned, such that a bonus pool of $1.2 million will exist if the Partnership
earns $9.0 million of Available Cash. Bonuses will be paid to employees as each
$1.5 million increment of Available Cash is earned, but only if distributions
are made to the Common Unitholders. Payments under the Bonus Plan will be at the
discretion of the Compensation Committee, and the General Partner can amend or
change the Bonus Plan at any time.
In 2002, we paid no regular quarterly distributions to our Common
Unitholders, so no bonuses accrued under the Bonus Plan. The Compensation
Committee chose, however, to pay a bonus to all employees equivalent to one week
of pay.
Item 12. Security Ownership of Certain Beneficial Owners and Management
We know of no one who beneficially owns in excess of five percent of the
Common Units of the Partnership. As set forth below, certain beneficial owners
own interests in the General Partner of the Partnership as of February 28, 2003.
37
Amount and Nature
Name and Address of Beneficial Ownership Percent
Title of Class of Beneficial Owner as of January 1, 2002 of Class
- ---------------------------------------- ------------------------- ----------------------------- ----------------
General Partner Interest Genesis Energy, Inc. 1 (1) 100.00
500 Dallas, Suite 2500
Houston, TX 77002
General Partner Interest Denbury Resources Inc. 1 (1) 100.00
5100 Tennyson Parkway.
Plano, TX 75024
---------------------
<FN>
(1) Denbury owns Genesis Energy, Inc. 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, 2003,
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. This information is based on data furnished by
the persons named.
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. Gareth Roberts - - *
Common Unit Mark J. Gorman 25,525 - *
Ronald T. Evans - 1,000 *
Herbert I. Goodman 2,000 - *
Susan O. Rheney - 700 *
Phil Rykhoek 4,000 - *
J. Conley Stone 1,000 - *
Mark A. Worthey - - *
Ross A. Benavides 9,283 - *
Kerry W. Mazoch 8,085 584 *
Karen N. Pape 3,386 - *
All directors and
executive officers as
a group (11 in number) 53,279 2,284 *
---------------------
* Less than 1%
The above table includes shares owned by certain members of the families of
the directors or executive officers, including shares in which pecuniary
interest may be disclaimed.
Item 13. Certain Relationships and Related Transactions
Through its control of the General Partner, Denbury has the ability to
control the management of the Partnership and GCOLP. Genesis enters into
transactions with Denbury and the General Partner in the ordinary course of its
operations. During 2002, these transactions included:
o Purchases of crude oil from Denbury totaling $26.4 million.
o Provision of personnel to manage and operate the assets and operations
of Genesis by the General Partner. Genesis reimbursed the General
Partner for all direct and indirect costs of these services in the
amount of $17.3 million.
Item 14. Controls and Procedures
We have evaluated the effectiveness of the design and operation of our
disclosure controls and procedures as of a date within 90 days prior to the
filing date of this annual report on Form 10-K (the "Evaluation Date"). Such
38
evaluation was conducted under the supervision and with the
participation of our Chief Executive Officer (CEO) and Chief Financial Officer
(CFO). Based on such evaluation, the CEO and CFO concluded that, as of the
Evaluation Date, Genesis' disclosure controls and procedures are effective in
alerting them on a timely basis to material information relating to Genesis
(including its consolidated subsidiaries) required to be included in Genesis'
periodic filing under the Exchange Act.
Since the Evaluation Date, there have not been any significant changes in
our internal controls or in other factors that could significantly affect such
controls.
Item 15. 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 43.
(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 Third Amended and Restated Agreement of Limited Partnership of Genesis
(incorporated by reference to Exhibit 4.1 of Form 8-K dated July 31,
2002)
3.3 Certificate of Limited Partnership of Genesis Crude Oil, L.P. (the
"Operating Partnership") (incorporated by reference to Exhibit 3.3 to
Form 10-K for the year ended December 31, 1996)
3.4 Third Amended and Restated Agreement of Limited Partnership of the
Operating Partnership (incorporated by reference to Exhibit 4.1 to
Form 8-K dated July 31, 2002)
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. (incorporated by
reference to Exhibit 10.1 to Form 10-K for the year ended December 31,
1996)
10.2 First Amendment to Purchase & Sale and Contribution & Conveyance
Agreement (incorporated by reference to Exhibit 10.2 to Form 10-K for
the year ended December 31, 1996)
10.3 Severance Agreement between Genesis Energy, L.L.C. and Mark J. Gorman
(incorporated by reference to Exhibit 10.5 of Form 10-K for the year
ended December 31, 2001)
10.4 Severance Agreement between Genesis Energy, L.L.C. and Ross A.
Benavides (incorporated by reference to Exhibit 10.6 of Form 10-K for
the year ended December 31, 2001)
10.5 Severance Agreement between Genesis Energy, L.L.C. and Kerry W. Mazoch
(incorporated by reference to Exhibit 10.7 of Form 10-K for the year
ended December 31, 2001)
10.6 Severance Agreement between Genesis Energy, L.L.C. and Karen N. Pape
(incorporated by reference to Exhibit 10.8 of Form 10-K for the year
ended December 31, 2001)
10.7 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)
10.8 Amended and Restated Restricted Unit Plan (incorporated by reference
to Exhibit 10.18 to Form 10-K for the year ended December 31, 1997)
10.9 Amended and Restated Credit Agreement dated as of May 3, 2002, between
Genesis Crude Oil, L.P., Genesis Energy, L.L.C., Genesis Energy, L.P.,
39
Citicorp North America, Inc., and Certain Financial Institutions
(incorporated by reference to Form 10-Q for the period ended March 31,
2002)
* 10.10 Credit Agreement dated as of March 14, 2003, between Genesis Crude
Oil, L.P., Genesis Energy, Inc. Genesis Energy, L.P., Fleet
National Bank and Certain Financial Institutions
11.1 Statement Regarding Computation of Per Share Earnings (See Note 3 to
the Consolidated Financial Statements - "Net Income Per Common Unit")
* 21.1 Subsidiaries of the Registrant
* 99.1 Certification by Chief Executive Officer Pursuant to 18 U.S.C.
Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
Act 0f 2002.
* 99.2 Certification by Chief Financial Officer Pursuant to 18 U.S.C.
Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
Act 0f 2002
--------------------
* Filed herewith
(b) Reports on Form 8-K
None.
40
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 19 th day of
March, 2003.
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
By: GENESIS ENERGY, INC., as
General Partner
By: /s/ Mark J. Gorman
--------------------------------
Mark J. Gorman
Chief Executive Officer
and President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons in the capacities and on
the dates indicated.
/s/ MARK J. GORMAN Director, Chief Executive Officer March 19, 2003
- ------------------------- and President
Mark J. Gorman (Principal Executive Officer)
/s/ ROSS A. BENAVIDES Chief Financial Officer, March 19, 2003
- ------------------------- General Counsel and Secretary
Ross A. Benavides (Principal Financial Officer)
/s/ KAREN N. PAPE Vice President and Controller March 19, 2003
- -------------------------
Karen N. Pape (Principal Accounting Officer)
/s/ GARETH ROBERTS Chairman of the Board and March 19, 2003
- ------------------------- Director
Gareth Roberts
/s/ RONALD T. EVANS Director March 19, 2003
- -------------------------
Ronald T. Evans
/s/ HERBERT I GOODMAN Director March 19, 2003
- -------------------------
Herbert I. Goodman
/s/ SUSAN O. RHENEY Director March 19, 2003
- -------------------------
Susan O. Rheney
/s/ PHILIP RYKHOEK Director March 19, 2003
- -------------------------
Philip Rykhoek
/s/ J. CONLEY STONE Director March 19, 2003
- -------------------------
J. Conley Stone
/s/ MARK A. WORTHEY Director March 19, 2003
- --------------------------
Mark A. Worthey
41
CERTIFICATIONS PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
CERTIFICATION
I, Mark J. Gorman, certify that:
1. I have reviewed this annual report on Form 10-K of Genesis Energy,
L.P.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report is
being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: March 19, 2003
/s/ Mark J. Gorman
-----------------------------------
Mark J. Gorman
President & Chief Executive Officer
42
CERTIFICATION
I, Ross A. Benavides, certify that:
1. I have reviewed this annual report on Form 10-K of Genesis Energy,
L.P.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report is
being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: March 19, 2003
/s/ Ross A. Benavides
----------------------------
Ross A. Benavides
Chief Financial Officer
43
GENESIS ENERGY, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Independent Auditors' Report........................................... 44
Consolidated Balance Sheets, December 31, 2002 and 2001................ 46
Consolidated Statements of Operations for the Years Ended
December 31, 2002, 2001 and 2000....................................... 47
Consolidated Statements of Comprehensive Income for the Years
Ended December 31, 2002, 2001 and 2000................................. 48
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2002, 2001 and 2000....................................... 49
Consolidated Statements of Partners' Capital for the Years
Ended December 31, 2002, 2001 and 2000................................. 50
Notes to Consolidated Financial Statements............................. 51
44
INDEPENDENT AUDITORS' REPORT
Genesis Energy, L.P.
Houston, Texas
We have audited the accompanying consolidated balance sheet of Genesis Energy,
L.P., (the "Partnership") as of December 31, 2002, and the related consolidated
statements of operations, comprehensive income, partners' capital and cash flows
for the year then ended. These financial statements are the responsibility of
the Partnership's management. Our responsibility is to express an opinion on
these financial statements based on our audit. The consolidated balance sheet of
the Partnership as of December 31, 2001 and the consolidated statements of
operations, partners' capital and cash flows for the two years in the period
ended December 31, 2001, were audited by other auditors who have ceased
operations. Those auditors expressed an unqualified opinion on those statements
dated March 8, 2002, and included an explanatory paragraph that described the
Partnership's change in method of accounting for derivative instruments as
discussed in Note 3 to those financial statements.
We conducted our audit in accordance with auditing standards generally accepted
in the United States of America. 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 audit provides a
reasonable basis for our opinion.
In our opinion, the December 31, 2002 consolidated financial statements referred
to above present fairly, in all material respects, the financial position of
Partnership at December 31, 2002, and the results of its operations and its cash
flows for the year then ended in conformity with accounting principles generally
accepted in the United States of America.
As discussed in Note 8 to the consolidated financial statements, in 2002, the
Partnership changed its method of accounting for goodwill. As discussed in Note
19 to the consolidated financial statements, in 2001, the Partnership changed
its method of accounting for derivative instruments.
As discussed above, the financial statements of Genesis Energy, L.P. as of
December 31, 2001, and for the years ended December 31, 2001 and 2000, were
audited by other auditors who have ceased operations. As described in Note 8,
these financial statements have been revised to include transitional disclosures
required by Statement of Financial Standards ("Statement") No. 142, Goodwill and
Other Intangible Assets, which was adopted by the Partnership as of January 1,
2002. Our audit procedures with respect to the disclosures in Note 8 with
respect to the year ended December 31, 2001, and the year ended December 31,
2000, included (a) agreeing the previously reported net income to the previously
issued financial statements and the adjustments to reported net income
representing amortization expense recognized in those periods related to
goodwill as a result of initially applying Statement No. 142 to the Company's
underlying records obtained from management, and (b) testing the mathematical
accuracy of the reconciliation of adjusted net income to reported net income,
and the related earnings-per-unit amounts. In our opinion, the disclosures for
the year ended December 31, 2001, and the year ended December 31, 2000, in Note
8 are appropriate. However, we were not engaged to audit, review or apply any
procedures to the 2001 or 2000 financial statements of the Partnership other
than with respect to such disclosures and, accordingly, we do not express an
opinion or any other form of assurance on the 2001 or 2000 financial statements
taken as a whole.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Houston, Texas
March 14, 2003
45
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, 2001 and 2000, and the
related consolidated statements of operations, cash flows and partners' capital
for each of the three years in the period ended December 31, 2001. These
financial statements are the responsibility of the Partnership's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Genesis Energy, L.P.
as of December 31, 2001 and 2000, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2001, in
conformity with accounting principles generally accepted in the United States.
As explained in Note 3 to the consolidated financial statements, effective
January 1, 2001, the Partnership changed its method of accounting for derivative
instruments.
ARTHUR ANDERSEN LLP
Houston, Texas
March 8, 2002
This is a copy of the audit report previously issued by Arthur Andersen LLP in
connection with our filing on Form 10-K for the year ended December 31, 2001.
This audit report has not been reissued by Arthur Andersen LLP in connection
with this filing on Form 10-K.
46
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31, December 31,
2002 2001
-------- ----------
ASSETS
CURRENT ASSETS
Cash and cash equivalents...................................... $ 1,071 $ 5,777
Accounts receivable -
Trade....................................................... 80,664 160,734
Related party............................................... - 1,064
Inventories.................................................... 4,952 3,737
Insurance receivable for pipeline spill costs.................. 3,425 1,570
Other.......................................................... 2,718 9,218
---------- ----------
Total current assets........................................ 92,830 182,100
FIXED ASSETS, at cost............................................. 118,418 115,336
Less: Accumulated depreciation................................ (73,958) (69,626)
----------- -----------
Net fixed assets............................................ 44,460 45,710
OTHER ASSETS, net of amortization................................. 247 2,303
---------- ----------
TOTAL ASSETS...................................................... $ 137,537 $ 230,113
========== ==========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable -
Trade....................................................... $ 82,640 $ 172,848
Related party............................................... 4,746 697
Accrued liabilities............................................ 8,834 10,144
---------- ----------
Total current liabilities................................... 96,220 183,689
LONG-TERM DEBT.................................................... 5,500 13,900
COMMITMENTS AND CONTINGENCIES (Note 20)
MINORITY INTERESTS................................................ 515 515
PARTNERS' CAPITAL
Common unitholders, 8,625 units issued and outstanding......... 34,626 31,361
General partner................................................ 715 648
Accumulated other comprehensive loss........................... (39) -
---------- ----------
Total partners' capital..................................... 35,302 32,009
---------- ----------
TOTAL LIABILITIES AND PARTNERS' CAPITAL........................... $ 137,537 $ 230,113
========== ==========
The accompanying notes are an integral part of these
consolidated financial statements.
47
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
Year Ended December 31,
-----------------------------------------------
2002 2001 2000
------------ ----------- ------------
REVENUES:
Gathering and marketing revenues
Unrelated parties................................. $ 888,559 $ 3,296,156 $ 4,274,519
Related parties................................... 3,036 29,847 35,095
Pipeline revenues.................................... 20,211 14,195 14,940
------------ ----------- ------------
Total revenues................................. 911,806 3,340,198 4,324,554
COST OF SALES:
Crude costs, unrelated parties....................... 832,860 3,257,137 4,150,888
Crude costs, related parties......................... 26,452 36,699 130,679
Field operating costs................................ 16,451 15,649 13,673
Pipeline operating costs............................. 12,928 10,897 8,652
------------ ----------- ------------
Total cost of sales............................... 888,691 3,320,382 4,303,892
------------ ----------- ------------
GROSS MARGIN............................................ 23,115 19,816 20,662
EXPENSES:
General and administrative........................... 8,289 11,691 10,942
Depreciation and amortization........................ 5,813 7,546 8,032
Impairment of long-lived assets...................... - 45,061 -
Other operating charges.............................. 1,500 1,500 1,387
------------ ----------- ------------
OPERATING INCOME (LOSS)................................. 7,513 (45,982) 301
OTHER INCOME (EXPENSE):
Interest income...................................... 69 166 259
Interest expense..................................... (1,104) (693) (1,269)
Change in fair value of derivatives.................. (2,094) 2,259 -
Net gain on disposal of surplus assets............... 708 167 1,148
------------ ----------- ------------
Income (loss) before minority interests and cumulative
effect of change in accounting principle.............. 5,092 (44,083) 439
Minority interests...................................... - (4) 258
------------ ----------- ------------
Income (loss) before cumulative effect of change in
accounting principle.................................. 5,092 (44,079) 181
Cumulative effect of change in accounting principle, net
of minority interest effect........................... - 467 -
------------ ----------- ------------
NET INCOME (LOSS)....................................... $ 5,092 $ (43,612) $ 181
============ =========== ============
NET INCOME PER COMMON UNIT- BASIC AND DILUTED:
Income (loss) before cumulative effect of change in
accounting principle............................ $ 0.58 $ (5.01) $ 0.02
Cumulative effect of change in accounting principle - 0.05 -
Net income (loss)................................. $ 0.58 $ (4.96) $ 0.02
============ ========== ============
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING..... 8,625 8,624 8,617
============ =========== ============
The accompanying notes are an integral part of these
consolidated financial statements.
48
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
Year Ended December 31,
---------------------------------------
2002 2001 2000
---------- --------- ---------
NET INCOME (LOSS)................................................... $ 5,092 $ (43,612) $ 181
OTHER COMPREHENSIVE INCOME (LOSS):
Change in fair value of derivatives used for hedging purposes.. (39) - -
---------- --------- ---------
COMPREHENSIVE INCOME (LOSS)......................................... $ 5,053 $(43,612) $ 181
========== ======== =========
The accompanying notes are an integral part of these
consolidated financial statements.
49
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Year Ended December 31,
---------------------------------------
2002 2001 2000
---------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)................................................. $ 5,092 $ (43,612) $ 181
Adjustments to reconcile net income to net cash provided by
operating activities -
Depreciation................................................... 4,965 6,228 6,714
Amortization of other assets................................... 848 1,318 1,318
Impairment of long-lived assets................................ - 45,061 -
Cumulative effect of change in accounting principle............ - (467) -
Change in fair value of derivatives............................ 2,055 (2,259) -
Gain on disposal of surplus assets............................. (708) (167) (1,148)
Minority interests equity in earnings (losses)................. - (4) 258
Restructuring costs............................................ - - 1,387
Other noncash charges.......................................... 1,500 1,605 1,801
Changes in components of working capital -
Accounts receivable......................................... 81,134 167,666 (80,905)
Inventories................................................. (1,051) (2,743) (590)
Other current assets........................................ 4,645 3,565 4,436
Accounts payable............................................ (86,159) (154,117) 74,316
Accrued liabilities......................................... (4,904) (5,230) (3,355)
---------- --------- ---------
Net cash provided by operating activities........................... 7,417 16,844 4,413
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment............................... (4,211) (1,882) (1,685)
Change in other assets............................................ 5 - 11
Proceeds from sales of assets..................................... 2,243 453 1,942
---------- --------- ---------
Net cash (used in) provided by investing activities................. (1,963) (1,429) 268
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank borrowings (repayments), net................................. (8,400) (8,100) 2,100
Distributions to common unitholders............................... (1,725) (6,898) (19,645)
Distributions to General Partner.................................. (35) (141) (352)
Distributions to minority interest owner.......................... - (1) -
Issuance of additional partnership interests...................... - - 13,702
Payment of restructuring costs.................................... - - (1,387)
Purchase of treasury units, net................................... - (6) (255)
---------- --------- ---------
Net cash used in financing activities............................... (10,160) (15,146) (5,837)
Net (decrease) increase in cash and cash equivalents................ (4,706) 269 (1,156)
Cash and cash equivalents at beginning of period.................... 5,777 5,508 6,664
---------- --------- ---------
Cash and cash equivalents at end of period.......................... $ 1,071 $ 5,777 $ 5,508
========== ========= =========
The accompanying notes are an integral part of these
consolidated financial statements.
50
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(In thousands)
Partners' Capital
Accumulated
Other
Common General Treasury Comprehensive
Unitholders Partner Units Income Total
----------- --------- -------- ------------- ---------
Partners' capital, December 31, 1999................ $ 52,574 $ 1,051 $ (40) $ - $ 53,585
Net income.......................................... 177 4 - - 181
Cash distributions.................................. (19,645) (352) - - (19,997)
Purchase of treasury units.......................... - - (255) - (255)
Issuance of treasury units to Restricted Unit Plan
participants...................................... - - 289 - 289
Excess of expense over cost of treasury units issued
for Restricted Unit Plan.......................... 901 - - - 901
Elimination of additional partnership interests..... 17,248 352 - - 17,600
Elimination of subordinated limited partner interests
in Operating Partnership.......................... 29,705 606 - - 30,311
----------- --------- -------- ------------- ---------
Partners' capital, December 31, 2000................ 80,960 1,661 (6) - 82,615
Net loss ........................................... (42,740) (872) - - (43,612)
Cash distributions.................................. (6,898) (141) - - (7,039)
Purchase of treasury units.......................... - - (6) - (6)
Issuance of treasury units to Restricted Unit Plan
participants...................................... - - 12 - 12
Excess of expense over cost of treasury units issued
for Restricted Unit Plan.......................... 39 - - - 39
----------- --------- -------- ------------- ---------
Partners' capital, December 31, 2001................ 31,361 648 - - 32,009
Net income.......................................... 4,990 102 - - 5,092
Cash distributions.................................. (1,725) (35) - - (1,760)
Change in fair value of derivatives used for
hedging purposes - - - (39) (39)
----------- --------- -------- ------------- ---------
Partners' capital, December 31, 2002................ $ 34,626 $ 715 $ - $ (39) $ 35,302
=========== ========= ======== ============= =========
The accompanying notes are an integral part of these
consolidated financial statements.
51
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Partnership Structure
Genesis Energy, L.P. ("GELP" or the "Partnership") was formed in
December 1996 as an initial public offering of 8.6 million Common Units,
representing limited partner interests in GELP of 98%. The General Partner of
GELP is Genesis Energy, Inc. (the "General Partner") and owns a 2% general
partner interest in GELP. The General Partner is owned by Denbury Gathering &
Marketing, Inc. a subsidiary of Denbury Resources Inc.
Genesis Crude Oil, L.P. is the operating limited partnership and is
owned 99.99% by GELP and 0.01% by the General Partner. Genesis Crude Oil, L.P.
has two subsidiary partnerships, Genesis Pipeline Texas, L.P. and Genesis
Pipeline USA, L.P. Genesis Crude Oil, L.P. and its subsidiary partnerships will
be referred to as GCOLP.
Previous Structure
Prior to a restructuring in December 2000, GELP owned 80.01% of GCOLP
and Salomon Smith Barney Holdings Inc. ("Salomon") and Howell Corporation
("Howell") owned an aggregate of 2.2 million subordinated limited partner units
in GCOLP ("Subordinated OLP Units"). As a result of the December 2000
restructuring, the Subordinated OLP Units were eliminated.
2. Basis of Presentation
The accompanying financial statements and related notes present the
consolidated financial position as of December 31, 2002 and 2001 for GELP and
its results of operations, cash flows and changes in partners' capital for the
years ended December 31, 2002, 2001 and 2000.
No provision for income taxes related to the operation of GELP is included
in the accompanying consolidated financial statements, as such income will be
taxable directly to the partners holding partnership interests in the
Partnership.
3. Summary of Significant Accounting Policies
Principles of Consolidation
The Partnership owns and operates its assets through GCOLP, an operating
limited partnership. The accompanying consolidated financial statements reflect
the combined accounts of the Partnership and the operating partnership after
elimination of intercompany transactions.
Nature of Operations
The principal business activities of the Partnership are the purchasing,
gathering, transporting and marketing of crude oil in the United States. The
Partnership gathers crude oil at the wellhead principally in the southern and
southwestern states. The Partnership also owns and operates three crude oil
pipelines. The pipelines are in Texas, Mississippi/Louisiana and
Florida/Alabama.
Use of Estimates
The preparation of consolidated financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities, if any, at the date of the consolidated financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
Cash and Cash Equivalents
The Partnership considers investments purchased with an original
maturity of three months or less to be cash equivalents. The Partnership has no
requirement for compensating balances or restrictions on cash.
52
Inventories
Crude oil inventories held for sale are valued at the lower of average
cost or market. Fuel inventories are carried at the lower of cost or market.
Fixed Assets
Property and equipment are carried at cost. Depreciation of property and
equipment is provided using the straight-line method over the respective
estimated useful lives of the assets. Asset lives are 12 to 20 years for
pipelines and related assets, 3 to 7 years for vehicles and transportation
equipment, and 3 to 10 years for buildings, office equipment, furniture and
fixtures and other equipment. In 2001, the Partnership recorded an impairment
charge related to its pipelines and related assets. See Note 11. The remaining
book value of these assets will be amortized over the useful lives of the assets
which, based on the estimated cash flows, is expected to be 7 to 15 years.
Maintenance and repair costs are charged to expense as incurred. Costs incurred
for major replacements and upgrades are capitalized and depreciated over the
remaining useful life of the asset. Certain volumes of crude oil are classified
in fixed assets, as they are necessary to ensure efficient and uninterrupted
operations of the gathering businesses. These crude oil volumes are carried at
their weighted average cost.
Other Assets
Other assets consist primarily of intangibles. Intangibles include a
covenant not to compete, which is being amortized over five years.
Minority Interests
Minority interests represent a 0.01% general partner interest in GCOLP
held by the General Partner. Prior to the December 2000 restructuring, minority
interests represented the Subordinated OLP Units held by Salomon and Howell
totaling 19.59% and a 0.4% interest in GCOLP owned directly by the General
Partner.
Environmental Liabilities
The Partnership provides for the estimated costs of environmental
contingencies when liabilities are likely to occur and reasonable estimates can
be made. Ongoing environmental compliance costs, including maintenance and
monitoring costs, are charged to expense as incurred.
Revenue Recognition
Gathering and marketing revenues are recognized when title to the crude
oil is transferred to the customer. Pipeline revenues are recognized upon
delivery of the barrels to the location designated by the shipper. Pipeline loss
allowance revenues are recognized to the extent that pipeline losses allowances
charged to shippers exceed pipeline measurement losses for the period based upon
the fair market value of the crude oil upon which the allowance is based.
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.
Derivatives
Effective January 1, 2001, the Partnership accounts for its derivative
transactions in accordance with Statement of Financial Accounting Standards No.
133 "Accounting for Derivative Instruments and Hedging Activities", as amended
and interpreted. Derivative transactions, which can include forward contracts
and futures positions on the NYMEX, are recorded on the balance sheet as assets
and liabilities based on the derivative's fair value. Changes in the fair value
of derivative contracts are recognized currently in earnings unless specific
hedge accounting criteria are met. If the derivatives meet those criteria, the
derivative's gains and losses offset related results on the hedged item in the
income statement. We must formally designate the derivative as a hedge and
document and assess the effectiveness of derivatives associated with
transactions that receive hedge accounting.
Derivative instruments that hedge our commodity price risks involve our
normal business activities, and have been designated as cash flow hedges under
SFAS No. 133, SFAS No. 133 designates derivatives that hedge
53
exposure to variable cash flows of forecasted transactions as cash flow
hedges and the effective portion of the derivative's gain or loss is initially
reported as a component of other comprehensive income (outside earnings) and
subsequently reclassified into earnings when the forecasted transaction affects
earnings. The ineffective portion of the gain or loss is reported in earnings
immediately. If a derivative transaction qualifies for and is designated as a
normal purchase and sale, it is exempted from the fair value accounting
requirements and is accounted for using traditional accrual accounting.
Net Income Per Common Unit
Basic net income per Common Unit is calculated on the weighted average
number of outstanding Common Units. The weighted average number of Common Units
outstanding was 8,625,000, 8,623,741 and 8,616,744 for the years ended December
31, 2002, 2001 and 2000, respectively. For this purpose, the 0.01% or 2% General
Partner interest, as applicable, is excluded from net income. Diluted net income
per Common Unit did not differ from basic net income per Common Unit for any
period presented.
4. New Accounting Pronouncements
In June, 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." This statement requires entities to record the fair
value of a liability for legal obligations associated with the retirement
obligations of tangible long-lived assets in the period in which it is incurred.
When the liability is initially recorded, a corresponding increase in the
carrying amount of the related long-lived asset would be recorded. Over time,
accretion of the liability is recognized each period, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss on settlement. The standard is effective for Genesis on
January 1, 2003.
With respect to our pipelines, federal regulations will require us to purge
the crude oil from our pipelines when the pipelines are retired. Our right of
way agreements do not require us to remove pipe or otherwise perform remediation
upon taking the pipelines out of service. Many of our truck unload stations are
on leased sites that require that we remove our improvements upon expiration of
the lease term. For our pipelines, we expect that we will be unable to
reasonably estimate and record liabilities for the majority of our obligations
that fall under the provisions of this statement because we cannot reasonably
estimate when such obligations would be settled. For the truck unload stations,
the site leases have provisions such that the lease continues until one of the
parties gives notice that it wishes to end the lease. At this time we cannot
reasonably estimate when such notice would be given and when the obligations to
remove our improvements would be settled. We will record asset retirement
obligations in the period in which we determine the settlement dates.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt" and an amendment of that statement, SFAS No. 64,
"Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." SFAS No.
145 also rescinds SFAS No. 44, "Accounting for Intangible Assets of Motor
Carriers." SFAS No. 145 also amends SFAS No. 13, "Accounting for Leases," to
eliminate an inconsistency between the required accounting for sale-leaseback
transactions and the required accounting for certain lease modifications that
have economic effects that are similar to sale-leaseback transactions. SFAS No.
145 also amends other existing authoritative pronouncements to make various
technical corrections, clarify meanings, or describe their applicability under
changed conditions. The provisions related to the rescission of SFAS No. 4 shall
be applied in fiscal years beginning after May 15, 2002. The provisions related
to SFAS No. 13 shall be effective for transactions occurring after May 15, 2002.
All other provisions shall be effective for financial statements issued on or
after May 15, 2002, with early application encouraged. The adoption of this
statement did not have a material effect on the Partnership's results of
operations.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities," which addresses accounting for
restructuring and similar costs. SFAS No. 146 supersedes previous accounting
guidance, principally EITF Issue No. 94-3. Genesis will adopt the provisions of
SFAS No. 146 for restructuring activities initiated after December 31, 2002.
SFAS No. 146 requires that the liability for costs associated with an exit or
disposal activity be recognized when the liability is incurred. Under Issue No.
94-3, a liability for an exit cost was recognized at the date of commitment to
an exit plan. SFAS No. 146 also establishes that the liability should initially
be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the
timing of recognizing future restructuring costs as well as the amounts
recognized. The impact that SFAS No. 146
54
will have on the consolidated financial statements will depend on the
circumstances of any specific exit or disposal activity.
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others". This interpretation of SFAS No. 5, 57 and
107, and rescission of FASB Interpretation No. 34 elaborates on the disclosures
to be made by a guarantor in its interim and annual financial statements about
its obligations under certain guarantees that it has issued. It also clarifies
that a guarantor is required to recognize, at the inception of a guarantee, a
liability for the fair value of the obligation undertaken in issuing the
guarantee. The initial recognition and initial measurement provisions of this
interpretation are applicable on a prospective basis to guarantees issued or
modified after December 31, 2002. The disclosure requirements in this
interpretation are effective for financial statements of interim or annual
periods after December 15, 2002.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation-Transition and Disclosure," which provides alternative methods of
transition from a voluntary change to the fair value based method of accounting
for stock-based employee compensation. In addition, SFAS No. 148 amends the
disclosure requirements of SFAS No. 123 in both annual and interim financial
statements. SFAS No. 148 is effective for financial statements for fiscal years
ending after December 15, 2002, and financial reports containing condensed
financial statements for interim periods beginning after December 15, 2002. At
this time, there are no outstanding grants of Partnership units under our
Restricted Unit Plan (see Note 15). Therefore, we do not believe that the
adoption of this statement will have a material effect on either our financial
position, results of operations, cash flows or disclosure requirements.
5. Business Segment and Customer Information
Based on its management approach, the Partnership believes that all of its
material operations revolve around the gathering, transportation and marketing
of crude oil and it currently reports its operations, both internally and
externally, as a single business segment. Marathon Ashland Petroleum LLC and
ExxonMobil Corporation accounted for 18.5% and 13.6% of total revenues in 2002,
respectively. In 2001, BP Amoco Corporation subsidiaries and Enron Corporation
subsidiaries accounted for 10.6% and 14.1% of total revenues, respectively.
Genesis received full payment for all sales to Enron Corporation subsidiaries.
In 2000, no customer accounted for more than 10% of the Partnership's revenues.
6. Inventories
Inventories consisted of the following (in thousands).
December 31,
2002 2001
------------ ------------
Crude oil inventories, at lower
of cost or market...................... $ 4,841 $ 3,662
Fuel and supplies inventories, at lower
of cost or market...................... 111 75
------------ ------------
Total inventories.................... $ 4,952 $ 3,737
============ ============
7. Fixed Assets
Fixed assets consisted of the following (in thousands).
December 31,
2002 2001
------------ ------------
Land and buildings....................... $ 3,492 $ 3,718
Pipelines and related assets............ 101,397 98,085
Vehicles and transportation equipment... 1,527 1,808
Office equipment, furniture and fixtures 3,138 2,809
Other .................................. 8,864 8,916
------------ ------------
118,418 115,336
Less - Accumulated depreciation.. (73,958) (69,626)
------------ ------------
Net fixed assets................. $ 44,460 $ 45,710
============ ============
55
Depreciation expense was $4,965,000, $6,228,000 and $6,714,000 and for the
years ended December 31, 2002, 2001 and 2000, respectively. In 2001, the
Partnership recorded an impairment charge related to its pipeline assets of
$38,049,000. See Note 11.
8. Other Assets
Other assets consisted of the following (in thousands).
December 31,
2002 2001
------------ ------------
Covenant not to compete................... $ 4,238 $ 4,238
NYMEX seats............................... - 1,203
Other..................................... 42 47
------------ ------------
4,280 5,488
Less - Accumulated amortization.... (4,033) (3,185)
------------- ------------
Net other assets............ $ 247 $ 2,303
============ ============
In 2001, the Partnership recorded an impairment charge related to goodwill
of $7,012,000, which reduced the net book value of goodwill to zero at December
31, 2001. See Note 11. .In accordance with SFAS No. 142, "Goodwill and Other
Intangible Assets," which we adopted January 1, 2002, we test other intangible
assets periodically to determine if impairment has occurred. An impairment loss
is recognized for intangibles if the carrying amount of an intangible asset is
not recoverable and its carrying amount exceeds its fair value. As of December
31, 2002, no impairment has occurred.
Amortization expense for goodwill was $470,000 for the years ended December
31, 2001 and 2000. Amortization expense for the covenant-not-to-compete was
$848,000 for the each of the years ended December 31, 2002, 2001 and 2000.
Accumulated amortization of the covenant-not-to-compete was $4,033,000 and
$3,185,000 at December 31, 2002 and 2001, respectively. The estimated aggregate
amortization expense for 2003 is expected to be $205,000, at which time the
covenant-not-to-compete will have expired.
Had SFAS No. 142 been in effect prior to January 1, 2002, reported net
income and net income per unit would have been as follows (in thousands, except
per unit amounts):
Year Ended December 31,
2002 2001 2000
----------- ----------- -----------
Reported net income............... $ 5,092 $ (43,612) $ 181
Goodwill amortization, after
minority interest effect........ $ - $ 470 $ 384
----------- ----------- -----------
Adjusted net income............... $ 5,092 $ (43,142) $ 565
=========== =========== ===========
Net income per unit-basic
and diluted:
Reported net income............... $ 0.58 $ (4.96) $ 0.02
Goodwill amortization............. - $ 0.05 $ 0.04
----------- ----------- -----------
Adjusted net income............... $ 0.58 $ (4.91) $ 0.06
=========== =========== ===========
In February 2002, the Partnership sold its NYMEX seats for a total of
$1,700,000.
9. Credit Resources
In 2001, Genesis had a $300 million Master Credit Support Agreement
("Guaranty Facility") with Salomon and a $25 million working capital facility
("WC Facility") with BNP Paribas.
Effective December 19, 2001, GCOLP entered into a two-year $130 million
Senior Secured Revolving Credit Facility ("Credit Agreement") with Citicorp
North America, Inc. ("Citicorp"). Citicorp and Salomon, the former owner of the
partnership's General Partner, are both wholly-owned subsidiaries of Citigroup
Inc. The Credit Agreement replaced the Guaranty Facility and the WC Facility.
In May 2002, the Partnership elected, under the terms of the Credit
Agreement, to amend the Credit Agreement to reduce the maximum facility amount
to $80 million. The Credit Agreement had a $25 million sublimit for
56
working capital loans. Any amount not being used for working capital loans was
available for letters of credit to support crude oil purchases.
During the first four months of 2002, Salomon provided guaranties to the
Partnership's counterparties under a transition arrangement between Salomon,
Citicorp and the Partnership. For crude oil purchases in December 2001 and April
2002, a maximum of $100 million in guaranties were available to be issued under
the Salomon guaranty facility. Beginning with May 2002, Citicorp provided
letters of credit to the Partnership's counterparties.
In March 2003, the Partnership replaced the Citicorp Credit Agreement with
a $65 million three-year credit facility with a group of banks with Fleet
National Bank as agent ("Fleet Agreement"). The Fleet Agreement also has a
sublimit for working capital loans in the amount of $25 million, with the
remainder of the facility available for letters of credit.
The key terms of the Fleet Agreement are as follows:
o Letter of credit fees are based on the Applicable Usage Level
("AUL") and will range from 2.00% to 3.00%. During the first six
months of the facility, the rate will be 2.50%. The AUL is a
function of the facility usage to the borrowing base on that day.
o The interest rate on working capital borrowings is also based on the
AUL and allows for loans based on the prime rate or the LIBOR rate
at our option. The interest rate on prime rate loans can range from
the prime rate plus 1.00% to the prime rate plus 2.00%. The interest
rate for LIBOR-based loans can range from the LIBOR rate plus 2.00%
to the LIBOR rate plus 3.00%. During the first six months of the
facility, the rate will be the Libor rate plus 2.50%.
o The Partnership will pay a commitment fee on the unused portion of
the $65 million commitment. This commitment fee is also based on the
AUL and will range from 0.375% to 0.50%. During the first six months
of the facility, the commitment fee will be 0.50%.
o The amount that the Partnership may have outstanding cumulatively in
working capital borrowings and letters of credit is subject to a
Borrowing Base calculation. The Borrowing Base (as defined in the
Fleet Credit Agreement) generally includes cash balances, net
accounts receivable and inventory, less deductions for certain
accounts payable, and is calculated monthly.
o Collateral under the Fleet Agreement consists of the Partnership's
accounts receivable, inventory, cash accounts, margin accounts and
property and equipment.
o The Fleet Agreement contains covenants requiring a Current Ratio (as
defined in the Fleet Agreement), a Leverage Ratio (as defined in the
Fleet Agreement), a Cash Flow Coverage Ratio (as defined in the
Fleet Agreement), a Funded Indebtedness to Capitalization Ratio (as
defined in the Fleet Agreement), Minimum EBITDA, and limitations on
distributions to Unitholders.
Under the Citicorp Credit Agreement, distributions to Unitholders and the
General Partner could only be made if the Borrowing Base exceeds the usage
(working capital borrowings plus outstanding letters of credit) under the
Citicorp Credit Agreement for every day of the quarter by at least $20 million.
Under the Fleet Agreement, this provision is changed to require that the
Borrowing Base exceed the usage under the Fleet Credit Facility by at least $10
million plus the distribution measured once each month. See additional
discussion below under "Distributions".
At December 31, 2002, the Partnership had $5.5 million outstanding under
the Citicorp Credit Agreement. Due to the revolving nature of loans under the
Citicorp Credit Agreement, additional borrowings and periodic repayments and
re-borrowings may be made until the maturity date of December 31, 2003. As a
result of the refinancing of the debt under the Fleet Agreement, this
outstanding balance is shown as long-term debt in the consolidated balance
sheet. At December 31, 2002, the Partnership had letters of credit outstanding
under the Citicorp Credit Agreement totaling $26.3 million, comprised of $13.8
million and $12.5 million for crude oil purchases related to December 2002 and
January 2003, respectively.
Credit Availability
As a result of the Partnership's decision to reduce the level of bulk
and exchange transactions, credit support in the form of letters of credit has
been less in 2002 than it was in 2001. However, any significant decrease in the
Partnership's financial strength, regardless of the reason for such decrease,
may increase the number of transactions
57
requiring letters of credit, which could restrict its gathering and
marketing activities due to the limitations of the Fleet Agreement and Borrowing
Base. This situation could in turn adversely affect its ability to maintain or
increase the level of its purchasing and marketing activities or otherwise
adversely affect its profitability and Available Cash.
Distributions
Generally, GCOLP will distribute 100% of its Available Cash within 45
days after the end of each quarter to Unitholders of record and to the General
Partner. Available Cash consists generally of all of the cash receipts less cash
disbursements of GCOLP adjusted for net changes to reserves. As a result of the
restructuring approved by Unitholders in December 2000, the target minimum
quarterly distribution ("MQD") for each quarter was reduced to $0.20 per unit.
The Partnership has not made a regular quarterly distribution since the fourth
quarter of 2001.
Under the Citicorp Agreement, distributions to Unitholders and the
General Partner could only be made if the Borrowing Base exceeded the usage
(working capital borrowings plus outstanding letters of credit) under the
Citicorp Agreement for every day of the quarter by at least $20 million plus the
distribution. Under the Fleet Agreement, this provision is changed to require
that the Borrowing Base exceed the usage under the Fleet Agreement by at least
$10 million plus the distribution measured once each month.
For the first and second quarters of 2002, the Partnership did not pay a
distribution as the excess of the Borrowing Base over the usage dropped below
the required level. During the third quarter of 2002, the Partnership met the
test and thus was not restricted from making a distribution under the Credit
Agreement. However, a distribution was not made for the third quarter of 2002
because of a reserve established fro future needs of the Partnership. These
reserves exceeded Available Cash for the third quarter of 2002. Similarly, the
Partnership did not make a distribution for the fourth quarter of 2002 as
reserves again exceeded Available Cash. Such future needs of the Partnership
include, but are not limited to, the fines that are being imposed in connection
with the crude oil spill that occurred on the Mississippi System in December
1999 and future expenditures that will be required for pipeline integrity
management programs required by federal regulations. Management of the
Partnership is still evaluating plans to restore the distribution. Any
distribution to restore the distribution will take into account the
Partnership's ability to sustain the distribution on an ongoing basis with cash
generated by the existing asset base, capital requirements needed to maintain
and optimize the performance of the asset base, and the Partnership's ability to
finance its existing capital requirements and accretive acquisitions. If
distributions are resumed, the distribution per common unit may be for less than
the MQD target of $0.20 per unit.
The Partnership Agreement authorizes the General Partner to cause GCOLP
to issue additional limited partner interests and other equity securities, the
proceeds from which could be used to provide additional funds for acquisitions
or other GCOLP needs.
10. Partnership Equity
Partnership equity in GELP consists of the general partner interest of 2%
and 8.6 million Common Units representing limited partner interests of 98%. The
Common Units were sold to the public in an initial public offering in December
1996. The general partner interest is held by the General Partner. The
Partnership is managed by the General Partner. The General Partner also holds a
0.01% general partner interest in GCOLP, which is reflected as a minority
interest in the consolidated balance sheet at December 31, 2002.
11. Impairment of Pipeline Assets
In the fourth quarter of 2001, as a result of declining revenues and rising
costs from its pipeline operations for operations and maintenance combined with
regulatory changes requiring additional testing for pipeline integrity, the
Partnership determined that the estimated undiscounted future cash flows did not
support the carrying value of its pipelines. Under Statement of Financial
Accounting Standard No. 121, "Accounting for the Impairment of Long-Lived Assets
and Long-Lived Assets to Be Disposed Of" (SFAS 121) (the relevant accounting
guidance at that time), the carrying value of the assets must be reduced to the
fair value of the assets. The estimated fair value of the pipelines was
determined by reducing the estimated undiscounted future cash flows plus salvage
value to its present value at December 31, 2001. Because the goodwill on the
consolidated balance sheet was generated from the acquisition of the pipeline
assets, the carrying value of the net goodwill was reduced to zero with the
remaining impairment allocated to the fixed assets. An impairment charge
totaling $45.1 million was recorded for the pipeline assets and goodwill.
58
12. Other Operating Charges
In each of the third quarter of 2002 and the fourth quarter of 2001, the
Partnership recorded a charge of $1.5 million, for a total of $3.0 million,
related to environmental matters including the Mississippi spill that occurred
in 1999. These charges are reflected as other operating charges on the
consolidated statement of operations for 2002 and 2001.
In connection with the restructuring of the Partnership in December 2000,
costs totaling $1.4 million were incurred primarily for legal and accounting
fees, financial advisor fees, proxy solicitation expenses and the costs to print
and mail proxy materials to Common Unitholders. These costs are reflected as
other operating charges in the consolidated statement of operations for 2000.
The cash needed to fund these expenses was provided from the final distribution
support obligation payment made by Salomon pursuant to the terms of the proxy
statement.
13. Transactions with Related Parties
Sales, purchases and other transactions with affiliated companies, except
the guarantee fees paid to Salomon, in the opinion of management, are conducted
under terms no more or less favorable than those conducted with unaffiliated
parties.
Sales and Purchases of Crude Oil
A summary of sales to and purchases from related parties of crude oil is
as follows (in thousands).
Year Ended December 31,
2002 2001 2000
----------- ----------- -----------
Purchases from Denbury............... $ 26,452
Sales to Salomon affiliates.......... $ 3,036 $ 29,847 $ 35,095
Purchases from Salomon and Howell
affiliates......................... $ - $ 36,699 $ 130,679
Denbury became a related party in May 2002. Purchases during the period
from May 14, 2002 to December 31, 2002 from Denbury were $26.5 million.
Purchases in 2002 from Denbury before it became an affiliate were $10.9 million.
Purchases from Denbury are secured by letters of credit.
The related party sales in all years were made to Phibro, Inc.,
("Phibro"), a subsidiary of Salomon. Purchases of $36.7 million and $121.1
million, respectively, were made in 2001 and 2000 from Phibro. These
transactions were bulk and exchange transactions. Purchases of wellhead
production were made from Howell in 2000 of $9.6 million.
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 $17,280,000, $18,089,000, and $16,946,000 for the years ended December 31,
2002, 2001 and 2000, respectively.
Credit Agreement
In December 2001, Citicorp began providing the Partnership with a
working capital and letter of credit facility. In January 1, 2002, until Mary
14, 2002, when Citicorp ceased to be a related party, the Partnership incurred
letter of credit fees, interest and commitment fees totaling $396,000 under the
Credit Agreement. In 2001, the Partnership paid Citicorp for interest and
commitment fees totaling $27,000 and $900,000 as a fee for providing the
facility. This facility fee is being amortized to earnings over the two-year
life of the Credit Agreement and is included in interest expense on the
consolidated statements of operations.
Guaranty Fees
In 2001 and 2000, Salomon provided a guaranty facility to the
Partnership and, from January 2002 to April 2002, Salomon provided guaranties
under a transition arrangement with Salomon, Citicorp and the Partnership. For
the years ended December 31, 2002, 2001 and 2000, the Partnership paid Salomon
$61,000, $1,250,000 and $1,712,000, respectively, for guarantee fees. The
guarantee fees are included as a component in cost of crude on the consolidated
statements of operations. These guarantee fees were less than the cost of a
letter of credit facility from a bank.
59
14. Supplemental Cash Flow Information
In 2000, two noncash transactions occurred as a result of the restructuring
of the Partnership. Additional Partnership Interests and minority interests
related to the Subordinated OLP Units were eliminated and resulted in an
increase in the capital accounts of the Common Unitholders and General Partner
of GELP.
Cash received by the Partnership for interest during the years ended
December 31, 2002, 2001 and 2000 was $68,000, $195,000, and $241,000,
respectively. Cash payments for interest were $537,000, $1,391,000, and
$1,370,000 during the years ended December 31, 2002, 2001 and 2000,
respectively.
15. Employee Benefit Plans
The Partnership does not directly employ any of the persons responsible for
managing or operating the Partnership. Employees of the General Partner provide
those services and are covered by various retirement and other benefit plans.
In order to encourage long-term savings and to provide additional funds for
retirement to its employees, the General Partner sponsors a profit-sharing and
retirement savings plan. Under this plan, the General Partner's matching
contribution is calculated as the lesser of 50% of each employee's annual pretax
contribution or 3% of each employee's total compensation. The General Partner
also made a profit-sharing contribution of 3% of each eligible employee's total
compensation. The expenses included in the consolidated statements of operations
for costs relating to this plan were $564,000, $603,000, and $570,000 for the
years ended December 31, 2002, 2001 and 2000, respectively.
The General Partner also provided certain health care and survivor benefits
for its active employees. In 2002, 2001 and 2000, these benefit programs were
self-insured. The General Partner plans to continue self-insuring these plans in
the future. The expenses included in the consolidated statements of operations
for these benefits were $1,360,000, $1,526,000, and $1,718,000 in 2002, 2001 and
2000, respectively.
Restricted Unit Plan
In January 1997, the General Partner adopted a restricted unit plan for
key employees of the General Partner that provided for the award of rights to
receive Common Units under certain restrictions, including meeting thresholds
tied to Available Cash and Adjusted Operating Surplus.
In January 1998, the restricted unit plan was amended and restated, and
the thresholds tied to Available Cash and Adjusted Operating Surplus were
eliminated. The discussion that follows is based on the terms of the Amended and
Restated Restricted Unit Plan (the "Restricted Unit Plan"). Initially, rights to
receive 291,000 Common Units are available under the Restricted Unit Plan. From
these Units, rights to receive 261,000 Common Units (the "Restricted Units")
were allocated to approximately 34 individuals, subject to the vesting
conditions described below and subject to other customary terms and conditions.
One-third of the Restricted Units allocated to each individual vested
annually beginning in December 1998. The remaining rights to receive 30,000
Common Units available under the Restricted Unit Plan may be allocated or issued
in the future to key employees on such terms and conditions (including vesting
conditions) as the Compensation Committee of the General Partner ("Compensation
Committee") shall determine.
Upon "vesting" in accordance with the terms and conditions of the
Restricted Unit Plan, Common Units allocated to a plan participant will be
issued to such participant. Units issued to participants may be newly issued
Units acquired by the General Partner from the Partnership at then prevailing
market prices or may be acquired by the General Partner in the open market. In
either case, the associated expense will be borne by the Partnership. Until
Common Units have vested and have been issued to a participant, such participant
shall not be entitled to any distributions or allocations of income or loss and
shall not have any voting or other rights in respect of such Common Units. No
consideration will be payable by the participants in the Restricted Unit Plan
upon vesting and issuance of the Common Units. Additionally, the participant
cannot sell the Common Units until one year after the date of vesting.
Termination without cause in violation of a written employment
agreement, or a Significant Event as defined in the Restricted Unit Plan, will
result in immediate vesting of all non-vested units and conversion to Common
Units without any restrictions.
60
In 2001 and 2000, the Partnership recorded expense of $55,000 and
$1,192,000, respectively, related to the Restricted Units.
Bonus Plan
In February 2001, the Compensation Committee of the Board of Directors
of the General Partner approved a Bonus Plan (the "Bonus Plan") for all
employees of the General Partner. The Bonus Plan is designed to enhance the
financial performance of the Partnership by rewarding all employees for
achieving financial performance objectives. The Bonus Plan will be administered
by the Compensation Committee. Under this plan, amounts will be allocated for
the payment of bonuses to employees each time GCOLP earns $1.5 million of
Available Cash. The amount allocated to the bonus pool increases for each $1.5
million earned, such that a bonus pool of $1.2 million will exist if the
Partnership earns $9.0 million of Available Cash. Bonuses will be paid to
employees as each $1.5 million increment of Available Cash is earned, but only
if distributions are made to the Common Unitholders. Payments under the Bonus
Plan will be at the discretion of the Compensation Committee, and the General
Partner will be able to amend or change the Bonus Plan at any time.
16. Sale of Tractor/Trailer Fleet
Management of the Partnership made the decision to sell its existing
tractor/trailer fleet and replace it with vehicles provided by Ryder
Transportation Services ("Ryder") under an operating lease. During 2000, the
Partnership sold 22 tractors and 68 trailers for a total of $1,802,000 and
recognized a gain of $1,037,000 on the sale of this equipment. The remaining 31
tractors were sold on January 8, 2001, for $400,000. The net book value of those
tractors, totaling $286,000, was reflected in other current assets at December
31, 2000. A gain of $114,000 on this sale was recorded in 2001.
17. Concentration and Credit Risk
The Partnership derives its revenues from customers primarily in the crude
oil industry. This industry concentration has the potential to impact the
Partnership's overall exposure to credit risk, either positively or negatively,
in that the Partnership's customers could be affected by similar changes in
economic, industry or other conditions. However, the Partnership believes that
the credit risk posed by this industry concentration is offset by the
creditworthiness of the Partnership's customer base. The Partnership's portfolio
of accounts receivable is comprised primarily of major international corporate
entities with stable payment experience. The credit risk related to contracts
which are traded on the NYMEX is limited due to the daily cash settlement
procedures and other NYMEX requirements.
The Partnership has established various procedures to manage its credit
exposure, including initial credit approvals, credit limits, collateral
requirements and rights of offset. Letters of credit, prepayments and guarantees
are also utilized to limit credit risk to ensure that management's established
credit criteria are met.
18. Fair Value of Financial Instruments
The carrying values of cash and cash equivalents, accounts receivable,
accounts payable and accrued liabilities in the Consolidated Balance Sheets
approximated fair value due to the short maturity of these instruments.
Additionally, the carrying value of the long-term debt approximated fair value
due to its floating rate of interest.
At December 31, 2002 and 2001, the Partnership had no option contracts
outstanding. At December 31, 2000, the carrying amount and estimated fair values
of option contracts used as hedges was $7.3 million.
Quoted market prices were used in determining the fair value of the option
contracts. If quoted prices were not available, fair values were 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.
19. Derivatives
The Partnership's market risk in the purchase and sale of its crude oil
contracts is the potential loss that can be caused by a change in the market
value of the asset or commitment. In order to hedge its exposure to such market
fluctuations, the Partnership enters into various financial contracts, including
futures, options and swaps. Normally, any contracts used to hedge market risk
are less than one year in duration.
61
The Partnership utilizes crude oil futures contracts and other financial
derivatives to reduce its exposure to unfavorable changes in crude oil prices.
On January 1, 2001, the Partnership adopted the provisions of SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities", which
established new accounting and reporting guidelines for derivative instruments
and hedging activities. SFAS No. 133 established accounting and reporting
standards requiring that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded in the balance
sheet as either an asset or liability measured at its fair value. SFAS No. 133
requires that changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. Special accounting
for qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the income statement. Companies must formally
document, designate and assess the effectiveness of transactions that receive
hedge accounting.
Under SFAS No. 133, the Partnership marks to fair value its derivative
instruments at each period end with changes in fair value of derivatives not
designated as hedges being recorded as unrealized gains or losses. Such
unrealized gains or losses will change, based on prevailing market prices, at
each balance sheet date prior to the period in which the transaction actually
occurs. Unrealized gains or losses on derivative transaction qualifying as
hedges are reflected in other comprehensive income.
In general, SFAS No. 133 requires that at the date of initial adoption, the
difference between the fair value of derivative instruments and the previous
carrying amount of those derivatives be recorded in net income or other
comprehensive income, as appropriate, as the cumulative effect of a change in
accounting principle. On January 1, 2001, recognition of the Partnership's
derivatives resulted in a gain of $0.5 million, which was recognized in the
consolidated statement of operations as the cumulative effect of adopting SFAS
No. 133. Certain derivative contracts related to written option contracts had
been recorded on the balance sheet at fair value at December 31, 2000, so no
adjustment was necessary for those contracts upon adoption of SFAS No. 133.
The Partnership regularly reviews its contracts to determine if the
contracts qualify for treatment as derivatives in accordance with SFAS No. 133.
At December 31, 2002, the Partnership determined that the only contract
qualifying as a derivative was a qualifying cash flow hedge. The decrease of
$39,000 in the fair value of this hedge is recorded in other comprehensive
income and as accumulated other comprehensive income in the consolidated balance
sheet. No hedge ineffectiveness was recognized during 2002. The anticipated
transaction (crude oil sales) will occur in January 2003, and all related
amounts currently held in other comprehensive income will be reclassed to the
income statement in 2003. The Partnership determined that its other derivative
contracts qualified for the normal purchase and sale exemption at December 31,
2002. Therefore, the decrease in fair value of the Partnership's net asset for
derivatives not qualifying as hedges decreased to zero. This decrease in fair
value of $2.1 million is recorded as a loss in the consolidated statements of
operations under the caption "Change in fair value of derivatives". The
consolidated balance sheet at December 31, 2001, included $5.5 million in other
current assets and $3.5 million in accrued liabilities as a result of recording
the fair value of derivatives. In 2001, the Partnership did not designate any of
its derivatives as hedging instruments under SFAS No. 133.
20. Commitments and Contingencies
Commitments and Guarantees
The Partnership leases office space for its headquarters office under a
long-term lease. The lease extends until October 31, 2005. Ryder provides
tractors and trailers to the Partnership under an operating lease that also
includes full-service maintenance. Under the terms of the lease, the Partnership
leases 75 tractors and 75 trailers. The Partnership pays a fixed monthly rental
charge for each tractor and trailer and a fee based on mileage for the
maintenance services. The Partnership leases three tanks for use in its pipeline
operations. The tank leases expire in 2004. Additionally, it leases a segment of
pipeline. Under the terms of that lease, the Partnership makes lease payments
based on throughput, and has no minimum volumetric or financial requirements
remaining. The Partnership also leases service vehicles for its field personnel.
The future minimum rental payments under all noncancelable operating
leases as of December 31, 2002, were as follows (in thousands).
62
Office Tractors and Service
Space Trailers Tanks Vehicles Total
-------- --------- --------- --------- ---------
2003...... $ 431 $ 2,832 $ 465 $ 374 $ 4,102
2004...... 489 2,838 465 373 4,165
2005...... 410 2,387 - 222 3,019
2006...... 18 997 - - 1,015
2007....... 15 887 - - 902
2008 and
thereafter. - 2,518 - - 2,518
--------- --------- --------- --------- ---------
Total minimum
lease obligations $ 1,363 $ 12,459 $ 930 $ 969 $ 15,721
========= ========= ========= ========= ========
Total operating lease expense was as follows (in thousands).
Year ended December 31, 2002.............................. $ 4,713
Year ended December 31, 2001.............................. $ 4,379
Year ended December 31, 2000.............................. $ 2,500
The Partnership has guaranteed $5.2 million of residual value related to
the leases of tractors and trailers. Management of the Partnership believes the
likelihood the Partnership would be required to perform or otherwise incur any
significant losses associated with this guaranty is remote.
GELP has guaranteed crude oil purchases of GCOLP. These guarantees,
totaling $9.9 million, were provided to counterparties. To the extent
liabilities exist under the contracts subject to these guarantees, such
liabilities are included in the consolidated balance sheet.
GELP, the General Partner and the subsidiaries of GCOLP have guaranteed
the payments by GCOLP to Citicorp under the terms of the Citicorp Agreement
related to borrowings and letters of credit. Borrowings at December 31, 2002
were $5.5 million and are reflected in the consolidated balance sheet. To the
extent liabilities exist under the letters of credit, such liabilities are
include in the consolidated balance sheet.
The Partnership has contractual commitments (forward contracts) arising
in the ordinary course of its crude oil marketing activities. At December 31,
2002, the Partnership had commitments to purchase 2,743,000 barrels of crude oil
in January 2003, and 1,864,000 barrels of crude oil between February 2003, and
June 2004. The partnership had commitments to sell 2,810,000 barrels of crude
oil in January 2003, and 749,000 barrels of crude oil between February 2003 and
July 2003. All of these contracts are associated with market-price-related
contracts. The total commitment to purchase crude oil would be valued at $139.9
million, using market prices at December 31, 2002. The total commitment to sell
crude oil would be valued at $110.2 million, using market prices at December 31,
2002.
In general, the Partnership expects to increase its expenditures in the
future to comply with higher industry and regulatory safety standards. While the
total amount of increased expenditures cannot be accurately estimated at this
time, the Partnership anticipates that it will expend a total of approximately
$9.6 million in 2003 and 2004 for testing and rehabilitation under regulations
requiring assessment of the integrity of crude oil pipelines.
Unitholder Litigation
On June 7, 2000, Bruce E. Zoren, a holder of units of limited partner
interests in the partnership, filed a putative class action complaint in the
Delaware Court of Chancery, No. 18096-NC, seeking to enjoin the restructuring
and seeking damages. Defendants named in the complaint include the Partnership,
Genesis Energy L.L.C., members of the board of directors of Genesis Energy,
L.L.C., and Salomon Smith Barney Holdings Inc. The plaintiff alleges numerous
breaches of fiduciary duty loyalty owed by the defendants to the purported class
in connection with making a proposal for restructuring. In November 2000, the
plaintiff amended its complaint. In response, the defendants removed the amended
complaint to federal court. On March 27, 2002, the federal court dismissed the
suit; however, the plaintiff filed a motion to alter or amend the judgment. On
May 15, 2002, the federal court denied the motion to alter or amend. The time
for an appeal to be taken expired without an appeal being filed. On June 11,
2002, the plaintiff refiled the original complaint in the Delaware Court of
Chancery, No. 19694-NC. On July 19, 2002, the defendants moved to dismiss the
complaint for failure to state a claim upon which relief can be granted. The
court has not ruled on that motion. Management of the General Partner believes
that the
63
complaint is without merit and intends to vigorously defend the action.
Management of the Partnership believes that any potential liability will be
covered by insurance.
Pennzoil Litigation
The Partnership was named one of the defendants in a complaint filed on
January 11, 2001, in the 125th District Court of Harris County, Texas, cause No.
2001-01176. Pennzoil-Quaker State Company ("PQS") seeks property damages, loss
of use and business interruption suffered as a result of a fire and explosion
that occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on
January 18, 2000. PQS claims the fire and explosion was caused, in part, by
Genesis selling to PQS crude oil that was contaminated with organic chlorides.
We believe that the suit is without merit and intend to vigorously defend
ourselves in this matter. We believe that any potential liability will be
covered by insurance.
PQS is also a defendant in five suits brought by neighbors living in
the vicinity of the PQS Shreveport, Louisiana refinery in the First Judicial
District Court, Caddo Parish, Louisiana, cause nos. 455,647-A. 455,658-B,
455,655-A, 456,574-A, and 458,379-C. PQS has brought third party demand against
Genesis and others for indemnity with respect to the fire and explosion of
January 18, 2000. We believe that the demand against Genesis is without merit
and intend to vigorously defend ourselves in this matter. We believe that any
potential liability will substantially be covered by insurance.
Other Matters
On December 20, 1999, the Partnership had a spill of crude oil from its
Mississippi System. Approximately 8,000 barrels of oil spilled from the pipeline
near Summerland, Mississippi, and entered a creek nearby. A portion of the oil
then flowed into the Leaf River. The oil spill is covered by insurance and the
financial impact to the Partnership for the cost of the clean-up has not been
material. As a result of this crude oil spill, certain federal and state
regulatory agencies will likely impose fines and penalties that would not be
covered by insurance.
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 as a result of the spill from the Mississippi System, a total
accrual of $3.0 million was recorded during 2002 and 2001.
The Partnership is subject to lawsuits in the normal course of business
and examination by tax and other regulatory authorities. Such matters presently
pending are not expected to have a material adverse effect on the financial
position, results of operations or cash flows of the Partnership.