Back to GetFilings.com
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
4
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
- ---------------------
(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.
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
============ ============ =========== ============ ============
(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.
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 per