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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the fiscal year ended December 31, 2003
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).
| |
The aggregate market value of the Common Units held by non-affiliates of the
Registrant on June 30, 2003 (the last business day of Registrant's most recently
completed second fiscal quarter), was approximately $52,612,500 based on $6.10
per unit, the closing price of the Common Units as reported on the American
Stock Exchange on such date. At March 1, 2004, 9,313,811 Common Units were
outstanding.
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GENESIS ENERGY, L.P.
2003 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
Page
----
PART I
Items 1. Business and Properties............................................................... 3
and 2
Item 3. Legal Proceedings..................................................................... 11
Item 4. Submission of Matters to a Vote of Security Holders................................... 13
PART II
Item 5. Market for Registrant's Common Units and Related Unitholder Matters................... 13
Item 6. Selected Financial and Operating Data................................................. 14
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 15
Item 7A. Quantitative and Qualitative Disclosures about Market Risks........................... 41
Item 8. Financial Statements and Supplementary Data........................................... 41
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.. 41
Item 9A. Controls and Procedures............................................................... 41
PART III
Item 10. Directors and Executive Officers of Our General Partner............................... 42
Item 11. Executive Compensation................................................................ 44
Item 12. Security Ownership of Certain Beneficial Owners and Management........................ 46
Item 13. Certain Relationships and Related Transactions........................................ 47
Item 14. Principal Accountants Fees and Services............................................... 48
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K....................... 48
2
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
the various provisions of the Securities Act of 1933 and the Securities Exchange
Act of 1934. All statements, other than historical facts, included in this
document that address activities, events or developments that we expect or
anticipate will or may occur in the future, including things such as plans for
growth of the business, future capital expenditures, competitive strengths,
goals, references to future goals or intentions and other such references are
forward-looking statements. These statements include, but are not limited to,
statements identified by the words "anticipate," "believe," "estimate,"
"expect," "plan," or "intend" and similar expressions and statements regarding
our business strategy, plans and objectives of our management for future
operations. These statements are made by us based on our past experience and our
perception of historical trends, current conditions and expected future
developments as well as other considerations we believe are appropriate under
the circumstances. Whether actual results and developments in the future will
conform to our expectations is subject to numerous risks and uncertainties, many
of which are beyond our control. These risks and uncertainties include general
economic conditions, market and business conditions, opportunities that may be
presented and pursued by us or the lack of such opportunities, competitive
actions by other companies in our industries, changes in laws and regulations,
access to capital, and other factors. Therefore, all the forward-looking
statements made in this document are qualified in their entirety by these
cautionary statements, and no assurance can be made that our goals will be
achieved or that expectations regarding future developments will prove to be
correct. Please read "Other Matters- Risk Factors Related to Our Business"
discussed in Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operations." Except as required by applicable
securities laws, we do not intend to update these forward-looking statements and
information.
PART I
ITEMS 1AND 2. BUSINESS AND PROPERTIES
WEBSITE ACCESS TO REPORTS
We make available free of charge on our internet website
(www.genesiscrudeoil.com) our annual report on Form 10-K, quarterly reports on
Form 10-Q, current reports on Form 8-K and amendments to those reports filed or
furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of
1934 available as soon as reasonably practicable after we electronically file
the material with, or furnish it to, the SEC.
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 engaged in three
operations - crude oil gathering and marketing, crude oil pipeline
transportation and carbon dioxide (CO2) marketing.
We are an independent gatherer and marketer of crude oil. Our
operations are concentrated in Texas, Louisiana, Alabama, Florida, and
Mississippi. Our gathering and marketing margins are generated by buying crude
oil at competitive prices, efficiently transporting or exchanging the crude oil
and marketing the crude oil to customers at favorable prices. We utilize our
trucking fleet of 49 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.
Our operations include transportation of crude oil at regulated
published tariffs on our three common carrier pipeline systems. These systems
are the Texas System, the Jay System extending between Florida and Alabama, and
the Mississippi System extending between Mississippi and Louisiana. The Jay and
Mississippi 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. The Texas pipeline system receives all of its volume from
connections to other carriers. 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.
In November 2003, we acquired assets enabling us to start a
wholesale CO2 operation. We acquired a volumetric production payment from
Denbury Resources Inc. that will provide us with 167.5 billion cubic feet (Bcf)
3
of CO2. We also acquired from Denbury three of their long-term industrial supply
contracts for CO2. We will ship the CO2 from the source to the customers on a
pipeline owned by Denbury and will sell the CO2 to the customers. These sales
contracts extend through 2015.
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.
DESCRIPTION OF SEGMENTS AND RELATED ASSETS
Crude Oil Gathering and Marketing
In our gathering and marketing business, we are principally engaged
in the purchase and aggregation of crude oil for resale at various points along
the crude oil distribution chain, which extends from the wellhead to aggregation
at terminal facilities and refineries. (the "Distribution Chain"). 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. We generally enter into an exchange transaction only when the
cost of the exchange is less than the alternative costs that we 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 contractual delivery
requirements.
Segment margin from our crude oil gathering and marketing operations
varies from period to period, depending, to a significant extent, upon changes
in the supply of and demand for 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 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.
An increase in the market price of crude oil does not impact us to
the extent many people expect. When market prices for crude 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.
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. Both bulk purchases and buy/sell agreements
were significantly reduced in 2002 compared to prior years. During 2003, our
bulk and exchange transactions averaged 12,000 barrels per day, down from
246,319 barrels per day in the fourth quarter of 2001. The reduction is
attributable primarily to credit requirements for these transactions as
discussed below.
We provide crude oil gathering services through our fleet of 49
leased tractor-trailers. The trucking fleet generally hauls the crude oil to one
of the approximately 60 pipeline injection stations owned or leased by us. We
may sell the crude oil as it exits our injection station and enters the
pipeline, or we may ship the crude oil on the pipeline to a point further along
the Distribution Chain.
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 400
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
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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 calculating and paying production taxes on behalf of interest owners.
In order to compete effectively, we must 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
2003, we distributed payments to approximately 17,000 interest owners.
Credit
Our credit standing is an important consideration for parties with
whom we do business. Some counterparties, in connection with our crude oil
purchases or exchanges, require us to furnish guarantees or letters of credit.
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 an important 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.
Over the last three years 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
our cost 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 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 crude oil gathering and marketing business, 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 400 producers.
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 Marketing, L.P., Link Energy Partners,
L.P., Shell Trading Company, GulfMark Energy, Inc. and TEPPCO Partners, L.P.
Additionally, we compete with many regional or local gatherers who may have
significant market share in the areas in which they operate. Competitive factors
include price, personal relationships, range and quality of services, knowledge
of products and markets, availability of trade credit and capabilities of risk
management systems.
As part of the sale of our Texas Gulf Coast operations to TEPPCO
Crude Pipeline, L.P., we agreed not to compete in a 40 county area for five
years from the effective date of the transaction of October 31, 2003. See
additional information on this sale below.
Crude Oil Pipeline Transportation
Through the pipeline systems we own and operate our pipeline
subsidiaries transport crude oil for our gathering and marketing operations 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
5
specifications contained in the applicable tariff. Pipeline revenues are a
function of the level of throughput and the particular 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 and deductions
exceed measurement losses, the net pipeline loss allowance volumes are earned
and recognized as income and inventory available for sale 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
pipeline revenue.
The margins from our pipeline operations are generated by the
difference between the revenues from regulated published tariffs, pipeline loss
allowance revenues and the fixed and variable costs of operating and maintaining
our pipelines.
We own and operate three common carrier crude oil pipeline systems.
The pipelines and related gathering systems consist of the 135-mile Texas
system, the 103-mile Jay System, and the 266-mile Mississippi System.
In 2003 we sold portions of our Texas system to TEPPCO Crude
Pipeline, L.P. and to Blackhawk Pipeline, L.P., an affiliate of MultiFuels, Inc.
The segments we sold to TEPPCO included Bryan to Hearne, Conroe to Satsuma,
Hillje to West Columbia and Withers to West Columbia. TEPPCO also acquired our
crude oil gathering and marketing operations in the 40 county area surrounding
the pipeline. The segments we sold to Blackhawk had been idle since 2002. These
segments include Neches to Satsuma, Raccoon Bend to Satsuma and a short portion
of the segment from Satsuma to Cullen Junction.
We abandoned in place segments that had been idled in 2002,
primarily between Satsuma and Cullen Junction. The segments we continue to
operate extend from West Columbia to Webster, Cullen Junction to Webster,
Webster to Texas City and Webster to Houston. These segments include
approximately 135 miles of pipe. We entered into a joint tariff with TEPPCO to
receive oil from their system at West Columbia and Cullen Junction. We also
continue to receive barrels from a connection with Seminole Pipeline Company at
Webster.
The joint tariff arrangement with TEPPCO ends in September 2004 when
we will idle the West Columbia to Webster segment and the Cullen Junction to
Webster segment. We will idle these segments to avoid the costs of testing and
possible repairs required under pipeline integrity management regulations. See
Regulation - Safety Regulations below. We will evaluate alternatives at that
time, including converting the segments to natural gas service.
We own approximately 500,000 barrels of storage capacity associated
with the Texas pipeline system that is temporarily being used in conjunction
with our transitional arrangement with TEPPCO. Once TEPPCO integrates the assets
they acquired from us into their operations, we will idle all of this storage
capacity. Additionally, we lease approximately 200,000 barrels of storage
capacity for the Texas System in Webster.
The Mississippi system extends from Soso, Mississippi to Liberty,
Mississippi and then from Liberty, Mississippi to near Baton Rouge, Louisiana.
We own 200,000 barrels of storage capacity on our Mississippi System, with the
tankage located at different places along the system. The segment of the
Mississippi system from Liberty to Baton Rouge has been temporarily idled since
February 2002. In the second quarter of 2004, we will remove the oil from this
segment of the pipeline and consider alternatives for its use, including product
or natural gas service.
The Jay system begins near oil fields in southeastern Alabama and
the panhandle of Florida and extends to a point near Mobile, Alabama. The Jay
system has 230,000 barrels of storage capacity, primarily at Jay station.
Credit
Under the tariffs we have filed with the FERC and the Texas Railroad
Commission, shippers are required to pay the tariff invoices we send to them
within ten days of receipt of the invoices. If they fail to do so, we can charge
interest and suspend service to that shipper. Because shippers do not want any
disruption in shipments, they generally pay the invoices promptly. Additionally,
the larger shippers on our systems are large oil companies.
Under the joint tariff with TEPPCO for the Texas system, TEPPCO
invoices and collects the tariff from the shipper and remits to us our share of
the joint tariff.
6
The only shipper on our Mississippi system as of December 31, 2003
is Genesis Crude Oil, L.P. Genesis buys production from producers, primarily
Denbury, and ships it on the pipeline for sale at Liberty to third parties.
Competition
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 production, refineries and connecting
pipelines. We believe that high capital costs, tariff regulation and the cost of
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 competitive.
CO2 Marketing
In November 2003, we entered the wholesale CO2 marketing business.
We acquired a volumetric production payment from Denbury consisting of 167.5 Bcf
of CO2. Denbury owns 1.6 trillion cubic feet of estimated proved reserves of
CO2 in the Jackson Dome area near Jackson, Mississippi. We also acquired from
Denbury three long-term CO2 agreements with industrial customers to supply
CO2 through 2015. Denbury transports the CO2 to the customer, charging us a
fee. We then sell the CO2 to the customers who treat the CO2 and sell it to
end users for use it for beverage carbonation and food chilling and freezing.
The margins from the CO2 operations are generated by the difference
between the sales price of the CO2 to the industrial customers and the costs of
the transportation provided by Denbury.
Credit
The three customers we have contracts with for CO2 sales are large
companies with good credit ratings. We do not expect to experience any credit
related issues with these customers, however we do monitor their credit
standings on an ongoing basis.
Competition
Naturally-occurring CO2, like that from the Jackson Dome area,
occurs infrequently, and only in limited areas east of the Mississippi River,
including the fields controlled by Denbury. This natural CO2 requires less
processing and treatment in order to be of a quality to be used in food than
does CO2 that is a by-product of fertilizer production. Our industrial CO2
customers have facilities that are connected to Denbury's CO2 pipeline to make
delivery easy and efficient.
CO2 does have other uses, such as tertiary recovery in oil fields,
should the food industries uses decline. Our contracts have take-or-pay
provisions requiring minimum volumes each year for each customer that must be
paid for even if the CO2 is not taken.
EMPLOYEES
To carry out various purchasing, gathering, transporting and
marketing activities, the General Partner employed, at December 31, 2003,
approximately 200 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 has issued rules to adopt and implement the Sarbanes-Oxley Act. These
rules include 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
7
requirements to make filings with the SEC available on our website. Additional
rules 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 2004 an internal control report that contains management's assertions
regarding the effectiveness of procedures over financial reporting and a report
from our auditors attesting to that certification. Our deadlines for filing
quarterly and annual filings with the SEC will also be shortened under the
regulations.
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. Increases from grandfathered 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 year to year change 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.
FERC allows for rate changes under three 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.
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. Most of the volume on our Texas system is now
shipped under a joint tariff with TEPPCO. Approximately 10% of the volume
shipped is pursuant to a tariff we issued. 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
8
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 "hazardous
substances." Although we have applied operating and disposal practices that were
standard 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 $3.0 million during 2001 and 2002. We expect to finalize the agreements
with the federal and Mississippi governments during 2004; however, no assurance
can be made that we will reach final agreement with the governments or the
specific terms of a final agreement if one is reached.
Safety and Security 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
9
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 mandates, 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 other 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 considered include proximity to population
areas, waterways and sensitive areas, known pipe and coating conditions, leak
history, pipe material and manufacturer, adequacy of cathodic protection,
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.
We have developed a Risk Management Plan as part of our 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
identified HCAs and unusually sensitive areas (USAs) along the pipeline
right-of-ways in addition to mapping of shorelines to characterize the potential
of a spill of crude oil on waterways.
States are largely preempted from regulating pipeline safety by
federal law but may assume responsibility for enforcing federal 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. The regulations also required all pipeline operators to develop a
training program for pipeline personnel and qualify them on individually covered
tasks at the operator's pipeline facilities. 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.
10
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 spend a total of
approximately $2.2 million in 2004 and 2005 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
our trucking operations. We are subject to federal EPA regulations for the
development of written Spill Prevention Control and Countermeasure (SPCC) Plans.
All trucking facilities have a current SPCC Plan and employees have received
training on the SPCC Plans and regulations. Annually, trucking employees receive
training regarding the transportation of hazardous materials.
Since the terrorist attacks of September 11, 2001, the United States
Government has issued numerous warnings that energy assets could be the subject
of future terrorist attacks. We have instituted security measures and procedures
in conformity with DOT guidance. We will institute, as appropriate, additional
security measures or procedures indicated by the DOT or the Transportation
Safety Administration (an agency of the Department of Homeland Security, which
has assumed responsibility from the DOT). None of these measures or procedures
should be construed as a guarantee that our assets are protected in the event of
a terrorist attack.
Commodities regulation
If we use futures and options contracts that are traded on the
NYMEX, these contracts are subject to strict regulation by the Commodity Futures
Trading Commission and the rules of the NYMEX.
SUMMARY OF TAX CONSIDERATIONS
The tax consequences of ownership of common units depend on the
owner's individual tax circumstances. However, the following is a brief summary
of material tax consequences of owning and disposing of common units.
Partnership Status; Cash Distributions
We are classified for federal income tax purposes as a partnership
based upon our meeting certain requirements imposed by the Internal Revenue Code
(the "Code"), which we must meet every year. The owners of common units are
considered partners in the Partnership so long as they do not loan their common
units to others to cover short sales or otherwise dispose of those units.
Accordingly, we pay no federal income taxes, and each common unitholder is
required to report on the unitholders federal income tax return the unitholder's
share of our income, gains, losses and deductions. In general, cash
distributions to a common unitholder are taxable only if, and the extent that,
they exceed the tax basis in the common units held.
Partnership Allocations
In general, our income and loss is allocated to the general partner
and the unitholders for each taxable year in accordance with their respective
percentage interests in the Partnership (including, with respect to the general
partner, its incentive distribution right), as determined annually and prorated
on a monthly basis and subsequently apportioned among the general partner and
the unitholders of record as of the opening of the first business day of the
month to which they related, even though unitholders may dispose of their units
during the month in question. A unitholder is required to take into account, in
determining federal income tax liability, the unitholder's share of income
generated by us for each taxable year of the Partnership ending within or with
the unitholder's taxable year, even if cash distributions are not made to the
unitholder. As a consequence, a unitholder's share of our taxable income (and
possibly the income tax payable by the unitholder with respect to such income)
may exceed the cash actually distributed to the unitholder by us. At any time
incentive distributions are made to the general partner, gross income will be
allocated to the recipient to the extent of those distributions.
Basis of Common Units
A unitholder's initial tax basis for a common unit is generally the
amount paid for the common unit. A unitholder's basis is generally increased by
the unitholder's share of our income and decreased, but not below zero, by the
unitholder's share of our losses and distributions.
11
Limitations on Deductibility of Partnership Losses
In the case of taxpayers subject to the passive loss rules
(generally, individuals and closely-held corporations), any partnership losses
are only available to offset future income generated by us and cannot be used to
offset income from other activities, including passive activities or
investments. Any losses unused by virtue of the passive loss rules may be fully
deducted if the unitholder disposes of all of the unitholder's common units in a
taxable transaction with an unrelated party.
Section 754 Election
We have made the election pursuant to Section 754 of the Code, which
will generally result in a unitholder being allocated income and deductions
calculated by reference to the portion of the unitholder's purchase price
attributable to each asset of the Partnership.
Disposition of Common Units
A unitholder who sells common units will recognize gain or loss
equal to the difference between the amount realized and the adjusted tax basis
of those common units. A unitholder may not be able to trace basis to particular
common units for this purpose. Thus, distributions of cash from us to a
unitholder in excess of the income allocated to the unitholder will, in effect,
become taxable income if the unitholder sells the common units at a price
greater than the unitholder's adjusted tax basis even if the price is less than
the unitholder's original cost. Moreover, a portion of the amount realized
(whether or not representing gain) will be ordinary income.
State, Local and Other Tax Considerations
In addition to federal income taxes, unitholders will likely be
subject to other taxes, such as state and local income taxes, unincorporated
business taxes, and estate, inheritance or intangible taxes that are imposed by
the various jurisdictions in which a unitholder resides or in which we do
business or own property. A unitholder may be required to file state income tax
returns and to pay taxes in various states. A unitholder may be subject to
penalties for failure to comply with such requirement. In certain states, tax
losses may not produce a tax benefit in the year incurred (if, for example, we
have no income from sources within that state) and also may not be available to
offset income in subsequent taxable years. Some states may require us, or we may
elect, to withhold a percentage of income from amounts to be distributed to a
unitholder who is not a resident of the state. Withholding, the amount of which
may be more or less than a particular unitholder's income tax liability owed to
the state, may not relieve the nonresident unitholder from the obligation to
file an income tax return. Amounts withheld may be treated as if distributed to
unitholders for purposes of determining the amounts distributed by us.
It is the responsibility of each prospective unitholder to
investigate the legal and tax consequences, under the laws of pertinent states
and localities, of the unitholder's investment in us. Further, it is the
responsibility of each unitholder to file all U.S. federal, state and local tax
returns that may be required of the unitholder.
Ownership of Common Units by Tax-Exempt Organizations and Certain
Other Investors
An investment in common units by tax-exempt organizations (including
IRAs and other retirement plans), regulated investment companies (mutual funds)
and foreign persons raises issues unique to such persons. Virtually all income
allocated to a unitholder that is a tax-exempt organization is unrelated
business taxable income and, thus, is taxable to such a unitholder. Furthermore,
no significant amount of our gross income is qualifying income for purposes of
determining whether a unitholder will qualify as a regulated investment company,
and a unitholder who is a nonresident alien, foreign corporation or other
foreign person is regarded as being engaged in a trade or business in the United
States as a result of ownership of a common unit and, thus, is required to file
federal income tax returns and to pay tax on the unitholder's share of our
taxable income. Finally, distributions to foreign unitholders are subject to
federal income tax withholding.
Tax Shelter Registration
The Code generally requires that "tax shelters" be registered with
the Secretary of the Treasury. We are registered as a tax shelter with the
Secretary of the Treasury. Our tax shelter registration number is 97043000153.
Issuance of the registration number does not indicate that an investment in the
Partnership or the claimed tax benefits has been reviewed, examined or approved
by the Internal Revenue Service.
12
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, of such proceedings is not expected to have a material
adverse effect on the financial condition or results of our operations. For
information on the settlement of litigation with Pennzoil see Management's
Discussion and Analysis - Other Matters on page 39.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the security holders during the
fiscal year covered by this report.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON UNITS AND RELATED SECURITY HOLDER MATTERS
The Common Units are listed on the American Stock Exchange under the
symbol "GEL". 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)
2003
First Quarter...................................... $ 5.70 $ 4.11 $ --
Second Quarter..................................... $ 6.59 $ 4.62 $ 0.05
Third Quarter...................................... $ 7.60 $ 5.10 $ 0.05
Fourth Quarter..................................... $ 10.00 $ 6.85 $ 0.05
----------
(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, 2003, there were 9,313,811 Common Units outstanding,
including 688,811 Common Units held by our General Partner. As of December 31,
2003, there were approximately 6,500 record holders and beneficial owners (held
in street name) of our Common Units.
We distribute all of our 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 our cash
receipts less cash disbursements, adjusted for net changes to cash reserves.
Cash reserves are the amounts deemed necessary or appropriate, in the reasonable
discretion of our general partner, to provide for the proper conduct of our
business or to comply with applicable law, any of our debt instruments or other
agreements. The full definition of Available Cash is set forth in the
Partnership Agreement and amendments thereto, which is filed as an exhibit to
this Form 10-K.
Our target minimum quarterly distribution is $0.20 per Common Unit. In
addition to its 2% general partner interest, our general partner is entitled to
receive incentive distributions if the amount we distribute with respect to any
quarter exceeds levels specified in our partnership agreement.
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. We paid a special distribution in the
fourth quarter of 2002 to mitigate potential taxable income allocations to
unitholders. In 2003, we began paying quarterly distributions again with
distributions for the first quarter of 2003 of $0.05 per unit. For the fourth
quarter of 2003, we increased our distribution to $0.15 per unit (which was paid
in February 2004).
13
ITEM 6. SELECTED FINANCIAL DATA
The table below includes selected financial data for the Partnership for
the years ended December 31, 2003, 2002, 2001, 2000, and 1999 (in thousands,
except per unit and volume data).
Year Ended December 31,
----------------------------------------------------------------------------
2003 2002 2001 2000 1999
---------- ------------ ---------- ---------- ----------
INCOME STATEMENT DATA:
Revenues:
Crude oil revenues:
Gathering & marketing ...................... $ 641,684 $ 639,143(1) $3,001,632 $3,897,799 $1,941,353
Pipeline ................................... 15,134 13,485 9,948 10,728 12,344
CO2 revenues ................................... 1,079 -- -- -- --
Total revenues ............................. 657,897 652,628 3,011,580 3,908,527 1,953,697
Costs and expenses:
Crude oil costs:
Crude oil and field operating .............. 633,776 627,966(1) 2,991,904 3,887,474 1,927,930
Pipeline operating ......................... 10,324 8,076 7,038 5,342 5,067
CO2 transportation costs ....................... 355 -- -- -- --
---------- ------------ ---------- ---------- ----------
General and administrative expenses ............ 8,768 7,864 11,307 10,623 11,358
Depreciation and amortization .................. 4,641 4,603 5,340 6,023 6,250
Impairment of long-lived assets ................ -- -- 9,589(2) -- --
Change in fair value of
derivatives .................................... -- 1,279 (1,681) -- --
Gain from sale of surplus assets ............... (236) (705) (167) (1,148) (849)
Other operating charges ........................ -- 1,500 1,500 1,387 --
---------- ------------ ---------- ---------- ----------
Total costs and expenses ................... 657,330 650,583 3,024,830 3,909,701 1,949,756
---------- ------------ ---------- ---------- ----------
Operating income (loss) from continuing
operations ................................... 34 2,045 (13,250) (1,174) 3,941
Interest expense, net ............................. (986) (1,035) (527) (1,010) (929)
Minority interests effects ........................ -- -- 1 223 (602)
---------- ------------ ---------- ---------- ----------
Income (loss) in continuing operations
before cumulative effect of change
in accounting principle ...................... (717) 1,010 (13,776) (1,961) 2,410
Income (loss) from discontinued
operations ................................... 14,039 4,082 (30,303)(2) 2,142 (78)
Cumulative effect of change in
accounting principle, net of
minority interest effect ..................... -- -- 467 -- --
---------- ------------ ---------- ---------- ----------
Net income (loss) ................................. $ 13,322 $ 5,092 $ (43,612) $ 181 $ 2,332
========== ========== ========== ========== ==========
Net income (loss) per common
unit-basic and diluted:
Continuing operations .......................... $ (0.05) $ 0.12 $ (1.57) $ (0.22) $ 0.35
Discontinued operations ........................ 1.55 0.46 (3.44) 0.24 (0.08)
Cumulative effect of change in
accounting principle ......................... -- -- 0.05 -- --
---------- ---------- ---------- ---------- ----------
Net income (loss) .............................. $ 1.50 $ 0.58 $ (4.96) $ 0.02 $ 0.27
========== ========== ========== ========== ==========
Cash distributions per common unit: ............... $ 0.15 $ 0.20 $ 0.80 $ 2.28 $ 2.00
14
Year Ended December 31,
-----------------------------------------------------------------------
2003 2002 2001 2000 1999
-------- -------- -------- -------- --------
BALANCE SHEET DATA (AT END OF PERIOD):
Current assets .................................. $ 88,211 $ 92,830 $182,100 $350,604 $274,717
Total assets .................................... 147,115 137,537 230,113 449,343 380,592
Long-term liabilities ........................... 7,000 5,500 13,900 -- 3,900
Minority interests .............................. 517 515 515 520 30,571
Partners' capital ............................... 52,354 35,302 32,009 82,615 53,585
OTHER DATA:
Maintenance capital expenditures(3) ............. $ 4,178 $ 4,211 $ 1,882 $ 1,685 $ 1,682
Volumes-continuing operations:
Crude oil gathering and marketing:
Wellhead (bpd) ............................. 45,015 47,819 67,373 94,995 89,076
Bulk and exchange (bpd) .................... 11,790 25,610(1) 253,159 264,235 215,019
Crude oil pipeline (bpd) ..................... 66,959 71,870 80,408 82,092 89,298
CO2 marketing(4) (Mcf) ....................... 36,332 -- -- -- --
(1) At the end of 2001, we changed our business model to substantially
eliminate bulk and exchange transactions due to relatively low margins and
high credit requirements.
(2) In 2001, we recorded an impairment charge of $45.1 million, with $35.5
million of that amount included in discontinued operations. This
impairment charge related to goodwill and our pipeline operations.
(3) Maintenance capital expenditures are capital expenditures to replace or
enhance partially or fully depreciated assets to sustain the existing
operating capacity or efficiency of our assets and extend their useful
lives.
(4) Represents average daily volume for the two month period that we owned the
assets.
The table below summarizes our quarterly financial data for 2003 and 2002
(in thousands, except per unit data).
2003 Quarters
--------------------------------------------------------------
First Second Third Fourth
--------- --------- --------- ---------
Revenues - continuing operations ............................ $ 175,682 $ 146,670 $ 157,094 $ 178,451
Operating income (loss) - continuing operations ............. $ 923 $ 903 $ (1,411) $ (145)
Income (loss) from continuing operations .................... 381 745 (1,568) (275)
Income from discontinued operations ......................... 489 1,145 355 12,041
Net income (loss) ........................................... $ 879 $ 1,890 $ (1,213) $ 11,766
Net income (loss) per Common Unit-
basic and diluted ...................................... $ 0.10 $ 0.21 $ (0.14) $ 1.28
2002 Quarters
--------------------------------------------------------------
First Second Third Fourth
--------- --------- --------- ---------
Revenues - continuing operations ............................ $ 176,757 $ 169,681 $ 154,357 $ 147,961
Operating income (loss) - continuing operations ............. $ (239) $ 941 $ 604 $ 1,268
Income (loss) from continuing operations .................... (725) 569 34 1,087
Income (loss) from discontinued operations .................. 2,039 1,537 69 482
Net income (loss) ........................................... $ 1,314 $ 2,106 $ 103 $ 1,569
Net income (loss) per Common Unit -
basic and diluted ...................................... $ 0.15 $ 0.24 $ 0.01 $ 0.18
15
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:
- Overview of 2003
- Critical Accounting Policies
- Results of Operations and Outlook for 2004 and Beyond
- Liquidity and Capital Resources
- Commitments and Off-Balance Sheet Arrangements
- Other Matters
- New Accounting Pronouncements
In the discussions that follow, we will focus on two measures that we use
to manage the business and to review the results of our operations. Those two
measures are segment margin and available cash. Our profitability depends to a
significant extent upon our ability to maximize segment margin. Segment margin
is calculated as revenues less cost of sales and operating expense, and does not
include depreciation and amortization. A reconciliation of Segment Margin to
income from continuing operations is included in our segment disclosures in Note
8 to the consolidated financial statements. Available Cash is a non-GAAP
liquidity measure calculated as net income with several adjustments, the most
significant of which are the elimination of gains and losses on asset sales,
except those from the sale of surplus assets, the addition of non-cash expenses
such as depreciation, and the subtraction of maintenance capital expenditures,
which are expenditures to sustain existing cash flows but not to provide new
sources of revenues. For additional information on Available Cash and a
reconciliation of this measure to cash flows from operations, see "Non-GAAP
Financial Measure" below.
OVERVIEW OF 2003
Genesis Energy, L.P. is a Delaware limited partnership that is
publicly traded on the American Stock Exchange. We operate through Genesis Crude
Oil, L.P., and its subsidiary partnerships, Genesis Pipeline Texas, L.P. and
Genesis Pipeline, USA, L.P. Our operations are managed through our general
partner, Genesis Energy, Inc., a wholly-owned indirect subsidiary of Denbury
Resources Inc. The general partner holds a 2% general partner interest and a
7.25% limited partner interest and public unitholders hold an aggregate 90.75%
limited partner interest in Genesis Energy, L.P.
We operate in three business segments - crude oil gathering and
marketing, crude oil pipeline transportation and CO2 marketing. Our revenues
are earned by selling crude oil and CO2 and by charging fees for the
transportation of crude oil on our pipelines. Our focus is on the margin we earn
on these revenues, which is calculated by subtracting the costs of the crude
oil, the costs of transporting the crude oil and CO2 to the customer, and the
costs of operating our assets.
Our primary goal is to generate Available Cash for our unitholders.
This Available Cash is then distributed quarterly to our unitholders. We are
pleased with the progress we made in 2003 toward our goal of generating more
stable sources of Available Cash. Two significant actions that we took in 2003
toward this goal were:
- Disposing of our Texas Gulf Coast operations
- Purchasing a CO2 volumetric production payment and related
marketing contracts.
During the fourth quarter of 2003, we closed the sale of portions of
our Texas Gulf Coast operations to TEPPCO Crude Pipeline, L.P. We also sold
portions of our Texas pipeline system that we idled in 2002 to Blackhawk
Pipeline, L.P. We abandoned in place other portions of the Texas pipeline
system. The sale of these operations was the result of an initiative we started
in 2002 to evaluate our pipeline systems to determine which segments, if any,
should be sold, idled or abandoned to reduce costs or risks of operation, and
which segments we should invest in for future growth. As a result of these
actions we recorded a gain on the disposal of these discontinued operations of
$13.0 million.
The sale of the Texas Gulf Coast operations to TEPPCO benefited both
parties almost immediately. TEPPCO realized benefits from integrating these
assets into their existing South Texas pipeline system. By selling
16
these assets, we reduced 2004 projected maintenance expenditures by $6.6 million
and eliminated potential risks to the continuation of our revenue stream that
may have resulted from consolidation of pipeline assets in the area. We believe
that these assets had more long-term strategic benefit to TEPPCO than to us.
The pipeline segments sold to Blackhawk were assets that we idled in
2002 due to declining volumes and/or risks of operation. We received no proceeds
from this sale. By making the sale to Blackhawk, we eliminated costs of
maintaining the assets. Blackhawk intends to convert the pipeline segments to
natural gas service.
The segments we abandoned in place had not been in service since
2002 and this abandonment reduces our costs for monitoring and maintenance.
Additionally, this abandonment helped to offset tax gains allocated to our
unitholders from the sale to TEPPCO.
The carbon dioxide (CO2) volumetric production payment we
purchased enables us to commence a wholesale CO2 marketing operation. We
acquired this production payment, as well as related long-term CO2 industrial
sales contracts, from Denbury. While this CO2 operation will have some
seasonality, the cash flows from this operation will be much less volatile than
those of our existing crude oil gathering and marketing operation.
The funds to acquire this production payment came from the $21
million received from TEPPCO for the sale of the Texas Gulf Coast operations and
the issuance of 688,811 limited partner units to our general partner in exchange
for $5.0 million.
Our continuing operations did not perform as well as expected.
Volatility in P-Plus market prices for crude oil has historically created
fluctuations in our segment margins. During 2003, we experienced positive
results when P-Plus market prices increased in the early part of the year;
however, a precipitous decline in segment margin during the latter half of the
year offset some of the segment margin earned in the first half of the year.
Revenues from our pipeline transportation operations increased
primarily due to tariff increases in 2002 and 2003.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of consolidated financial statements in conformity
with accounting principles generally accepted in the United States requires us
to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities, if any, at the
date of the consolidated financial statements and the reported amounts of
revenues and expenses during the reporting period. Although we believe these
estimates are reasonable, actual results could differ from those estimates.
Significant accounting policies that we employ are presented in the notes to the
consolidated financial statements (see Note 2. Summary of Significant Accounting
Policies).
Critical accounting policies and estimates are those that are most
important to the portrayal of our financial results and positions. These
policies require management's judgment and often employ the use of information
that is inherently uncertain. Our most critical accounting policies pertain to
revenue and expense accruals, pipeline loss allowance recognition, depreciation,
amortization and impairment of long-lived assets and contingent and
environmental liabilities. These policies are discussed below.
Revenue and Expense Accruals
Information needed to record our revenues is generally available to
allow us to record substantially all of our revenue-generating transactions
based on actual information. The accruals that we are required to make for
revenues are generally insignificant.
We routinely make accruals for expenses due to the timing of
receiving third party information and reconciling that information to our
records. These accruals can include some crude oil purchase costs and expenses
for operating our assets such as contractor charges for goods and services
provided. For crude oil purchases transported on our trucks or our pipelines, we
have access to the volumetric and pricing data so that we can record these
transactions based on actual information. Accounting for crude oil purchases
that involve third party transportation services sometimes require us to make
estimates, as the necessary volumetric data is not available within the
timeframe needed. By balancing our crude oil purchase and sales volumes with the
change in our inventory positions, we believe we can make reasonable estimates
of the unavailable data.
17
The provisions of SFAS No. 133, as amended, require that estimates
be made of the effectiveness of derivatives as hedges and the fair value of
derivatives. The actual results of the transactions involving the derivative
instruments will most likely differ from the estimates. We make very limited use
of derivative instruments; however, when we do, we base these estimates on
information obtained from third parties and from our own internal records.
We believe our estimates for revenue and expense items are
reasonable, but there can be no assurance that actual amounts will not vary from
estimated amounts.
Pipeline Loss Allowance Recognition
Numerous factors can cause crude oil volumes to expand and contract.
These factors include temperature of both the crude oil and the surrounding
atmosphere and the quality of the crude oil, in addition to inherent imprecision
of measurement equipment. As a result of these factors, crude oil volumes
fluctuate, which can result in losses in volumes of crude oil in the custody of
the pipeline that belongs to the shippers. In order to compensate the pipeline
for bearing the risk of actual losses in volumes that occur, the pipeline
generally has established in its tariffs the right to make volumetric deductions
from the shippers for quality and volumetric fluctuations. These deductions are
referred to as pipeline loss allowances.
These allowances are compared to the actual volumetric gains and
losses of the pipeline and the net gain or loss is recorded as revenue or
expense, based on prevailing market prices at that time. When net gains occur,
the pipeline company has crude oil inventory. When net losses occur, any
recorded inventory on hand is reduced and the pipeline records a liability for
the purchase of crude oil that it must make to replace the lost volumes.
Inventories are reflected in the financial statements at the lower of the
recorded value or the market value at the balance sheet date. Liabilities to
replace crude oil are valued at current market prices. The crude oil in
inventory can then be sold, resulting in additional revenue if the sales price
exceeds the inventory value.
Future pipeline loss allowance revenue cannot be predicted, as it
depends on factors beyond management's control such as the crude oil quality and
temperatures, as well as crude oil market prices.
Depreciation, Amortization and Impairment of Long-Lived Assets
In order to calculate depreciation and amortization we must estimate
the useful lives of our fixed assets at the time the assets are placed in
service. Calculation of the useful life of an asset is based on our experience
with similar assets. Experience, however, can cause us to change our estimates,
thus impacting the future calculation of depreciation and amortization.
When events or changes in circumstances indicate that the carrying
amount of an asset may not be recoverable, we review our assets for impairment
in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets. We compare the carrying value of the fixed asset to the
estimated undiscounted future cash flows expected to be generated from that
asset. Estimates of future net cash flows include estimating future volumes,
future margins or tariff rates, future operating costs and other estimates and
assumptions consistent with our business plans. Should the undiscounted future
cash flows be less than the carrying value, we record an impairment charge to
reflect the asset at fair value.
Liability and Contingency Accruals
We accrue reserves for contingent liabilities including
environmental remediation and potential legal claims. When our assessment
indicates that it is probable that a liability has occurred and the amount of
the liability can be reasonably estimated, accruals are made. Our estimates are
based on all known facts at the time and our assessment of the ultimate outcome,
including consultation with external experts and counsel. These estimates are
revised as additional information is obtained or resolution is achieved.
In 2001, we recorded an estimate of $1.5 million for the potential
liability for fines related to the crude oil spill in December 1999 from our
Mississippi pipeline system. After assessing information obtained in meetings
with the government, this estimate was increased to a total of $3.0 million in
2002.
We also make estimates related to future payments for environmental
costs to remediate existing conditions attributable to past operations.
Environmental costs include costs for studies and testing as well as remediation
and restoration. These estimates are sometimes made with the assistance of third
parties involved in monitoring the remediation effort.
18
We have recorded an estimate for the additional costs expected to be
incurred to complete the remediation of the site of the Mississippi crude oil
pipeline spill. This estimate is based upon expectations of the additional work
to be performed to meet regulatory requirements and restore the site. Because
the costs of remediation and restoration for this spill are covered by
insurance, we record a receivable from the insurers for a similar amount.
We believe our estimates for contingent liabilities are reasonable,
but there can be no assurance that actual amounts will not vary from estimated
amounts.
RESULTS OF OPERATIONS AND OUTLOOK FOR 2004 AND BEYOND
The following table summarizes financial data by segment for the
years ended December 31, 2003, 2002 and 2001 (in thousands).
Years Ended December 31,
-------------------------------------------------
2003 2002 2001
----------- ----------- -----------
Revenues
Crude oil gathering & marketing ........................... $ 641,684 $ 639,143 $ 3,001,632
Crude oil pipeline ........................................ 15,134 13,485 9,948
CO2 marketing ............................................. 1,079 -- --
----------- ----------- -----------
Total revenues ................................................ $ 657,897 $ 652,628 $ 3,011,580
=========== =========== ===========
Segment margin
Crude oil gathering & marketing ........................... $ 7,908 $ 11,177 $ 9,728
Crude oil pipeline ........................................ 5,108 5,409 2,910
CO2 marketing ............................................. 724 -- --
----------- ----------- -----------
Total segment margin .......................................... $ 13,740 $ 16,586 $ 12,638
General and administrative expenses ........................... 8,768 7,864 11,307
Depreciation and amortization ................................. 4,641 4,603 5,340
Impairment of long-lived assets ............................... -- -- 9,589
Change in fair value of derivatives ........................... -- 1,279 (1,681)
Net gain on disposal of surplus assets ........................ (236) (705) (167)
Other operating charges ....................................... -- 1,500 1,500
----------- ----------- -----------
Operating income (loss) ....................................... 567 2,045 (13,250)
Interest income (expense), net ................................ (986) (1,035) (527)
Minority interest ............................................. -- -- 1
----------- ----------- -----------
Income from continuing operations ............................. (419) 1,010 (13,776)
Discontinued operations, net of minority interest ............. 13,741 4,082 (30,303)
Cumulative effect of adoption of FAS 133 ...................... -- -- 467
----------- ----------- -----------
Net income (loss) ............................................. $ 13,322 $ 5,092 $ (43,612)
=========== =========== ===========
Barrels per day from continuing operations:
Crude oil wellhead ........................................ 45,015 47,819 67,373
Crude oil total ........................................... 56,805 73,429 320,532
Crude oil pipeline ........................................ 66,959 71,870 80,408
CRUDE OIL GATHERING AND MARKETING OPERATIONS
The key drivers affecting our crude oil gathering and marketing
segment margin include production volumes, volatility of P-Plus, volatility of
grade differentials, inventory management, and credit costs.
Segment 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 segment 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
19
meaningful in analyzing the variation in segment 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 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, generally
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.
A significant factor affecting our gathering and marketing segment
margins is the change in domestic production of crude oil. Short-term and
long-term price trends impact the amount of capital that oil 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. During the last two years,
posted prices for West Texas Intermediate crude oil have ranged from a low near
$16 per barrel to a high of $32 per barrel. The volatility in prices over the
last two 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.
Crude oil prices in the United States are impacted by both
international factors as well as domestic factors. International factors such as
wars and conflicts, instability of foreign governments, and labor strikes affect
prices, as do the influences in the U.S. of environmental regulations and the
supply of domestic production. 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 individual transactions
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
crude 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. by quarter in 2003, 2002 and 2001, based on the simple
averaging of the monthly averages.
20
Quarter P-Plus WTI Posting
------- ------ -----------
2001
First $3.9053 $25.7808
Second $2.7097 $24.8163
Third $3.4173 $23.6087
Fourth $2.8517 $17.2577
2002
First $2.7953 $18.4846
Second $3.3015 $23.0634
Third $3.4400 $25.0589
Fourth $3.5060 $24.9902
2003
First $4.1336 $30.6306
Second $4.6063 $25.7125
Third $4.0336 $27.0065
Fourth $3.4881 $27.9642
As can be seen from this table, changes in P-Plus do not necessarily
correspond to changes in the market price of oil. An example is the decline in
P-Plus between the third and fourth quarters of 2003 when the WTI posting
increased. 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 that
ultimately process the crude oil. We may buy crude 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 margin from that oil purchase and
sale. The table below shows the grade differential between West Texas
Intermediate grade crude oil and West Texas Sour grade crude oil, using the
monthly averages for each quarter of 2001, 2002 and 2003, and the differential
between West Texas Intermediate grade crude oil and Light Louisiana Sweet grade
crude oil for the same periods.
WTI/WTS WTI/LLS
Quarter Differential Differential
------- ------------ ------------
2001
First $(3.694) $(0.137)
Second $(3.810) $(0.149)
Third $(2.047) $(0.081)
Fourth $(2.088) $ 0.180
2002
First $(1.536) $ 0.348
Second $(1.218) $ 0.090
Third $(1.028) $(0.323)
Fourth $(1.772) $ 0.004
2003
First $(2.361) $ 0.460
Second $(3.189) $(0.216)
Third $(2.443) $(0.234)
Fourth $(2.711) $ 0.320
As can be seen from this table, the WTI/WTS market differential varied
from $1.028 per barrel in the third quarter of 2002 to $3.810 per barrel in
second quarter of 2001. The WTI/LLS market differential varied from a negative
$0.323 per barrel in the third quarter of 2002 to a positive $0.460 in the first
quarter of 2003. This volatility in grade differentials can affect the
volatility of our gathering and marketing segment margin.
21
Our 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 or 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 segment margins from the
sale of the crude oil may 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 recognize a loss in our financial
statements should the market price fall below the cost of the inventory. Should
market prices rise, then we will realize a gain when we sell the unexpected
volume of inventory in a later month at higher prices. We make every effort to
limit our exposure to these price fluctuations by minimizing inventory volumes.
Year Ended December 31, 2003 as Compared to Year Ended December 31,
2002
Gathering and marketing segment margins decreased $3.3 million or
29% to $7.9 million for the year ended December 31, 2003, as compared to $11.2
million for the year ended December 31, 2002.
A 22 percent decrease in wellhead, bulk and exchange purchase
volumes between 2002 and 2003, resulting in a $5.3 million decrease in segment
margin, was the primary reason for this decrease.
Factors offsetting this decrease were:
- A $1.6 million increase in segment margin 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; and
- a $0.4 million decrease in field operating costs,
primarily from a $0.5 million decrease in payroll and
benefits, offset by a $0.1 million increase in repair
costs. The decreased payroll-related costs can be
attributed to an approximate 6 percent decrease in the
wellhead volumes. The increase in repair costs is
attributable primarily to repairs at truck unloading
stations.
Although P-Plus declined significantly in the latter half of 2003,
the average for 2003 of $4.065 per barrel was 25% higher than the average for
2002 of $3.261 per barrel. This price increase was not enough however to offset
the decline in volumes.
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 began in late 2001 and continued into the first half of 2002.
Volumes beginning in the third quarter of 2002 have remained relatively stable
at an average of 57,500 barrels per day. For the fourth quarter of 2003, daily
volumes were 61,400 barrels. The change in our business model was the primary
reason crude oil gathering and marketing volumes decreased by 23%.
Field operating costs primarily consist of the costs to operate our
fleet of 49 trucks used to transport crude oil, and the costs to maintain the
trucks and assets used in the crude oil gathering operation. Approximately 55%
of these costs are variable and decline when volumes decline. Such costs include
payroll and benefits (as drivers are paid on a commission basis based on
volumes), maintenance costs for the trucks (as we lease the trucks under full
service maintenance contracts under which we pay a maintenance fee per mile
driven), and fuel costs. Fixed costs include the base lease payment for the
vehicle, insurance costs and costs for environmental and safety related items.
22
Year Ended December 31, 2002 as Compared to Year Ended December 31,
2001
Gathering and marketing segment margins increased $1.4 million or
15% to $11.2 million for the year ended December 31, 2002, as compared to $9.7
million for the year ended December 31, 2001.
The factors increasing segment margin were:
- an $18.4 million increase in segment margin 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; and
- an $0.8 million decrease in credit costs primarily due
to the reduction in bulk and exchange transactions.
Largely offsetting these increases were:
- a 77 percent decrease in wellhead, bulk and exchange
purchase volumes between 2001 and 2002, resulting in a
decrease in segment margin of $17.1 million; and
- a $0.7 million increase in field operating costs,
primarily from a $0.3 million increase in payroll and
benefits, a $0.2 million increase in repair costs, a
$0.1 million increase in vehicle lease costs, and a $0.1
million increase in insurance costs. The increased
payroll-related costs can be attributed to an increase
in benefit costs and an increase in the miles driven in
our trucks. The increased lease costs are attributable
to increases in the number of vehicles and in the miles
driven. 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 our loss history.
As discussed previously, we eliminated transactions with low margins
and high credit costs. These volume reductions were the primary reasons
gathering and marketing volumes decreased by 77% in the 2002 period.
Outlook for 2004 and Beyond
Volatility in P-Plus will continue. During 2004, we expect our crude
oil gathering and marketing business to generate at least as much segment margin
as it did in 2003; however, no assurance can be made that this will occur. Our
plans include increasing volumes by acquiring new production and production
currently being gathered by other parties.
CRUDE OIL PIPELINE OPERATIONS
We operate three common carrier pipeline systems in a five state
area. We refer to these pipelines as our Texas System, Mississippi System and
Jay System. Volumes shipped on these systems for the last three years are as
follows (barrels per day):
Pipeline System 2003 2002 2001
--------------- ---- ---- ----
Texas 43,388 47,987 43,322
Mississippi 8,443 7,426 17,792
Jay 15,128 16,455 19,294
In 2003, we sold or abandoned significant portions of our Texas
System. The segments we retained and continue to operate are from West Columbia
to Webster, Cullen Junction to Webster, and from Webster to Texas City, and
Webster to a shipper's facility in Houston. Information on the segments sold or
abandoned is discussed in the section "Discontinued Operations" below. The
following information pertains only to continuing operations.
Volumes on our Texas System averaged 43,388 barrels per day in 2003.
The crude oil that enters our system comes to us at West Columbia and Cullen
Junction where we have connections to TEPPCO's South Texas System and at Webster
where we have a connection with another pipeline. Under the terms of our sale to
TEPPCO of portions of the pipeline, we have a joint tariff with TEPPCO through
September 2004 under which we earn $0.40 per barrel on the majority of the
barrels we deliver to the shipper's facilities and $0.50 per barrel on heavier
crude oil we deliver. Most of the volume being shipped on our Texas System goes
to three refineries on the Texas Gulf Coast. We are still shipping most of the
same volumes that we were shipping before the sale to TEPPCO, however our tariff
revenue is much less than before the sale, as we ship the crude oil a shorter
distance.
23
The Mississippi System is best analyzed in two segments. The first
segment is the portion of the pipeline that begins in Soso, MS and extends to
Liberty, MS. At Liberty, shippers can transfer the crude oil to a connection to
Capline, a pipeline system that moves crude oil from the Gulf Coast to
refineries in the Midwest. The segment from Soso to Liberty has also been
improved to handle the increased volumes produced by Denbury and transported on
the pipeline. In order to handle future increases in production volumes in the
area that are expected, we have made capital expenditures for tank, station and
pipeline improvements and we will need to make further improvements. See Capital
Expenditures under "Liquidity and Capital Resources" below.
The second segment of the pipeline from Liberty to near Baton Rouge,
LA has been out of service since February 1, 2002 while a connecting carrier
tested its pipeline. The connecting carrier has decided not to reactivate its
pipeline, so we will displace the crude oil in this segment with inhibited water
until the connecting carrier either make repairs or we identify an alternative
use for this segment. The cost of this displacement is being paid for by the
owner of the crude oil. In 2003, this segment made no contribution to pipeline
revenues. In 2002 and 2001, this segment of pipeline contributed $0.1 million
and $1.5 million, respectively, to pipeline revenues. Volumes on this segment in
2001 were over 14,400 barrels per day.
The Jay pipeline system in Florida/Alabama ships crude oil from
fields with relatively short remaining production lives. Volumes have declined
from an annual average of 19,294 per day in 2001, to 16,455 in 2002 to 15,128 in
2003. Many of the costs to operate our pipeline are fixed costs, including the
costs of compliance with environmental regulations and the costs of insurance,
so the decline in volumes has necessitated increases in tariffs. The only
shipper on the largest portion of the pipeline has agreed to tariff rate
increases in 2002 and 2003 that have helped offset the declines in the volumes
and increased costs of operating this pipeline.
Historically, the largest operating costs in our crude oil pipeline
segment have consisted of personnel costs, power costs, maintenance costs and
costs of compliance with regulations. Some of these costs are not predictable,
such as failures of equipment, or are not within our control, like power cost
increases. We perform regular maintenance on our assets to keep them in good
operational condition to minimize any cost increases.
Year Ended December 31, 2003 Compared with Year Ended December 31,
2002
Pipeline segment margin decreased $0.3 million or 6% to $5.1 million
for the year ended December 31, 2003, as compared to $5.4 million for the year
ended December 31, 2002. The factors decreasing pipeline segment margin were:
- a 7 percent decrease in throughput between the two years,
resulting in a revenue decrease of $0.8 million; and
- a $1.9 million increase in pipeline operating costs in 2003.
In the third quarter we recorded an asset retirement
obligation of $0.7 million related to an offshore pipeline.
Pipeline operating costs increased $0.1 million for personnel
and benefits costs related to addition as of operations staff
in Mississippi and additions of staff engineers, and $0.1
million for costs associated with work vehicles for the new
staff. Costs associated with maintenance of right-of ways,
including clearing of tree canopies, and costs for testing
under pipeline integrity regulations increased a combined $0.2
million. In 2003, we increased safety training for pipeline
operations personnel at a cost of $0.3 million. Insurance
costs increased $0.2 million due to the combination of
insurance market conditions and our loss history. Other
operating costs, including power costs increased a total of
$0.3 million.
Partially offsetting these decreases were the following factors:
- a 22 percent increase in the average tariff on shipments
resulting in a $2.3 million increase in revenue; and
- a $0.1 million increase in revenues from sales of pipeline
loss allowance barrels primarily as a result of higher crude
oil market prices resulting in more revenue on these volumes.
Year Ended December 31, 2002 Compared with Year Ended December 31,
2001
Pipeline segment margin increased $2.5 million or 86% to $5.4
million for the year ended December 31, 2002, as compared to $2.9 million for
the year ended December 31, 2001. The factors increasing pipeline segment margin
were:
24
- a 35 percent increase in the average tariff on shipments
resulting in a $2.9 million increase in revenue; and
- a $1.6 million increase in revenues from sales of pipeline
loss allowance barrels 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.
Partially offsetting these increases were:
- an 11 percent decrease in throughput between the two years,
resulting in a revenue decrease of $1.0 million; and
- a $1.0 million increase in pipeline operating costs in 2002
primarily due to greater expenditures for personnel and
benefits, for maintenance of right-of-ways including clearing
of tree canopies and costs associated with residential and
commercial development around our pipelines, for testing under
the pipeline integrity management regulations, for tank and
station maintenance projects, for safety, training and related
projects, for liability and property damage insurance, offset
by lower costs for remote monitoring and control. Personnel
and benefits costs increased $0.3 million primarily as a
result of additions to the operations staff in Mississippi and
costs associated with work vehicles for the new staff added
$0.1 million. Costs associated with maintenance of right of
ways and testing under pipeline integrity regulations
increased a combined $0.1 million. In 2002, we increased
safety training for our pipeline operations personnel at a
cost of $0.1 million. Additionally we undertook a project to
add Global Positioning Satellite information to our pipeline
maps as required pursuant to pipeline safety regulations.
Expenses incurred on this project in 2002 totaled $0.2
million. Insurance costs increased by $0.3 million due to the
combination of insurance market conditions and our loss
history. Our remote monitoring and control costs were lower by
$0.1 million as we completed the transition in early 2002 from
a more expensive service.
Outlook for 2004 and Beyond
After September 2004, we may continue to provide capacity to
transport crude oil on our Texas System from Webster to Texas City and Houston.
We expect to cease using the West Columbia to Webster segment and the Cullen
Junction to Webster segment for crude oil service, as volumes shipped do not
support the costs we would expect to incur to test and repair those segments of
pipeline under the integrity management regulations. See discussion of the
integrity management regulations in Safety Regulation under in "Item 1". If we
continue to ship crude oil from Webster after September 2004, we would expect
that we will receive it at Webster from new connections to other pipelines and
receive less tariff income from those shipments than we are receiving under the
current joint tariff with TEPPCO. We are also examining strategic opportunities
to place the remaining segments in alternative service after the arrangement
with TEPPCO expires.
We expect that volumes may decline in 2004 as refiners on the Texas
Gulf Coast compete for crude oil with other markets connected to TEPPCO's
pipeline systems; however, those effects may not occur until the summer of 2004
when TEPPCO finishes its integration and connection of the segments acquired
from us.
As discussed above, the primary shipper on the segment of our
Mississippi pipeline from Liberty to near Baton Rouge advised us in February
2004 that it does not have plans to reinstate shipments on this segment of
pipeline. We currently plan to temporarily idle this segment of pipeline by
removing the crude oil from the line while we evaluate future plans for this
segment. Any future plans in crude oil service will require sufficient volumes
being available to be transported on this segment of pipeline to justify the
costs to perform the integrity testing and possible upgrading that may be
necessary as a result of that testing. Future plans for this segment may include
transportation of petroleum products or natural gas.
Denbury is the largest oil and 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 CO2 based tertiary recovery operations, Denbury would expect to
add crude oil gathering and CO2 supply infrastructure
25
to these fields. Further, as the fields are developed over time, it may create
increased demand for our crude oil transportation services.
The production shipped from oil fields surrounding our Jay system is
a combination of new fields with estimated short production lives and older
fields that have been producing for twenty to thirty years and are in the late
stages of economic life. We believe that the highest and best use of the Jay
system would be to convert it to natural gas service. We continue to review
strategic alternatives with other parties in the region to explore this
opportunity. This initiative is in a very preliminary stage. 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 2004 or 2005.
Pipeline segment margins from continuing operations should remain
flat or decline slightly in 2004. We expect volume increases on the Mississippi
system and the tariff increases on the Jay system to substantially offset
increases in fixed costs, including the costs for testing under the integrity
management program.
CARBON DIOXIDE (CO2) OPERATIONS
In November 2003, we acquired a volumetric production payment of
167.5 Bcf of CO2 from Denbury. Denbury owns 1.6 trillion cubic feet of estimated
proved reserves of CO2 in the Jackson Dome area near Jackson, Mississippi. In
addition to the production payment, Denbury also assigned to us three of their
existing long-term CO2 contracts with industrial customers. Denbury owns the
pipeline that is used to transport the CO2 to our customers as well as to its
own tertiary recovery operations.
The industrial customers treat the CO2 and transport it to their
own customers. The primary industrial applications of CO2 by these customers
include beverage carbonation and food chilling and freezing. Based on Denbury's
experience, we can expect some seasonality in our sales of CO2, as the
dominant months for beverage carbonation and freezing food are from April to
October, when warm weather drives up demand for beverages and the approaching
holidays increase demand for frozen foods.
The average daily Mcf for each month in 2003, 2002 and 2001
purchased under these contracts was as follows:
Month 2003 2002 2001
----- ---- ---- ----
January 35,533 35,802 32,185
February 38,441 38,770 38,458
March 38,292 39,342 32,761
April 41,683 37,295 36,470
May 42,092 37,890 37,944
June 42,898 37,296 39,342
July 43,220 37,125 40,148
August 42,048 39,799 41,042
September 43,564 39,746 41,159
October 42,810 40,844 41,489
November 38,767 38,568 42,349
December 33,975 34,835 38,234
The volumetric production payment entitles us to a maximum daily
quantity of CO2 of 52,500 million cubic feet (Mcf) per day through December
31, 2009, 43,000 Mcf per day for the calendar years 2010 through 2012, and
25,000 Mcf per day beginning in 2013 until we have received all volumes under
the production payment. Under the terms of a transportation agreement with
Denbury, Denbury will process and deliver this CO2 to our industrial customers
and receive a fee from us of $0.16 per Mcf, subject to inflationary adjustments,
for those transportation services.
The terms of the contracts with the industrial customers include
minimum take-or-pay and maximum delivery volumes. The maximum daily contract
quantity per year in the contracts totals 48,750 Mcf. Under the minimum take or
pay volumes, the customers must purchase a total of 14,468 Mcf per day whether
received or not. Any volume purchased under the take-or-pay provision in any
year can then be recovered in a future year as long as
26
the minimum requirement is met in that year. In the three years ended December
31, 2003, all three customers have purchased more than their minimum take-or-pay
quantities, as can be seen in the table above.
The three industrial contracts extend through 2010, 2012 and 2015.
The sales contracts contain provisions for inflationary adjustments to sales
prices based on the Producer Price Index, with a minimum price.
During the two months we owned the CO2 assets in 2003, we earned
revenues of $1.0 million and segment margin of $0.7 million. We expect to
generate approximately $5 million of annual segment margin from this business
during the first five years. The purchase of these assets provides us with
diversity in our asset base and a stable long-term source of cash flow.
DISCONTINUED OPERATIONS
In the fourth quarter of 2003, we sold a significant portion of our
Texas Pipeline System and the related crude oil gathering and marketing
operations to TEPPCO Crude Oil, L.P. Additionally we sold other segments of our
Texas Pipeline System that had been idled in 2002 to Blackhawk Pipeline, L.P.,
an affiliate of Multifuels, Inc.. We received no proceeds from the sale to
Blackhawk. Other remaining segments not sold to these parties were abandoned in
place.
The sale of these assets was the result of an initiative started in
2002 to evaluate our pipeline systems to determine which segments, if any,
should be sold, idled or abandoned to reduce costs and risks of operation. As a
result of this evaluation we determined that parts of our Texas Gulf Coast
operations were of more strategic value to TEPPCO than to us. We also determined
that other segments of the Texas Gulf Coast operations had little value and
should be abandoned in place or sold to reduce costs or risks. By selling these
assets, we eliminated approximately $6.6 million of capital expenditures that we
might have had to make depending on the results of IMP testing.
TEPPCO paid us $21.6 million for the assets it acquired. We incurred
transaction costs of $0.4 million which reduced the net proceeds to $21.2
million. TEPPCO also assumed responsibility for $0.6 million of unpaid royalties
related to the crude oil purchase and sale contracts it assumed.
We entered into various agreements with TEPPCO including (a) a
transitional services agreement whereby GELP will provide the use of certain
assets that TEPPCO did not acquire and pipeline monitoring services at least
through April 30, 2004, and (b) a joint tariff agreement whereby TEPPCO will
invoice and collect and share with us the tariffs for transportation on the
pipeline being sold and the segments we retained at least through October 31,
2004. We also agreed not to compete with TEPPCO in a 40-county area in Texas
surrounding the pipeline for a five year period.
We retained responsibility for environmental matters related to the
operations sold to TEPPCO for the period prior to the sale date, subject to
certain conditions. TEPPCO will pay the first $25,000 for each environmental
claim up to an aggregate of $100,000. We would be responsible for any
environmental claim in excess of that amount up to an aggregate total of $2
million. TEPPCO has purchased an environmental insurance policy for amounts in
excess of our $2 million responsibility and we reimbursed TEPPCO for one-half of
the policy premium. Our responsibility to indemnify TEPPCO for environmental
matters in connection with this transaction will cease in ten years. We do not
expect the effects of this indemnification to have a material effect on our
results of operations in the future.
During 2003, we recorded $0.4 million in termination benefits
related to this sale. These benefits included retention bonuses and severance
pay for employees affected by the sale.
Under the terms of the sale to Blackhawk, we agreed to provide
transition services through March 31, 2004. These transition services are not
significant as the pipeline is idle. We retained responsibility for any
environmental matters related to the pipeline segments acquired by Blackhawk
through December 31, 2003, however that responsibility will cease in ten years.
27
Operating results from the discontinued operations for the years
ended December 31, 2003, 2002 and 2001 were as follows:
Year Ended December 31,
---------------------------------------
2003 2002 2001
--------- --------- ---------
Revenues:
Gathering and marketing ........................................... $ 263,930 $ 252,452 $ 324,371
Pipeline .......................................................... 6,480 6,726 4,247
--------- --------- ---------
Total revenues ................................................. 270,410 259,178 328,618
Costs and expenses:
Crude costs ....................................................... 256,986 243,262 313,202
Field operating costs ............................................. 4,718 4,535 4,379
Pipeline operating costs .......................................... 5,846 4,852 3,859
General and administrative ........................................ 282 425 384
Depreciation and amortization ..................................... 1,864 1,210 2,206
Change in fair value of derivatives ............................... -- 815 (578)
Net gain on disposal of surplus assets ............................ -- (3) --
Impairment of long-lived assets ................................... -- -- 35,472
--------- --------- ---------
Total costs and expenses ....................................... 26,696 255,096 358,924
--------- --------- ---------
Operating income from discontinued operations .................. 714 4,082 (30,306)
--------- --------- ---------
Net proceeds from asset sales ........................................ 21,240 -- --
Net book value of assets sold ........................................ 8,212 -- --
--------- --------- ---------
Gain on disposal of assets ........................................... 13,028 -- --
--------- --------- ---------
Income from operations from discontinued Texas
System before minority interests .................................. $ 13,742 $ 4,082 $ (30,306)
========= ========= =========
Year Ended December 31, 2003 Compared with Year Ended December 31, 2002
Revenues less crude costs and pipeline and field operating costs
from discontinued operations in 2003 declined by $3.6 million, with $2.4 million
of the decline resulting from crude oil gathering and marketing operations, and
the remainder from pipeline operations.
Margin from discontinued crude oil gathering and marketing
operations declined due to the following:
- an $0.8 million decrease in margin due to an decrease 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;
- a 15 percent decrease in wellhead, bulk and exchange purchase
volumes between 2002 and 2003, resulting in a $1.4 million
decrease in margin; and
- a $0.2 million increase in field operating costs from
termination benefits.
Pipeline margin from discontinued operations decreased by $1.2
million due to the following:
- a 2 percent decrease in the average tariff on shipments
resulting in a $0.1 million decrease in revenue;
- an 11 percent decrease in throughput between the two years,
resulting in a $0.5 million revenue decrease; and
- a $1.0 million increase in pipeline operating costs in 2003.
Included in the pipeline operating costs in 2003 is $0.7
million for demolition and disposal costs for tanks and other
equipment that were not sold and no longer had any use to us.
We chose to perform this demolition in 2003 to reduce the
taxable gain that would be allocated to many of our
unitholders from the sale to TEPPCO. Also included in 2003 is
$0.2 million for termination benefits incurred as a result of
the sale to TEPPCO. Other operating costs increased a total of
$0.1 million.
These decreases were partially offset by a $0.4 million increase in
revenues from sales of pipeline loss allowance barrels primarily as a result of
higher crude oil market prices.
28
General and administrative expenses include the direct costs of
individuals involved only with the assets sold. The decrease in these costs
resulted from the termination of those persons from our employment as a result
of the sale. The increase in depreciation in 2003 as compared to 2002 resulted
from the elimination of the remaining book value of assets not sold that no
longer had any use to us.
Year Ended December 31, 2002 Compared with Year Ended December 31, 2001
Revenues less crude costs and pipeline and field operating costs
from discontinued operations in 2002 declined by $0.6 million. This amount is
the net result of a $2.1 million decrease in margin from crude oil gathering and
marketing operations, and a $1.5 million increase in margin from pipeline
operations. Margin from crude oil gathering and marketing operations declined
due to the following:
- a 22 percent decrease in wellhead, bulk and exchange purchase
volumes between 2002 and 2003, resulting in a decrease in
margin of $2.5 million; and
- $0.1 million increases in both field operating and credit
costs.
Partially offsetting these decreases was a $0.6 million increase in
margin due to a decrease 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.
Pipeline margin increased by $1.5 million due to the following:
- a 34 percent increase of in the average tariff on shipments
resulting in a $1.4 million increase in revenue;
- a 10 percent increase in throughput between the two years,
resulting in a $0.4 million revenue increase; and
- an increase in revenues from sales of pipeline loss allowance
barrels of $0.7 million primarily as a result of higher crude
oil market prices resulting in more revenue on these volumes.
Partially offsetting these increases was a $1.0 million increase in
pipeline operating costs in 2002. These increases included a $0.2 million
increase in costs associated with maintenance of right of ways and testing under
pipeline integrity regulations; tank and station maintenance expenses increased
$0.2 million and safety training for our pipeline operations personnel increased
$0.2 million. Insurance costs increased $0.1 million and the mapping project
added $0.3 million to costs.
In 2001, we recorded impairment of $35.5 related to the assets that
were sold or abandoned in 2003. This impairment reduced the depreciation
recorded in 2002.
OTHER COSTS AND INTEREST
Year Ended December 31, 2003 Compared with Year Ended December 31, 2002
General and administrative expenses. General and administrative
expenses increased $0.9 million in 2003 from the 2002 level. Corporate
governance costs including legal and consultant costs related to compliance with
the Sarbanes-Oxley Act of 2002, increased directors fees and higher directors
and officers insurance costs added $0.4 million. Other general and
administrative costs increased by $0.1 million. Two other factors contributing
to this increase were the write-off of $0.2 million of unamortized legal and
consultant costs related to credit agreement with Citicorp and a non-cash charge
of $0.2 million related to our new stock appreciation rights program for
employees and directors (see Note 14 to the consolidated financial statements).
The write-off of unamortized costs was necessitated by the
replacement of the Citicorp credit facility in 2003 with a credit facility with
Fleet National Bank. Under our bonus program, bonuses were eliminated unless
distributions were being paid, which resulted in no accrual in 2002.
We expect general and administrative expenses in 2004 to remain
level with those of 2003. Consultant costs related to the internal documentation
and assessment provisions of the Sarbanes-Oxley Act are expected to increase
over 2003 levels, offsetting the 2003 write-off of credit facility costs.
Change in fair value of derivatives. We designated our contracts as
normal purchases and sales under the provisions for that treatment in SFAS No.
133. We did not engage in any derivative transactions during 2003, and
29
would expect to do so in 2004 only as needed. During 2002, the fair value of the
Partnership's net asset for derivatives decreased by $2.1 million.
Other operating charges. In 2002, we reached an agreement in
principle with the federal and state regulatory authorities regarding the fines
we would pay related to the spill that occurred in December 1999 in Mississippi.
The cost to us under the agreement is expected to be $3.0 million. In the fourth
quarter of 2001 we accrued $1.5 million for this potential fine and in the third
quarter of 2002 another $1.5 million was accrued.
Interest expense, net. In 2003, our net interest expense decreased
by $0.1 million. The primary factor was a decrease in March 2003 of the size of
our credit facility from $80 million to $65 million. In 2002, the larger amount
of the credit facility resulted in higher commitment fees.
Year Ended December 31, 2002 Compared with Year Ended December 31, 2001
General and administrative expenses. General and administrative
expenses decreased $3.4 million in 2002 from the 2001 level. Changes in
personnel costs primarily due to the elimination of bulk and exchange activities
reduced general and administrative expenses $2.3 million, and charges from our
bonus program were $0.8 million less in 2002. The remaining decrease of $0.3
million is attributable to decreases in expenses for legal, tax and other
professional services, offset by small increases in administrative insurance
costs and contract labor costs.
Depreciation, amortization and impairment. Depreciation and
amortization expense decreased $1.7 million in 2002 from the 2001 level. As a
result of the impairment of our pipeline assets in 2001, the value to be
depreciated was reduced. The impairment recorded in 2001 was $9.6 million and
related primarily to goodwill.
Change in fair value of derivatives. As a result of the significant
reduction in our bulk and exchange activities at December 31, 2001, and a review
of contracts existing at December 31, 2002, we determined that substantially all
of our contracts did not meet the requirement for treatment as derivative
contracts under SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" (as amended and interpreted). The contracts were designated as
normal purchases and sales under the provisions for that treatment in SFAS No.
133. As a result, the fair value of the Partnership's net asset for derivatives
decreased by $2.1 million in 2002.
Net gain on disposal of surplus assets. In 2002, we disposed of our
seats on the NYMEX for $1.7 million, resulting in a gain of $0.5 million. The
changes we made in our business model to reduce our bulk and exchange activities
eliminated our reasons for owning the NYMEX seats. Additionally, in 2002, we
sold surplus land, a building and surplus vehicles, resulting in additional
cumulative net gains of $0.2 million. In 2000, we leased our tractor/trailer
fleet from Ryder Transportation Services. The majority of the existing fleet was
sold in 2000 and 2001. Cash proceeds of $0.4 million and a gain of $0.1 million
in 2001 were realized in 2001 from this sale.
Interest expense, net. In 2002, the Partnership had an increase in
its net interest expense of $0.5 million. In 2001, the Partnership paid
commitment fees on the unused portion of its $25 million facility with BNP
Paribas. In the 2002 period, the Partnership paid commitment fees on the unused
portion of its credit facility of $130 million in the first pat of the year and
$80 million thereafter. The larger amount of the credit facility resulted in
substantially higher commitment fees in 2002.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Our primary sources of cash flows are operations, credit facilities,
and in 2003, proceeds from the sale of a portion of our operations. Additionally
in 2003, we issued limited partner interests to our general partner and received
cash. Our primary uses of cash flows are capital expenditures and distributions.
A summary of our cash flows for the years ended December 31, 2003, 2002 and 2001
is as follows (in thousands):
Year Ended December 31,
-----------------------------------------------
2003 2002 2001
------------ ----------- ------------
Cash provided by (used in):
Operating activities................................. $ 4,693 $ 7,417 $ 18,156
Investing activities................................. $ (6,994) $ (1,963) $ (1,429)
Financing activities................................. $ 4,099 $ (10,160) $ (16,458)
30
Operating. Net cash from operating activities for each year have
been comprised of the following (in thousands):
Year Ended December 31,
-------------------------------------
2003 2002 2001
-------- -------- --------
Net income ............................................. $ 13,322 $ 5,092 $(43,612)
Depreciation, amortization and impairment .............. 7,535 6,549 52,630
Gain on sales of assets ................................ (13,264) (708) (167)
Derivative related non-cash adjustments ................ 39 2,055 (2,726)
Other non-cash items ................................... 229 1,500 1,601
Changes in components of working capital, net .......... (3,168) (7,071) 10,430
-------- -------- --------
Net cash from operating activities .................. $ 4,693 $ 7,417 $ 18,156
======== ======== ========
Our operating cash flows are affected significantly by changes in
items of working capital. We have had situations where other parties have
prepaid for purchases or paid more than was due, resulting in fluctuations in
one period as compared to the next until the party recovers the excess payment.
While this happens infrequently, we did incorrectly receive $2.4 million in 2001
that was not repaid until 2003. During the 2001 period while we were actively
engaged in bulk and exchange activities, our cash flows were affected by the
differences in the timing between receiving the cash effects of derivative
transactions and recording those transactions in net income. Affecting all
periods is the timing of capital expenditures and their effects on our recorded
liabilities.
Cash management in the crude oil gathering and marketing business
functions as follows. All purchases and sales are settled monthly with payment
on the 20th of the following month. We receive payment for sales by wire
transfer on the 20th. Approximately 75% of the obligations for purchases are
also paid by wire transfer on the 20th. The remaining 25% of purchases are paid
for by check. These checks, primarily to royalty owners and small oil companies,
generally take five or six days to clear our bank account. This payment cycle
provides several benefits to us. We know that substantially all of our
receivables for crude oil sales will be collected on the 20th. We also defer
payment until checks that were mailed clear our checking accounts. Our
borrowings, and therefore our interest costs, are reduced for this short time
period each month following the 20th.
Similarly, tariffs are billed monthly and require payment ten days
after the invoice date. Therefore collection of our pipeline accounts receivable
is very rapid. Because shippers generally want to continue shipping, these
receivables are generally paid quickly by our customers.
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 $66.7 million aggregate
receivables on our consolidated balance sheet at December 31, 2003,
approximately $65.4 million, or 98.1%, were less than 30 days past the invoice
date.
Investing. Cash flows used in investing activities in 2003 were $7.0
million as compared to $2.0 million in 2002. In 2003 we sold portions of our
Texas pipeline system as well as other assets for $22.3 million net, and we
expended $24.4 million to acquire the CO2 assets. Additionally we expended
$4.9 million for other capital improvements. These expenditures included
improvements on our Mississippi pipeline system to handle increased volumes more
efficiently and effectively, additions and improvements totaling approximately
$1.5 million on the Texas assets sold to TEPPCO in October 2003 and other
equipment improvements.
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 as
discussed above. 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 our 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. See additional detail on
capital expenditures below.
Financing. In 2003, financing activities provided net cash of $4.1
million. In November 2003, our general partner acquired from us 688,811
newly-issued Common Units and a proportionate general partner interest for $5.0
million. We also increased our outstanding debt by $1.5 million. We utilized
$1.1 million of these funds to pay
31
fees related to the new credit facility with Fleet National Bank. Distributions
to our partners utilized $1.3 million. Net cash expended for financing
activities was $10.2 million in 2002 as compared to $16.5 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
A summary of our capital expenditures in the three years ended
December 31, 2003, 2002, and 2001 is as follows (in thousands):
Year Ended December 31,
-----------------------------------------
2003 2002 2001
--------- --------- ---------
Maintenance capital expenditures:
Texas pipeline system ................................... $ 1,588 $ 1,638 $ 1,242
Mississippi pipeline system ............................. 1,684 1,838 222
Jay pipeline system ..................................... 213 43 10
Crude oil gathering assets .............................. 307 241 167
Administrative assets ................................... 384 451 241
--------- --------- ---------
Total maintenance capital expenditures ............... 4,176 4,211 1,882
Growth capital expenditures:
Mississippi pipeline system ............................. 76 -- --
Crude oil gathering assets .............................. 658 -- --
CO2 assets .............................................. 24,401 -- --
--------- --------- ---------
Total growth capital expenditures .................... 25,135 -- --
--------- --------- ---------
Total capital expenditures ........................ $ 29,311 $ 4,211 $ 1,882
========= ========= =========
Maintenance capital expenditures in 2003 included a total of $0.5
million for installation of pipeline satellite monitoring capabilities on all
three systems. Administrative asset expenditures included computer hardware and
software. In the first half of 2003, we continued to upgrade the West Columbia
to Markham segment of our Texas pipeline. The expenditures on the Mississippi
system included additional improvements to the pipeline from Soso to Gwinville,
where the crude oil spill had occurred in December 1999, to restore this segment
to service. We also improved the pipeline from Gwinville to Liberty to be able
to handle increased volumes on that segment by upgrading pumps and meters and
completing additional tankage.
Growth capital expenditures in 2003 included the acquisition of a
condensate storage facility in Texas that was subsequently sold to TEPPCO and
the acquisition of the CO2 assets from Denbury.
Although we have no commitments to make capital expenditures, based
on the information available to us at this time, we currently anticipate that
our capital expenditures will be as follows (in thousands):
2004 2005 2006
---- ---- ----
Maintenance capital expenditures:
Texas System $ 106 $ 396 $ 199
Mississippi System 455 1,593 969
Jay System 30 145 75
Other 167 60 60
-------- --------- ---------
Total $ 758 $ 2,194 $ 1,303
======== ========= =========
In 2004, we expect the expenditures on our Texas system to relate
primarily to corrosion control and in 2005 and 2006, to improvements to our
control and monitoring system.
The maintenance capital expenditure estimates for our Mississippi
system include corrosion control expenditures, minor facility improvements and
rehabilitation of the pipeline as a result of integrity management test results,
as discussed below.
32
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 High Consequence Areas (HCA). The integrity of
these pipelines must be assessed by internal inspection, pressure test, or
equivalent alternative technology. An 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 in 2002 that
detailed 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 assessed in the first three and
one-half years. Reassessment is then required every five years. We expect to
spend $0.6 million in 2004 and $0.2 million in 2005 for pipeline integrity
testing that will be charged to pipeline operating expense as incurred. As
testing is completed, we are required to take prompt remedial action to address
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 and 2003, we have estimated capital expenditures to be made
during the IMP assessment period from 2004 through 2009. These capital
expenditure projections are based on very preliminary data regarding the cost of
rehabilitation. Such capital expenditure projections have been updated to
eliminate the segments of the Texas system that were sold or abandoned in 2003,
and the projections will be updated as improved data is obtained. During 2003
and 2002, $1.0 million and $1.7 million in capital expenditures were spent for
rehabilitation of the Mississippi and Texas Pipeline Systems. Based on actual
experience during 2003 and 2002 applied to our written IMP plan, we expect to
spend $0.2 million, $1.2 million and $0.7 million in 2004, 2005 and 2006,
respectively, for pipeline rehabilitation on the Mississippi System as a result
of IMP testing. We currently do not expect to incur any rehabilitation
expenditures on the other systems during this period.
Expenditures on capital assets to grow the partnership will depend
on our access to debt and capital discussed below in "Sources of Future
Capital." Our focus will be on acquisitions that add stable cash flows to smooth
out the volatility of the crude oil gathering business. Those acquisitions may
include the acquisition of additional CO2 assets from Denbury and the
construction of CO2 and crude oil pipelines to access Denbury's crude oil
fields in Mississippi. Denbury owns additional CO2 industrial sales contracts
that we might be able to purchase along with additional volume under our
production payment. We may also construct and operate CO2 pipelines next to
crude oil pipelines to supply Denbury's fields with the CO2 for tertiary
recovery and then to move the resulting crude oil production to market. We will
also look for opportunities to acquire assets from other parties that meet our
criteria for stable cash flows.
Capital Resources
In March 2003, we entered into a $65 million three-year credit
facility with a group of banks with Fleet National Bank as agent ("Fleet
Facility"). The Fleet Facility 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 Facility are as follows:
- Letter of credit fees are based on the usage of the Fleet
Facility in relation to the borrowing base and will range from
2.00% to 3.00%. At December 31, 2003, the rate was 2.00%.
- The interest rate on working capital borrowings is also based
on the usage of the Fleet Facility in relation to the
borrowing base. Loans may be 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%. At December 31, 2003, we borrowed at the prime rate
plus 1.00%.
33
- We pay a commitment fee on the unused portion of the $65
million commitment. This commitment fee is also based on the
usage of the Fleet Facility in relation to the borrowing base
and will range from 0.375% to 0.50%. At December 31, 2003, the
commitment fee rate was 0.375%.
- 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 is defined in
the Fleet Facility generally to include cash balances, net
accounts receivable and inventory, less deductions for certain
accounts payable, and is calculated monthly.
- Collateral under the Fleet Facility consists of our accounts
receivable, inventory, cash accounts, margin accounts and
fixed assets.
- The Fleet Facility contains covenants requiring a minimum
current ratio, a minimum leverage ratio, a minimum cash flow
coverage ratio, a maximum ratio of indebtedness to
capitalization, a minimum EBITDA (earnings before interest,
taxes, depreciation and amortization), and limitations on
distributions to Unitholders.
We were in compliance with the Fleet Facility covenants at December
31, 2003.
Under the Fleet Facility, distributions to Unitholders and the
General Partner can only be made if the Borrowing Base exceeds the usage by
certain amounts. See additional discussion below under "Distributions".
At December 31, 2003, we had $7.0 million outstanding under the
Fleet Facility. Due to the revolving nature of loans under the Fleet Facility,
additional borrowings and periodic repayments and re-borrowings may be made
until the maturity date of March 14, 2006. At December 31, 2003, we had letters
of credit outstanding under the Fleet Facility totaling $21.6 million, comprised
of $10.0 million and $10.8 million for crude oil purchases related to December
2003 and January 2004, respectively and $0.8 million related to other business
obligations. Outstanding letters of credit issued to Denbury for the purchase of
crude oil at December 31, 2003, totaled $12.5 million, and are included in the
$21.6 million total above. In February 2004, Denbury agreed to reduce by half
its requirement to provide Denbury with letters of credit for our crude oil
purchases from them.
Sources of Future Capital
Prior to 2003, we funded our capital commitments from operating cash
and borrowings under bank facilities. In 2003, we issued common units to our
general partner for cash and sold assets to fund growth. Our plans for the
future include a combination of borrowings and the issuance of additional common
units to the public.
We have entered into discussions with Fleet National Bank regarding
an expansion of our existing credit facility from $65 million to $100 million.
We would like to reduce the amount of the facility committed to letters of
credit and working capital borrowings from $65 million to $50 million and have
$50 million available for acquisitions. We are in discussions with Fleet to
determine the terms of the expanded facility.
We may consider raising capital through an equity offering of
additional common units if we make acquisitions using an expanded credit
facility. Any such proceeds could be used to reduce the outstanding balances
under the credit facility thereby freeing up debt capacity to use for additional
accretive acquisitions. An equity offering would probably not occur before the
fourth quarter of 2004.
Distributions
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. Normally we 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 Cash consists generally of all of our cash receipts
less cash disbursements adjusted for net changes to reserves. The target minimum
quarterly distribution ("MQD") for each quarter is $0.20 per unit. For 2001, we
paid distributions of $0.20 per unit ($1.8 million in total) per quarter for the
first three quarters. For the fourth quarter of 2001 and for all of 2002, we did
not pay any regular quarterly distributions. We did pay a special distribution
of $0.20 per unit ($1.7 million in total) in December 2002 to help mitigate the
tax effects of income allocations for that year. Beginning with the distribution
for the first quarter of 2003, we paid a regular quarterly distribution of $0.05
per unit ($0.4 million in total per quarter). For the fourth quarter of 2003, we
increased our quarterly distribution to $0.15 per unit ($1.4 in total), which
was paid in February 2004.
34
Under the Fleet Agreement, a provision requires that the Borrowing
Base exceed the usage under the Fleet Agreement by at least $10 million plus the
distribution measured once each month in order for us to make a distribution for
the quarter.
Our general partner is entitled to receive incentive distributions
if the amount we distribute with respect to any quarter exceeds levels specified
in our partnership agreement. Under the quarterly incentive distribution
provisions, the general partner generally is entitled to receive 13.3% of any
distributions in excess of $0.25 per unit, 23.5% of any distributions in excess
of $0.28 per unit and 49% of any distributions in excess of $0.33 per unit
without duplication. We have not paid any incentive distributions through
December 31, 2003. The likelihood and timing of the payment of any incentive
distributions will depend on our ability to make accretive acquisitions and
generate cash flows from of those acquisitions. We do not expect to make
incentive distributions during 2004.
We believe we will be able to sustain a regular quarterly
distribution at $0.15 per unit during 2004. We do not expect to be able to
restore the distribution to the targeted minimum quarterly distribution level of
$0.20 per unit until 2005. 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.
Available Cash before reserves for the year ended December 31, 2003,
is as follows (in thousands):
Net income................................................... $ 13,322
Depreciation and amortization................................ 6,504
Excluded gain from asset sales............................... (13,088)
Cash proceeds in excess of gains on certain asset sales...... 879
Non-cash charges............................................. 229
Maintenance capital expenditures............................. (4,176)
-----------
Available Cash before reserves............................... $ 3,670
===========
Available Cash (a non-GAAP liquidity measure) has been reconciled to
cash flow from operating activities (the GAAP measure) for the year ended
December 31, 2003 below.
The non-GAAP financial measure of Available Cash is calculated in
accordance with generally accepted accounting principles (GAAP), with the
exception of maintenance capital expenditures as used in our calculation of
Available Cash. Maintenance capital expenditures are capital expenditures (as
defined by GAAP) to replace or enhance partially or fully depreciated assets in
order to sustain the existing operating capacity or efficiency of our assets and
extend their useful lives.
We believe that investors benefit from having access to the same
financial measures being utilized by management. Available Cash is a liquidity
measure used by our management to compare cash flows generated by the
Partnership to the cash distribution we pay to our limited partners and the
general partner. This is an important financial measure to our public
unitholders since it is an indicator of our ability to provide a cash return on
their investment. Specifically, this financial measure tells investors whether
or not the Partnership is generating cash flows at a level that can support a
quarterly cash distribution to our partners. Lastly, Available Cash (also
referred to as distributable cash flow) is a quantitative standard used
throughout the investment community with respect to publicly-traded
partnerships.
Several adjustments to net income are required to calculate
Available Cash. These adjustments include: (1) the addition of non-cash expenses
such as depreciation and amortization expense; (2) miscellaneous non-cash
adjustments such as the addition of decreases or the subtraction of increases in
the value of financial instruments; and (3) the subtraction of maintenance
capital expenditures. See "Distributions" above.
The reconciliation of Available Cash (a non-GAAP liquidity measure)
to cash flow from operating activities (the GAAP measure) for the year ended
December 31, 2003, is as follows (in thousands):
35
Year
Ended
December 31,
2003
------------
Cash flows from operating activities................................. $ 4,693
Adjustments to reconcile operating cash flows to Available Cash:
Maintenance capital expenditures................................. (4,176)
Proceeds from sales of certain assets............................ 1,055
Change in fair value of derivatives.............................. (39)
Amortization of credit facility issuance fees.................... (1,031)
Net effect of changes in operating accounts not
included in calculation of Available Cash..................... 3,168
---------
Available Cash before reserves....................................... $ 3,670
=========
COMMITMENTS AND OFF-BALANCE SHEET ARRANGEMENTS
Contractual Obligation and Commercial Commitments
In addition to the Fleet Facility discussed above, we have
contractual obligations under operating leases as well as commitments to
purchase crude oil. The table below summarizes our obligations and commitments
at December 31, 2003 (in thousands).
Payments Due by Period
-----------------------------------------------------------------
Less than 1 - 3 4 - 5 After 5
Contractual Cash Obligations 1 Year Years Years Years Total
-------- -------- -------- -------- --------
Long-term Debt ..................... $ -- $ 7,000 $ -- $ -- $ 7,000
Operating Leases ................... 3,048 3,539 1,074 935 8,596
Pennzoil litigation
settlement ...................... 12,750 -- -- -- 12,750
Mississippi oil spill fine ......... 3,000 -- -- -- 3,000
Offshore pipeline
removal ......................... 700 -- -- -- 700
Unconditional Purchase
Obligations ..................... 89,436 -- -- -- 89,436
-------- -------- -------- -------- --------
Total Contractual Cash
Obligations ..................... $108,934 $ 10,539 $ 1,074 $ 935 $121,482
======== ======== ======== ======== ========
In December 2003, our insurers settled litigation with
Pennzoil-Quaker State for $12.8 million. (see Note 18 to the consolidated
financial statements.) We have recorded in accrued liabilities on our
consolidated statement of operations the obligation for this settlement, and we
have recorded the insurance reimbursement for this obligation in insurance
receivable. The settlement was funded in February 2004, with certain insurance
companies directly funding $5.9 million of the payment and with our funding the
remaining $6.9 million. We expect to receive reimbursement from the insurance
company no later than May 2004.
We expect to pay the estimated $3.0 million fine related to the
Mississippi oil spill that occurred in 1999 (see Note 18 to the consolidated
financial statements) during the second quarter of 2004. We expect to incur
approximately $0.7 million to remove an abandoned offshore pipeline during the
second quarter of 2004.
While the temporary funding of the litigation settlement and the
payment of the fine and pipeline removal costs will increase our average
outstanding debt during 2004, we believe we have sufficient capacity under the
Fleet Facility to meet these obligations.
Off-Balance sheet Arrangements
We have no off-balance sheet arrangements, special purpose entities,
or financing partnerships, other than as disclosed in this section, nor do we
have any debt or equity triggers based upon our unit or commodity prices.
36
OTHER MATTERS
Risk Factors Related to Our Business
The success of our crude oil gathering, marketing and pipeline
operations is dependent upon increases in the availability of crude oil supplies
and our ability to secure those supplies. Securing additional supplies of crude
oil from increased production by oil companies and by aggressive lease gathering
efforts depends partially on the ability of oil producers to increase
production. Factors affecting an increase in production can include the
prevailing market price for oil, the exploration and production budgets of the
major and independent oil companies, the depletion rate of existing reservoirs,
the success of new wells drilled, environmental concerns, regulatory initiatives
and other matters that are beyond our control.
The profitability of our crude oil gathering and marketing
operations depends primarily on the volumes of crude oil we purchase and gather.
Natural declines in crude oil production from depleting wells or volumes lost to
competitors must be replaced by contracts for new supplies of crude oil so as to
maintain the volumes of crude oil we purchase. Replacement of lost volumes of
crude oil is particularly difficult in an environment where production is low
and competition to gather available production is intense. Generally, because
producers experience inconveniences in switching crude oil purchasers, such as
delays in receipt of proceeds while awaiting the preparation of new division
orders, producers typically do not change purchasers on the basis of minor
variations in price. Thus, we may experience difficulty acquiring crude oil at
the wellhead in areas where there are existing relationships between producers
and other gatherers and purchasers of crude oil.
Our operations are dependent upon demand for crude oil by refiners
in the Gulf Coast and Midwest. Any decrease in this demand could adversely
affect our business. This demand is dependent on the impact of future economic
conditions, fuel conservation measures, alternative fuel requirements,
government regulation or technological advances in fuel economy and energy
generation devices, all of which could reduce demand.
We face intense competition in our crude oil gathering and marketing
activities. Our competitors include independent gatherers, the major integrated
oil companies and their marketing affiliates and other marketers of various
sizes, financial resources and experience. Many of these competitors have
capital resources many times greater than ours and control much greater supplies
of crude oil.
We are exposed to the credit risk of our customers in the ordinary
course of our crude oil gathering and marketing operations. There can be no
assurance that we have adequately assessed the credit worthiness of our existing
or future counter-parties or that there will not be an unanticipated
deterioration in their credit worthiness, which could have an adverse impact on
us. In those cases where we provide division order services for crude oil
purchased at the wellhead, we may be responsible for the distribution of
proceeds to all parties. In other cases, we pay all or a portion of the
production proceeds to an operator who distributes these proceeds to the various
interest owners. These arrangements expose us to operator credit risk, and there
can be no assurance that we will not experience losses in dealings with other
parties.
The profitability of our crude oil pipeline operations depends on
the volume of crude oil shipped by third parties and on our interconnections
with other crude oil pipelines. Third-party shippers do not have long-term
contractual commitments to ship crude oil on our pipelines. A decision by a
shipper to substantially reduce or cease to ship volumes of crude oil on our
pipelines could cause a significant decline in our revenues. Additionally, in
Mississippi, we are dependent on interconnections with other pipelines to
provide shippers with a market for their crude oil, and in Texas, we are
dependent on interconnections with other pipelines to provide shippers with
transportation to our pipeline. Any reduction of throughput available to our
shippers on these interconnecting pipelines as a result of testing, pipeline
repair, reduced operating pressures or other causes could result in reduced
throughput on our pipelines that would adversely affect our profitability.
Fluctuations in demand for crude oil, such as caused by refinery
downtime or shutdowns, can negatively affect our operating results. Reduced
demand in areas we service with our pipelines can result in less demand for our
transmission services.
Our operations are subject to federal and state environmental and
safety regulations and laws related to environmental protection and operational
safety. Our crude oil gathering and pipeline operations are subject to the risk
of incurring substantial environmental and safety related costs and liabilities.
These costs and liabilities could rise under increasingly strict environmental
and safety laws, including regulations and enforcement policies, or
37
claims for damages to property or persons resulting from our operations. If we
are unable to recover such resulting costs through greater margins, higher
tariffs or insurance reimbursements; our cash flows and results of operations
could be materially impacted. The transportation and storage of crude oil
results in a risk that crude oil and related hydrocarbons may be suddenly or
gradually released into the environment, potentially causing substantial
expenditures for a response action, significant government penalties, liability
to government agencies for natural resources damages, liability to private
parties for personal injury or property damages, and significant business
interruption.
Certain of our field and pipeline operating costs and expenses are
fixed and do not vary with the volumes we gather and transport. These costs and
expenses may not decrease ratably or at all should we experience a reduction in
our volumes gathered by truck or transmitted by our pipelines. As a result, we
may experience declines in segment margin and profitability should our volumes
decrease.
Our CO2 operations are exposed to risks related to Denbury's
operation of their CO2 fields, equipment and pipeline. Because Denbury produces
the CO2 and transports the CO2 to our customers, any long-term failure of their
operations could have an impact on our ability to meet our obligations to our
CO2 customers. We have no other supply of CO2 or method to transport it to our
customers.
Fluctuations in demand for CO2 by our industrial customers could
materially impact our profitability. Our customers are not contractually
obligated to purchase volumes in excess of the take-or-pay amounts in the
contracts. The customers have processing facilities located at the delivery
points on Denbury's pipeline. Fluctuations in their demand due to market forces
or operational problems could result in a reduction in our revenues from the
sales of CO2.
The CO2 supplied by Denbury to us for our sale to our customers
could fail to meet the quality standards in the contracts due to impurities or
water vapor content. If the CO2 were below specifications, we could be
contractually obligated to provide compensation to our customers for the costs
incurred in raising the CO2 quality to serviceable levels.
Our wholesale CO2 industrial marketing operations are dependent on
three customers. Should one or more of those customers experience financial
difficulties such that they fail to purchase their required minimum take-or-pay
volume and fail to compensate us for the lost revenue, our profitability could
be materially impacted. The three customers appear to be credit worthy, however
there can be no assurance that an unanticipated deterioration in their ability
to meet their obligations to us might not occur.
Newly acquired properties could expose us to environmental
liabilities and increased regulatory compliance costs. Our business plan
includes making acquisitions to increase our cash flows. Assets that we may
acquire will likely have associated environmental liabilities, as well as
required compliance with regulations such as the integrity management program
for regulated pipelines. Although we will attempt to identify such exposures and
address the associated costs through indemnities, purchase price adjustments or
insurance, we may incur costs not covered by indemnity, insurance or reserves.
Cash distributions are not guaranteed and may fluctuate with our
performance and the establishment of reserves. Because distributions to our
unitholders are dependent on the amount of cash we generate, distributions may
fluctuate based on our performance. The actual amount of cash that is available
to be distributed each quarter will depend on numerous factors, some of which
are beyond our control and the control of our general partner. Cash
distributions are dependent primarily on cash flow, including cash flow from
financial reserves and working capital borrowings, and not solely on
profitability, which is affected by non-cash items. Therefore, cash
distributions might be made in periods when we record losses and might not be
made during periods when we record profits.
The terms of our credit facility may limit our ability to borrow
additional funds, make distributions to unitholders, or capitalize on business
opportunities. Our credit facility includes limitations on our ability to make
distributions to our unitholders and require approval of lenders to take certain
actions. Any refinancing of our current indebtedness or any new indebtedness
could have similar or greater restrictions.
Our tax treatment depends on our status as a partnership for federal
income tax purposes, as well as our not being subject to entity-level taxation
by states. If the IRS treats us as a corporation or we become subject to
entity-level taxation for state tax purposes, it could substantially reduce
distributions to our unitholders and might reduce
38
our ability to grow the business. The after-tax benefit of an investment in our
common units depends largely on our being treated as a partnership for federal
and state income tax purposes. If we were classified as a corporation for
federal income tax purposes, we would pay federal income tax on our income at
the corporate rate. Some or all of the distributions made to unitholders would
be treated as dividend income, and no income, gains, losses or deductions would
flow through to unitholders. Treatment of us as a corporation would cause a
material reduction in the anticipated cash flow and after-tax return to the
unitholders.
We believe a substantial number of our Common Units are held by
entities that derive a tax benefit from investment in partnership-type entities
with large gross receipts. Should a change occur such that our revenues declined
to a level that these investors might find alternative sources for this tax
benefit other than by ownership in our Common Units, an adverse change in our
unit price could take place. This condition could occur at the same time that we
would be growing our distribution or otherwise increasing the value of our
Common Units to the general investing public.
Crude Oil Contamination
We were named one of the defendants in a complaint filed on January
11, 2001, in the 125th District Court of Harris County, Texas, cause No.
2001-01176. Pennzoil-Quaker State Company ("PQS") was seeking property damages,
loss of use and business interruption suffered as a result of a fire and
explosion that occurred at the Pennzoil Quaker State refinery in Shreveport,
Louisiana, on January 18, 2000. PQS claimed the fire and explosion were caused,
in part, by Genesis selling to PQS crude oil that was contaminated with organic
chlorides. In December 2003, our insurers settled this litigation for $12.8
million. We have recorded in accrued liabilities on our consolidated balance
sheet the obligation for this settlement, and, in insurance receivable, we have
recorded the insurance reimbursement for this obligation. The settlement was
funded in February 2004, with certain insurance companies directly funding $5.9
million of the payment and $6.9 million funded by us. We expect to receive
reimbursement from the insurance company no later than May 2004 for the portion
funded by us. The settlement of this litigation had no effect on our results of
operations.
PQS is also a defendant in five suits brought by neighbors living in
the vicinity of the PQS Shreveport, Louisiana refinery in the First Judicial
District Court, Caddo Parish, Louisiana, cause nos. 455,647-A. 455,658-B,
455,655-A, 456,574-A, and 458,379-C. PQS has brought third party demand against
Genesis and others for indemnity with respect to the fire and explosion of
January 18, 2000. We believe that the demand against Genesis is without merit
and intend to vigorously defend ourselves in this matter.
Insurance
We maintain insurance of various types that we consider adequate to
cover our operations and properties. The insurance policies are subject to
deductibles that we consider reasonable. The policies do not cover every
potential risk associated with operating our assets, including the potential for
a loss of significant revenues. Consistent with the coverage available in the
industry, our policies provide limited pollution coverage, with broader coverage
for sudden and accidental pollution events. Additionally, as a result of the
events of September 11, the cost of insurance available to the industry has
risen significantly, and insurers have excluded or reduced coverage for losses
due to acts of terrorism and sabotage.
Since September 11, 2001, warnings have been issued by various
agencies of the United States Government to advise owners and operators of
energy assets that those assets may be a future target of terrorist
organizations. Any future terrorist attacks on our assets, or assets of our
customers or competitors could have a material adverse effect on our business.
We believe that we are adequately insured for public liability and
property damage to others as a result of our operations. However, no assurances
can be given that an event not fully insured or indemnified against will not
materially and adversely affect our operations and financial condition.
Additionally, no assurance can be given that we will be able to maintain
insurance in the future at rates that we consider reasonable.
NEW ACCOUNTING PRONOUNCEMENTS
SFAS 143
In June, 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." This statement requires entities to record the fair
value of a liability for legal obligations associated with the retirement
39
obligations of tangible long-lived assets in the period in which it is incurred.
When the liability is initially recorded, a corresponding increase in the
carrying amount of the related long-lived asset would be recorded. Over time,
accretion of the liability is recognized each period, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss on settlement. The standard was effective for us on
January 1, 2003.
With respect to our pipelines, federal regulations require us to
purge the crude oil from our pipelines when the pipelines are retired. Our right
of way agreements do not require us to remove pipe or otherwise perform
remediation upon taking the pipelines out of service. Many of our truck unload
stations are on leased sites that require that we remove our improvements upon
expiration of the lease term. For our pipelines, we are unable to reasonably
estimate and record liabilities for the majority of our obligations that fall
under the provisions of this statement because we cannot reasonably estimate
when such obligations would be settled. For the truck unload stations, the site
leases have provisions such that the lease continues until one of the parties
gives notice that it wishes to end the lease. At this time we cannot reasonably
estimate when such notice would be given and when the obligations to remove our
improvements would be settled. We will record asset retirement obligations in
the period in which we determine the settlement dates.
In the third quarter of 2003, we recorded an obligation to remove a
pipeline from offshore waters as a result of this standard. This pipeline has
been out of service since 1998. The State of Louisiana advised us that the
pipeline should be removed. We expect to remove this pipeline during 2004.
SFAS 145
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt" and an amendment of that statement, SFAS No. 64,
"Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." SFAS No.
145 also rescinds SFAS No. 44, "Accounting for Intangible Assets of Motor
Carriers." SFAS No. 145 also amends SFAS No. 13, "Accounting for Leases," to
eliminate an inconsistency between the required accounting for sale-leaseback
transactions and the required accounting for certain lease modifications that
have economic effects that are similar to sale-leaseback transactions. SFAS No.
145 also amends other existing authoritative pronouncements to make various
technical corrections, clarify meanings, or describe their applicability under
changed conditions. The provisions related to the rescission of SFAS No. 4 were
applied in fiscal years beginning after May 15, 2002. The provisions related to
SFAS No. 13 were effective for transactions occurring after May 15, 2002. All
other provisions were effective for financial statements issued on or after May
15, 2002, with early application encouraged. The adoption of this statement did
not have a material effect on our results of operations.
SFAS 146
On January 1, 2003, we adopted SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities," which addresses accounting for
restructuring and similar costs. This statement requires that the liability for
costs associated with an exit or disposal activity be recognized when the
liability is incurred rather than at the date of commitment to an exit plan.
This adoption of this statement on January 1, 2003, had no material impact on
our financial statements. During the third quarter of 2003, we recorded
termination benefits related to the sale of our Texas Gulf Coast operations and,
in the fourth quarter of 2003, recorded the sale of those operations. See Note
11 to the consolidated financial statements.
Interpretation No. 45
We implemented FASB Interpretation No. 45, "Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others" as of December 31, 2002. This interpretation of SFAS No.
5, 57 and 107, and rescission of FASB Interpretation No. 34 elaborates on the
disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under certain guarantees that it has issued. It
also clarifies that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligation undertaken in
issuing the guarantee. The information required by this interpretation is
included in Note 18 to the consolidated financial statements.
40
Interpretation No 46
In January 2003, the FASB issued Interpretation No. 46,
"Consolidation of Variable Interest Entities," and amended the Interpretation in
December 2003. The interpretation states that certain variable interest entities
(VIE) may be required to be consolidated into the results of operations and
financial position of the entity that is the primary beneficiary. The provisions
of the interpretation were effective immediately for VIEs created after January
15, 2003. We do not have any VIEs. The adoption of this interpretation in 2003
had no effect on our financial statements.
SFAS 148
We adopted SFAS No. 148, "Accounting for Stock-Based
Compensation-Transition and Disclosure," as of January 1, 2003. This statement
provides alternative methods of transition from a voluntary change to the fair
value based method of accounting for stock-based employee compensation and
amends the disclosure requirements of SFAS No. 123 in both annual and interim
financial statements. As there are no outstanding grants of Partnership units
under any compensation plans of the Partnership, the adoption of this statement
had no effect on our financial position, results of operations, cash flows or
disclosure requirements.
SFAS 149
On April 30, 2003, the FASB issued SFAS No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities." This statement
amends and clarifies accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities
under SFAS No. 133. This statement is effective for contracts entered into or
modified after June 30, 2003, for hedging relationships designated after June
30, 2003, and to certain preexisting contracts. We adopted SFAS No. 149 on July
1, 2003. The adoption of this statement had no effect on our financial position,
results of operations or cash flows.
SFAS 150
In May 2003, The FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity". SFAS
No. 150 establishes standards for how an issuer classifies and measures certain
freestanding instruments with characteristics of both liabilities and equity.
SFAS No. 150 requires that an issuer classify a financial instrument that is
within its scope as a liability (or asset in some circumstances). We adopted
SFAS No. 150 effective July 1, 2003. The adoption of this statement had no
effect on our financial position, results of operations or cash flows.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our primary price risk relates to the effect of crude oil price
fluctuations on our inventories and the fluctuations each month in grade and
location differentials and their effect on future contractual commitments. We
utilize NYMEX commodity based futures contracts and forward contracts to hedge
our exposure to these market price fluctuations as needed. At December 31, 2003,
we had no contracts outstanding.
At December 31, 2003, we held 49,000 barrels of crude oil in
inventory with a carrying cost of $1.5 million. The market value of this
inventory at December 31, 2003 was $30,000 greater than its cost.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required hereunder is included in this report as set
forth in the "Index to Consolidated Financial Statements" on page 52.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
None.
ITEM 9A. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures and internal controls
designed to ensure that information required to be disclosed in our filings
under the Securities Exchange Act of 1934 is recorded, processed, summarized and
reported within the time periods specified in the Securities and Exchange
Commission's rules and forms. Our chief executive officer and chief financial
officer have evaluated our disclosure controls and procedures as of the end of
the period covered by this Annual Report on Form 10-K and have determined that
such disclosure
41
controls and procedures are adequate and effective in all material respects in
providing to them on a timely basis material information relating to us
(including our consolidated subsidiaries) required to be disclosed in this
annual report.
There have been no significant changes in our internal controls over
financial reporting during the three months ended December 31, 2003, that have
materially affected, or are reasonably likely to materially affect, our internal
controls over financial reporting.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
We do not directly employ any persons responsible for managing or
operating the Partnership or for providing services relating to day-to-day
business affairs. The General Partner provides such services and is reimbursed
for its direct and indirect costs and expenses, including all compensation and
benefit costs.
The Board of Directors of the General Partner (the "Board") consists
of eight persons. Four of the directors, including the Chairman of the Board,
are executives of Denbury. Our Chief Executive Officer serves on the Board. The
three remaining directors are independent of Genesis and Denbury or any of its
affiliates.
Directors and Executive Officers of the General Partner
Set forth below is certain information concerning the directors and
executive officers of the General Partner. All executive officers serve at the
discretion of the General Partner.
Name Age Position
---- --- --------
Gareth Roberts................ 51 Director and Chairman of the Board
Mark J. Gorman................ 49 Director, Chief Executive Officer and President
Ronald T. Evans............... 41 Director
Herbert I. Goodman............ 81 Director
Susan O. Rheney............... 44 Director
Phil Rykhoek.................. 47 Director
J. Conley Stone............... 72 Director
Mark A. Worthey............... 46 Director
Ross A. Benavides............. 50 Chief Financial Officer, General Counsel and Secretary
Kerry W. Mazoch............... 57 Vice President, Crude Oil Acquisitions
Karen N. Pape................. 46 Vice President and Controller
Gareth Roberts has served as a Director and Chairman of the Board of
the General Partner since May 2002. Mr. Roberts is President, Chief Executive
Officer and a director of Denbury Resources Inc. and has served in those
capacities since 1992. Mr. Roberts also serves on the board of directors of
Belden & Blake Corporation.
Mark J. Gorman has served as a Director of the General Partner since
December 1996 and as President and Chief Executive Officer since October 1999.
From December 1996 to October 1999 he served as Executive Vice President and as
Chief Operating Officer from October 1997 to October 1999. He was President of
Howell Crude Oil Company, a wholly-owned subsidiary of Howell Corporation, from
September 1992 to December 1996.
Ronald T. Evans has served as a director of the General Partner
since May 2002. Mr. Evans is Senior Vice President of Reservoir Engineering of
Denbury and has served in that capacity since September 1999. Before joining
Denbury, Mr. Evans was employed as Engineering Manager with Matador Petroleum
Corporation for three years and employed by Enserch Exploration, Inc. for twelve
years in various positions.
Herbert I. Goodman has served as a director of the General Partner
since January 1997. He is the Chairman of IQ Holdings, Inc., a manufacturer and
marketer of petrochemical-based consumer products. During 2001, he served as the
Chief Executive Officer of PEPEX.NET, LLC, which provides electronic trading
solutions to the international oil industry. Since 2002 he has served as
Chairman of PEPEX.NET, LLC. From 1988 until 1996 he was Chairman and Chief
Executive Officer of Applied Trading Systems, Inc., a trading and consulting
business.
42
Susan O. Rheney became a Director of the General Partner in March
2002. Ms. Rheney is a private investor and formerly was a principal of The
Sterling Group, L.P., a private financial and investment organization, from 1992
to 2000. Ms. Rheney is a director of Texas Petrochemical Holdings, Inc., a
chemical manufacturer, where she serves on the audit and finance committees. She
is also a director of Mail-Well, Inc., a supplier of printing services and
products, where she serves on the audit and governance and nominating
committees.
Phil Rykhoek has served as a director of the General Partner since
May 2002. Mr. Rykhoek is Chief Financial Officer, Senior Vice President,
Secretary and Treasurer of Denbury, and has served in those capacities since
1995.
J. Conley Stone has served as a director of the General Partner
since January 1997. From 1987 to his retirement in 1995, he served as President,
Chief Executive Officer, Chief Operating Officer and Director of Plantation Pipe
Line Company, a common carrier liquid petroleum products pipeline transporter.
Mark A. Worthey has served as a director of the General Partner
since May 2002. Mr. Worthey is Senior Vice President, Operations for Denbury and
has been with Denbury since September 1992.
Ross A. Benavides has served as Chief Financial Officer of the
General Partner since October 1998. He has served as General Counsel and
Secretary since December 1999.
Kerry W. Mazoch has served as Vice President, Crude Oil
Acquisitions, of the General Partner since August 1997. From 1991 to 1997 he
held the position of Vice President and General Manager of Crude Oil
Acquisitions at Northridge Energy Marketing Corp., a wholly-owned subsidiary of
TransCanada Pipelines Limited.
Karen N. Pape was named Vice President and Controller of the General
Partner effective in March 2002. Ms. Pape has served as Controller and as
Director of Finance and Administration of the General Partner since December
1996. From 1990 to 1996, she was Vice President and Controller of Howell
Corporation.
Board Committees
The Audit Committee consists of Susan O. Rheney, Herbert I. Goodman and J.
Conley Stone. The Audit Committee has been established in accordance with SEC
rules and regulations, and all members are independent directors as defined
under the rules of the American Stock Exchange. The Board of Directors believes
that Susan O. Rheney qualifies as an audit committee financial expert as such
term is used in the rules and regulations of the SEC. The committee engages our
independent auditors and oversees our independence from the auditors,
pre-approves any services provided by our independent auditors, oversees the
quality and integrity of our financial reports and our systems of internal
controls with respect to finance, accounting, legal compliance and ethics, and
oversees our anonymous complaint procedure established for our employees. The
Audit Committee adopted a written Audit Committee charter on August 7, 2003. The
full text of the Audit Committee charter is available on our website.
Additionally, the General Partner is authorized to seek special approval
from the Audit Committee of any resolution of a potential conflict of interest
between the General Partner or of any of its affiliates and the Partnership or
any of its affiliates.
The Board has established a compensation committee to oversee compensation
decisions for the employees of the General Partner, as well as the compensation
plans of the General Partner. The members of the Compensation Committee are
Gareth Roberts, Susan O. Rheney and Herbert I. Goodman, all of whom are
non-employee directors of the General Partner.
Code of Ethics
We have adopted a code of ethics that is applicable to, among others, the
principal financial officer and the principal accounting officer. The Genesis
Energy Financial Employee Code of Professional Conduct is posted at our website,
where we intend to report any changes or waivers.
Section 16(a) Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires the officers
and directors of the General Partner and persons who own more than ten percent
of a registered class of the equity securities of the Partnership to file
reports of ownership and changes in ownership with the SEC and the American
Stock Exchange. Based solely on its review of the copies of such reports
received by it, or written representations from certain reporting persons that
43
no Forms 5 was required for those persons, we believe that during 2003 its
officers and directors complied with all applicable filing requirements in a
timely manner.
ITEM 11. EXECUTIVE COMPENSATION
EXECUTIVE OFFICER COMPENSATION
Under the terms of the Partnership Agreement, we are required to
reimburse the General Partner for expenses relating to the operation of the
Partnership, including salaries and bonuses of employees employed on behalf of
the Partnership, as well as the costs of providing benefits to such persons
under employee benefit plans and for the costs of health and life insurance. See
"Certain Relationships and Related Transactions."
Summary Compensation Table
The following table summarizes certain information regarding the
compensation paid or accrued by Genesis during 2003, 2002, and 2001 to the Chief
Executive Officer and each of our three other executive officers (the "Named
Officers").
Long-Term
Compensation
Annual Compensation Awards
-------------------------------------- ---------------
Securities
Other Annual underlying All Other
Salary Bonus Compensation SARs Granted(2) Compensation
Name and Principal Position Year $ $ $(1) # $
- --------------------------- ---- ------- ----- ------------ --------------- ------------
Mark J. Gorman 2003 275,000 4,070 12,755 23,620 15,000(3)
Chief Executive Officer 2002 270,000 5,193 -- -- 11,500(4)
and President 2001 270,000 56,814 -- -- 10,200(5)
Ross A. Benavides 2003 185,000 2,738 8,580 15,889 13,803(6)
Chief Financial Officer, 2002 180,000 3,462 -- -- 11,500(4)
General Counsel and 2001 175,000 54,785 -- -- 10,200(5)
Secretary
Kerry W. Mazoch 2003 175,000 2,590 8,116 15,030 13,023(7)
Vice President, Crude 2002 170,000 3,270 -- -- 11,478(8)
Oil Acquisitions 2001 169,000 30,720 -- -- 10,200(5)
Karen N. Pape 2003 141,000 2,094 6,563 12,153 10,533(9)
Vice President and 2002 136,000 2,616 -- -- 10,118(10)
Controller
(1) Represents the value deemed to have been "earned" during the year
under the Stock Appreciation Rights Plan discussed below. No Named
Officer had other "Perquisites and Other Personal Benefits" with a
value greater than the lesser of $50,000 or 10% of reported salary
and bonus.
(2) SARs are Stock Appreciation Rights. See additional information in
the table below.
(3) Includes $9,000 of Company-matching contributions to a defined
contribution plan and $6,000 of profit-sharing contributions to a
defined contribution plan.
(4) Includes $5,500 of Company-matching contributions to a defined
contribution plan and $6,000 of profit-sharing contributions to a
defined contribution plan.
(5) Includes $5,100 of Company-matching contributions to a defined
contribution plan and $5,100 of profit-sharing contributions to a
defined contribution plan.
(6) Includes $8,282 of Company-matching contributions to a defined
contribution plan and $5,521 of profit-sharing contributions to a
defined contribution plan.
(7) Includes $7,802 of Company-matching contributions to a defined
contribution plan and $5,521 of profit-sharing contributions to a
defined contribution plan
44
(8) Includes $5,500 of Company-matching contributions to a defined
contribution plan and $5,978 of profit-sharing contributions to a
defined contribution plan.
(9) Includes $6,320 of Company matching contributions to a defined
contribution plan and $4,213 of profit-sharing contributions to a
defined contribution plan.
(10) Includes $5,059 of Company-matching contributions to a defined
contribution plan and $5,059 of profit-sharing contributions to a
defined contribution plan.
Stock Appreciation Rights Plan
In December 2003, the Board approved a Stock Appreciation Rights
plan for all employees. Under the terms of this plan, all regular, full-time
active employees and the members of the Board are eligible to participate in the
plan. The plan is administered by the Compensation Committee of the Board, who
shall determine, in its full discretion, the number of rights to award, the
grant date of the units and the formula for allocating rights to the
participants and the strike price of the rights awarded. Each right is
equivalent to one Common Unit. The rights have a term of 10 years from the date
of grant. The initial award to a participant will vest one-fourth each year
beginning with the first anniversary of the grant date of the award. Subsequent
awards to participants will vest on the fourth anniversary of the grant date. If
the right has not been exercised at the end of the ten year term and the
participant has not terminated employment with us, the right will be deemed
exercised as of the date of the right's expiration and a cash payment will be
made as described below.
Upon vesting, the participant may exercise his rights to receive a
cash payment equal to the difference between the average of the closing market
price of Genesis Energy, L.P. Common Units for the ten days preceding the date
of exercise over the strike price of the right being exercised. The cash payment
to the participant will be net of any applicable withholding taxes required by
law. If the Committee determines, in its full discretion, that it would cause
significant financial harm to the Partnership to make cash payments to
participants who have exercised rights under the plan, then the Committee may
authorize deferral of the cash payments until a later date.
Termination for any reason other than death, disability or normal
retirement (as these terms are defined in the plan) will result in the
forfeiture of any non-vested rights. Upon death, disability or normal
retirement, all rights will become fully vested. If a participant is terminated
for any reason within one year after the effective date of a change in control
(as defined in the plan) all rights will become fully vested.
On December 31, 2003, the initial award of rights was made to
employees and directors. The following tables show the stock appreciation rights
granted to the Executive Officers and the values of the stock appreciation
rights at December 31, 2003. Information on rights granted to non-employee
directors is included in the section entitled Director Compensation.
SAR Grants During the Year Ended December 31, 2003
Individual Grants
- -------------------------------------------------------------------------------------------- Potential realizable value at
Number of Percent Grant assumed annual rates of
Securities of total date stock price appreciation
underlying SARs granted Exercise closing for SAR term
SARs to employees price price Expiration -----------------------------
Name granted (#) in fiscal year $/Unit $/Unit date 5%($) 10%($)
- ----------------- ----------- -------------- -------- ------- ---------- ------- -------
Mark J. Gorman 23,620 5.8% 9.26 9.80 12/31/2013 137,553 348,585
Ross A. Benavides 15,889 3.9% 9.26 9.80 12/31/2013 92,531 234,491
Kerry W. Mazoch 15,030 3.7% 9.26 9.80 12/31/2013 87,528 221,814
Karen N. Pape 12,153 3.0% 9.26 9.80 12/31/2013 70,774 179,355
December 31, 2003 SAR Values
45
Number of Common Units Value of
underlying unexercised unexercised in-the-money
SARs at December 31, 2003 (#) SARs at December 31, 2003 ($)
----------------------------- -----------------------------
Name Exercisable Unexercisable Exercisable Unexercisable
- ------------------ ----------- ------------- ----------- -------------
Mark J. Gorman -- 23,620 -- 12,755
Ross A. Benavides -- 15,889 -- 8,580
Kerry W. Mazoch -- 15,030 -- 8,116
Karen N. Pape -- 12,153 -- 6,563
Bonus Plan
In May 2003, the Compensation Committee of the Board of the General
Partner approved a Bonus Plan (the "Bonus Plan") for all employees of the
General Partner. The Bonus Plan is designed to enhance the financial performance
of the Partnership by rewarding employees for achieving financial performance
objectives. The Bonus Plan is administered by the Compensation Committee. Under
this plan, amounts will be allocated for the payment of bonuses to employees
each time GCOLP earns $1.6 million of Available Cash. The amount allocated to
the bonus pool increases for each $1.6 million earned, such that a maximum bonus
pool of $2.0 million will exist if the Partnership earns $14.6 million of
Available Cash.
Bonuses will be paid to employees after the end of the year. The
amount in the bonus pool will be allocated to employees based on the group to
which they are assigned. Employees in the first group can receive bonuses that
range from zero to ten percent of base compensation. The next group includes
employees in the professional group, who could earn a total bonus ranging from
zero to twenty percent. Certain members of the professional group that are part
of management or are exceptional performers are eligible to earn a total bonus
ranging from zero to thirty percent. Lastly, our officers and other senior
management are eligible for a total bonus ranging from zero to forty percent.
The Bonus Plan will be at the discretion of the Compensation Committee, and the
General Partner can amend or change the Bonus Plan at any time.
DIRECTOR COMPENSATION
Information regarding the compensation received from the General
Partner by Mr. Gorman, President, Chief Executive Officer and a director of the
General Partner, is disclosed under the heading "Executive Officer
Compensation".
Directors Fees
The three independent directors receive an annual fee of $30,000.
The Audit Committee Chairman receives an additional annual fee of $4,000 and all
members of the Audit Committee receive $1,500 for attendance at each committee
meeting. Denbury receives $120,000 from the Partnership for providing four of
its executives as directors. Mr. Gorman does not receive a fee for serving as a
director.
Stock Appreciation Rights
The non-employee directors received stock appreciation rights under
the same terms as the Executive Officers. Grants issued to directors during 2003
were:
Number of
Securities
underlying Exercise
SARs price Expiration
Name granted (#) $/Unit date
- -------------------- ----------- --------- ----------
Gareth Roberts 2,576 9.26 12/31/2013
Ronald T. Evans 2,576 9.26 12/31/2013
Herbert I. Goodman 3,092 9.26 12/31/2013
Susan O. Rheney 3,435 9.26 12/31/2013
J. Conley Stone 3,092 9.26 12/31/2013
Mark A. Worthey 2,576 9.26 12/31/2013
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
46
Beneficial Ownership of Partnership Units
The following table sets forth certain information as of February 28,
2004, regarding the beneficial ownership of our units by beneficial owners of 5%
or more of the units, by directors and the executive officers of our general
partner and by all directors and executive officers as a group. This information
is based on data furnished by the persons named.
Beneficial Ownership of Common Units
------------------------------------
Percent
Title of Class Name Number of Units of Class
-------------------- -------------------- --------------- --------
Genesis Energy, L.P. Genesis Energy, Inc. 688,811 7.4
Common Unit Gareth Roberts 10,000 *
Mark J. Gorman 25,525 *
Ronald T. Evans 1,000 *
Herbert I. Goodman 2,000 *
Susan O. Rheney 700 *
Phil Rykhoek 4,000 *
J. Conley Stone 1,000 *
Mark A. Worthey 1,600 *
Ross A. Benavides 9,283 *
Kerry W. Mazoch 8,669 *
Karen N. Pape 3,386 *
All directors and
executive officers as a
group (11 in number) 67,163 *
----------
* Less than 1%
Each unitholder in the above table is believed to have sole voting and
investment power with respect to the shares beneficially held. Included in the
units held by Mark A Worthey are 500 units held for a minor child. Included in
the units held by Kerry W. Mazoch are 584 units held with his children.
Beneficial Ownership of General Partner Interest
Genesis Energy, Inc. owns all of our 2% general partner interest and all
of our incentive distribution rights, in addition to 7.4% of our units. Genesis
Energy, Inc. is a wholly-owned subsidiary of Denbury Resources, Inc.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Our General Partner
Our operations are managed by, and our employees are employed by, Genesis
Energy, Inc., our general partner. Our general partner does not receive any
management fee or other compensation in connection with the management of our
business, but is reimbursed for all direct and indirect expenses incurred on our
behalf. During 2003, these reimbursements totaled $16.0 million. At December 31,
2003, we owed the general partner $0.1 million related to these services.
Our general partner owns the 2% general partner interest and all incentive
distribution rights. Our general partner is entitled to receive incentive
distributions if the amount we distribute with respect to any quarter exceeds
levels specified in our partnership agreement. Under the quarterly incentive
distribution provisions, generally our general partner is entitled to 13.3% of
amounts we distribute in excess of $0.25 per unit, 23.5% of the amounts we
distribute in excess of $0.28 per unit, and 49% of the amounts we distribute in
excess of $0.33 per unit.
Relationship with Denbury Resources, Inc.
Through its control of our general partner, Denbury has the ability to
control our management. During 2003, we acquired a CO2 volumetric production
payment and related wholesale marketing contracts from Denbury for $24.4
million. Additionally we enter into transactions with Denbury in the ordinary
course of its operations. During 2003, these transactions included:
47
- Purchases of crude oil from Denbury totaling $59.7 million. We
provide letter of credit to Denbury related to these
purchases.
- Provision of CO2 transportation services to our wholesale
industrial customers by Denbury's pipeline. The fees for this
service totaled $0.4 million in 2003.
- Provision of services by Denbury officers as directors of our
general partner. We paid Denbury $120,000 for these services
in 2003.
At December 31, 2003, we owed Denbury $6.9 million for purchases of crude
oil and $0.1 million for transportation services.
In 2002, we amended our partnership agreement to broaden the right of the
Common Unitholders to remove the General Partner. 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 would 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.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following table summarizes the aggregate fees billed to us by Deloitte
& Touche LLP.
2003 2002
---- ----
(in thousands)
Audit Fees (a)....................................... $ 211 $ 140
Audit-Related Fees (b)............................... 92 71
--------- ---------
Total................................................ $ 303 $ 211
========= =========
(a) Fees for audit services billed in 2003 consisted of:
Audit of our annual financial statements
Audit of our General Partner financial statements
Reviews of our quarterly financial statements
Financial statement audits of prior years that were originally
audited by Arthur Andersen LLP.
Fees for audit services billed in 2002 consisted of:
Audit of our annual financial statements
Reviews of our quarterly financial statements.
(b) Fees for audit-related services in 2003 and 2002 consisted of:
Financial accounting and reporting consultations
Sarbanes-Oxley Act, Section 404 advisory services
Employee benefit plan audits.
Deloitte provided no tax services or other services to us in 2002 or 2003.
In considering the nature of the services provided by Deloitte, the Audit
Committee determined that such services are compatible with the provision of
independent audit services. The Audit Committee discussed these services with
Deloitte and management of our General Partner to determine that they are
permitted under the rules and regulations concerning auditor independence
promulgated by the SEC to implement the Sarbanes-Oxley Act of 2002, as well as
the American Institute of Certified Public Accountants.
48
Pre-Approval Policy
The services by Deloitte in 2003 were pre-approved in accordance with the
pre-approval policy and procedures adopted by the Audit Committee at its May 9,
2003 meeting. This policy describes the permitted audit, audit-related, tax and
other services (collectively, the "Disclosure Categories") that the independent
auditor may perform. The policy requires that prior to the beginning of each
fiscal year, a description of the services (the "Service List") expected to be
performed by the independent auditor in each of the Disclosure Categories in the
following fiscal year be presented to the Audit Committee for approval.
Services provided by the independent auditor during the following year
that are included in the Service List were pre-approved following the policies
and procedures of the Audit Committee.
Any requests for audit, audit-related, tax and other services not
contemplated on the Service List must be submitted to the Audit Committee for
specific pre-approval and cannot commence until such approval has been granted.
Normally, pre-approval is provided at regularly scheduled meeting.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) and (2) Financial Statements and Financial Statement Schedules
See "Index to Consolidated Financial Statements" set forth on page
52.
(a)(3) Exhibits
3.1 Certificate of Limited Partnership of Genesis Energy,
L.P. ("Genesis") (incorporated by reference to Exhibit
3.1 to Registration Statement, File No. 333-11545)
3.2 Third Amended and Restated Agreement of Limited
Partnership of Genesis (incorporated by reference to
Exhibit 4.1 of Form 8-K dated July 31, 2002)
3.3 Certificate of Limited Partnership of Genesis Crude Oil,
L.P. (the "Operating Partnership") (incorporated by
reference to Exhibit 3.3 to Form 10-K for the year
ended December 31, 1996)
3.4 Third Amended and Restated Agreement of Limited
Partnership of the Operating Partnership (incorporated
by reference to Exhibit 4.1 to Form 8-K dated July 31,
2002)
10.1 Purchase & Sale and Contribution & Conveyance Agreement
dated as of December 3, 1996 among Basis Petroleum,
Inc. ("Basis"), Howell Corporation ("Howell"), certain
subsidiaries of Howell, Genesis, the Operating
Partnership and Genesis Energy, L.L.C. (incorporated
by reference to Exhibit 10.1 to Form 10-K for the year
ended December 31, 1996)
10.2 First Amendment to Purchase & Sale and Contribution &
Conveyance Agreement (incorporated by reference to
Exhibit 10.2 to Form 10-K for the year ended December
31, 1996)
10.3 Office Lease at One Allen Center between Trizec Allen
Center Limited Partnership (Landlord) and Genesis
Crude Oil, L.P. (Tenant) (incorporated by reference to
Exhibit 10 to Form 10-Q for the quarterly period ended
September 30, 1997)
10.4 Credit Agreement dated as of March 14, 2003, between
Genesis Crude Oil, L.P., Genesis Energy, Inc. Genesis
Energy, L.P., Fleet National Bank and Certain
Financial Institutions (incorporated by reference to
Exhibit 10.10 to Form 10-K for the year ended December
31, 2002)
10.5 Pipeline Sale and Purchase Agreement between TEPPCO
Crude Pipeline, L.P. and Genesis Crude Oil, L.P. and
Genesis Pipeline, L.P. (incorporated by reference to
Exhibit 10.1 to Form 8-K dated October 31, 2003)
10.6 Purchase and Sale Agreement between TEPPCO Crude
Pipeline, L.P. and Genesis Crude Oil, L.P. (incorporated
by reference to Exhibit 10.2 to Form 8-K dated October
31, 2003)
*10.7 Production Payment Purchase and Sale Agreement between
Denbury Resources, Inc. and Genesis Crude Oil, L.P.
executed November 14, 2003
49
*10.8 Carbon Dioxide Transportation Agreement between Denbury
Resources, Inc. and Genesis Crude Oil, L.P.
*10.9+ Genesis Energy, Inc. Stock Appreciation Rights Plan.
11.1 Statement Regarding Computation of Per Share Earnings
(See Notes 2 and 7 to the Consolidated Financial
Statements)
*21.1 Subsidiaries of the Registrant
*31.1 Certification by Chief Executive Officer Pursuant to
Rule 13a-14(a) under the Securities Exchange Act of
1934.
*31.2 Certification by Chief Financial Officer Pursuant to
Rule 13a-14(a) under the Securities Exchange Act of
1934.
*32.1 Certification by Chief Executive Officer Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2 Certification by Chief Financial Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
----------
* Filed herewith
+ A management contract or compensation plan or arrangement.
(b) Reports on Form 8-K
A Current Report on Form 8-K was filed on November 24, 2003, in
connection with the purchase of a volumetric production payment
from Denbury.
A Current Report on Form 8-K was furnished on November 11, 2003,
providing, under Items 7, 9 and 12, the Partnership's news
release including attached schedules dated November 11, 2003,
that announced the Partnership's financial and operating results
for the three and nine month periods ended September 30, 2003.
A Current Report on Form 8-K was filed on November 4, 2003,
including, as an exhibit, pro forma financial statements, in
connection with the sale of parts of the Partnership's crude oil
pipeline and associated gathering and marketing operations.
A Current Report on Form 8-K was furnished October 15, 2003,
providing, under Items 7, 9 and 12, the Partnership's news
release that announced the signing of a purchase and sale
agreement to sell parts of the Partnership's crude oil pipeline
and associated gathering and marketing operations and the
signing of a non-binding letter of intent to purchase a
volumetric production payment from Denbury.
50
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized on the 29th day of
March, 2004.
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
By: GENESIS ENERGY, INC., as
General Partner
By: /s/ Mark J. Gorman
-------------------------------------
Mark J. Gorman
Chief Executive Officer and President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons in the capacities and on
the dates indicated.
/s/ MARK J. GORMAN Director, Chief Executive Officer March 29, 2004
- ---------------------------- and President
Mark J. Gorman (Principal Executive Officer)
/s/ ROSS A. BENAVIDES Chief Financial Officer, March 29, 2004
- ---------------------------- General Counsel and Secretary
Ross A. Benavides (Principal Financial Officer)
/s/ KAREN N. PAPE Vice President and Controller March 29, 2004
- ---------------------------- (Principal Accounting Officer)
Karen N. Pape
Chairman of the Board and March __, 2004
- ---------------------------- Director
Gareth Roberts
/s/ RONALD T. EVANS Director March 29, 2004
- ----------------------------
Ronald T. Evans
/s/ HERBERT I GOODMAN Director March 29, 2004
- ----------------------------
Herbert I. Goodman
/s/ SUSAN O. RHENEY Director March 29, 2004
- ----------------------------
Susan O. Rheney
/s/ PHIL RYKHOEK Director March 29, 2004
- ----------------------------
Phil Rykhoek
/s/ J. CONLEY STONE Director March 29, 2004
- ----------------------------
J. Conley Stone
/s/ MARK A. WORTHEY Director March 29, 2004
- ----------------------------
Mark A. Worthey
51
GENESIS ENERGY, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
Independent Auditors' Report .............................................. 53
Consolidated Balance Sheets, December 31, 2003 and 2002 ................... 54
Consolidated Statements of Operations for the Years Ended
December 31, 2003, 2002 and 2001 ....................................... 55
Consolidated Statements of Comprehensive Income for the Years Ended
December 31, 2003, 2002 and 2001 ....................................... 56
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2003, 2002 and 2001 ....................................... 57
Consolidated Statements of Partners' Capital for the Years Ended
December 31, 2003, 2002 and 2001 ....................................... 58
Notes to Consolidated Financial Statements ................................ 59
52
INDEPENDENT AUDITORS' REPORT
Genesis Energy, L.P.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Genesis Energy,
L.P., (the "Partnership") as of December 31, 2003 and 2002, and the related
consolidated statements of operations, comprehensive income, partners' capital
and cash flows for each of the three years in the period ended December 31,
2003. These financial statements are the responsibility of the Partnership's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Partnership at December 31,
2003 and 2002, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2003 in conformity with
accounting principles generally accepted in the United States of America.
As discussed in Notes 2 and 4 to the consolidated financial statements,
effective January 1, 2002, the Partnership changed its method of accounting for
goodwill and discontinued operations. As discussed in Note 17 to the
consolidated financial statements, in 2001, the Partnership changed its method
of accounting for derivative financial instruments.
/s/ Deloitte & Touche LLP
- -------------------------
DELOITTE & TOUCHE LLP
Houston, Texas
March 19, 2004
53
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31, December 31,
2003 2002
------------ ------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents ................................... $ 2,869 $ 1,071
Accounts receivable - trade ................................. 66,732 80,664
Inventories ................................................. 1,546 4,952
Insurance receivable ........................................ 15,524 3,425
Other ....................................................... 1,540 1,985
--------- ---------
Total current assets ..................................... 88,211 92,830
FIXED ASSETS, at cost .......................................... 70,695 118,418
Less: Accumulated depreciation ............................. (36,724) (73,958)
--------- ---------
Net fixed assets ......................................... 33,971 44,460
CO2 ASSETS, net of amortization ................................ 24,073 --
OTHER ASSETS, net of amortization .............................. 860 980
--------- ---------
TOTAL ASSETS ................................................... $ 147,115 $ 137,537
========= =========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable -
Trade .................................................... $ 60,108 $ 82,640
Related party ............................................ 7,067 4,746
Accrued liabilities ......................................... 20,069 8,834
--------- ---------
Total current liabilities ................................ 87,244 96,220
LONG-TERM DEBT ................................................. 7,000 5,500
COMMITMENTS AND CONTINGENCIES (Note 18)
MINORITY INTERESTS ............................................. 517 515
PARTNERS' CAPITAL
Common unitholders, 9,314 and 8,625 units issued and
outstanding, respectively .................................. 51,299 34,626
General partner ............................................. 1,055 715
Accumulated other comprehensive loss ........................ -- (39)
--------- ---------
Total partners' capital .................................. 52,354 35,302
--------- ---------
TOTAL LIABILITIES AND PARTNERS' CAPITAL ........................ $ 147,115 $ 137,537
========= =========
The accompanying notes are an integral part of these
consolidated financial statements.
54
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
Year Ended December 31,
---------------------------------------------
2003 2002 2001
----------- ----------- -----------
REVENUES:
Crude oil gathering and marketing:
Unrelated parties .......................................... $ 641,684 $ 636,107 $ 2,971,785
Related parties ............................................ -- 3,036 29,847
Crude oil pipeline ............................................ 15,134 13,485 9,948
CO2 revenues .................................................. 1,079 -- --
----------- ----------- -----------
Total revenues .......................................... 657,897 652,628 3,011,580
COSTS AND EXPENSES:
Crude oil costs:
Unrelated parties .......................................... 562,626 589,598 2,943,935
Related parties ............................................ 59,653 26,452 36,699
Field operating ............................................ 11,497 11,916 11,270
Crude oil pipeline operating costs ............................ 10,026 8,076 7,038
CO2 transportation costs - related party ...................... 355 -- --
General and administrative .................................... 8,768 7,864 11,307
Depreciation and amortization ................................. 4,641 4,603 5,340
Impairment of long-lived assets ............................... -- -- 9,589
Change in fair value of derivatives ........................... -- 1,279 (1,681)
Net gain on disposal of surplus assets ........................ (236) (705) (167)
Other operating charges ....................................... -- 1,500 1,500
----------- ----------- -----------
Total costs and expenses ................................ 657,330 650,583 3,024,830
----------- ----------- -----------
OPERATING INCOME (LOSS) .......................................... 567 2,045 (13,250)
OTHER INCOME (EXPENSE):
Interest income ............................................... 34 69 166
Interest expense .............................................. (1,020) (1,104) (693)
----------- ----------- -----------
Income (loss) from continuing operations before
minority interests and cumulative effect of change
in accounting principle ....................................... (419) 1,010 (13,777)
Minority interests in continuing operations ...................... -- -- (1)
----------- ----------- -----------
INCOME (LOSS) FROM CONTINUING OPERATIONS ......................... (419) 1,010 (13,776)
Discontinued operations:
Income from operations from discontinued Texas
System (including gain on disposal of $13,028)
before minority interests ..................................... 13,742 4,082 (30,306)
Minority interests in discontinued operations .................... 1 -- (3)
----------- ----------- -----------
INCOME FROM DISCONTINUED OPERATIONS .............................. 13,741 4,082 (30,303)
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE, NET OF
MINORITY INTEREST EFFECT ...................................... -- -- 467
----------- ----------- -----------
NET INCOME (LOSS) ................................................ $ 13,322 $ 5,092 $ (43,612)
=========== =========== ===========
55
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS-CONTINUED
(In thousands, except per unit amounts)
Year Ended December 31,
--------------------------------------------
2003 2002 2001
--------- --------- ---------
NET INCOME PER COMMON UNIT- BASIC AND DILUTED:
Income (loss) from continuing operations
before cumulative effect of change in
accounting principle ............................ $ (0.05) $ 0.11 $ (1.57)
Income from discontinued operations ................ 1.55 0.47 (3.44)
Cumulative effect of change in accounting
principle ....................................... -- -- 0.05
--------- --------- ---------
NET INCOME (LOSS) .................................. $ 1.50 $ 0.58 $ (4.96)
========= ========= =========
Weighted average number of common units
outstanding ........................................... 8,715 8,625 8,624
========= ========= =========
The accompanying notes are an integral part of these
consolidated financial statements.
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
Year Ended December 31,
-----------------------------------------
2003 2002 2001
-------- -------- --------
NET INCOME (LOSS) ......................................................... $ 13,322 $ 5,092 $(43,612)
OTHER COMPREHENSIVE INCOME (LOSS):
Change in fair value of derivatives used for hedging purposes ........ 39 (39) --
-------- -------- --------
COMPREHENSIVE INCOME (LOSS) ............................................... $ 13,361 $ 5,053 $(43,612)
======== ======== ========
The accompanying notes are an integral part of these
consolidated financial statements.
56
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Year Ended December 31,
---------------------------------------
2003 2002 2001
--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) ............................................... $ 13,322 $ 5,092 $ (43,612)
Adjustments to reconcile net income to net cash
provided by operating activities -
Depreciation ................................................. 5,970 4,965 6,228
Amortization of CO2 contracts and covenant not-to-compete .... 534 848 1,318
Amortization and write-off of credit facility issuance costs . 1,031 736 23
Impairment of long-lived assets .............................. -- -- 45,061
Cumulative effect of change in accounting principle .......... -- -- (467)
Change in fair value of derivatives .......................... 39 2,055 (2,259)
Gain on disposal of assets ................................... (13,264) (708) (167)
Minority interests equity in earnings (losses) ............... 1 -- (4)
Other non-cash charges ....................................... 228 1,500 1,605
Changes in components of working capital -
Accounts receivable ....................................... 13,932 81,134 167,666
Inventories ............................................... 3,758 (1,051) (2,743)
Other current assets ...................................... (11,654) 3,909 4,854
Accounts payable .......................................... (20,211) (86,159) (154,117)
Accrued liabilities ....................................... 11,007 (4,904) (5,230)
--------- --------- ---------
Net cash provided by operating activities ......................... 4,693 7,417 18,156
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment ............................. (4,910) (4,211) (1,882)
CO2 contracts acquisition ....................................... (24,401) -- --
Change in other assets .......................................... (24) 5 --
Proceeds from disposal of assets ................................ 22,341 2,243 453
--------- --------- ---------
Net cash used in investing activities ............................. (6,994) (1,963) (1,429)
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank borrowings (repayments), net ............................... 1,500 (8,400) (8,100)
Credit facility issuance fees ................................... (1,093) -- (1,312)
Issuance of limited and general partner interests ............... 5,012 -- --
Minority interests contributions ................................ 1 -- --
Distributions to common unitholders ............................. (1,294) (1,725) (6,898)
Distributions to General Partner ................................ (27) (35) (141)
Distributions to minority interest owner ........................ -- -- (1)
Purchase of treasury units, net ................................. -- -- (6)
--------- --------- ---------
Net cash provided by (used in) financing activities ............... 4,099 (10,160) (16,458)
Net increase (decrease) in cash and cash equivalents .............. 1,798 (4,706) 269
Cash and cash equivalents at beginning of period .................. 1,071 5,777 5,508
--------- --------- ---------
Cash and cash equivalents at end of period ........................ $ 2,869 $ 1,071 $ 5,777
========= ========= =========
The accompanying notes are an integral part of these
consolidated financial statements.
57
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(In thousands)
Partners' Capital
-------------------------------------------------------------------------------
Accumulated
Number of Other
Common Common General Treasury Comprehensive
Units Unitholders Partner Units Income Total
--------- ----------- ------- -------- ------------- -----
Partners' capital, January 1, 2001 .......... 8,625 $ 80,960 $ 1,661 $ (6) $ -- $ 82,615
Net loss .................................... -- (42,740) (872) -- -- (43,612)
Cash distributions .......................... -- (6,898) (141) -- -- (7,039)
Purchase of treasury units .................. -- -- -- (6) -- (6)
Issuance of treasury units to
Restricted Unit Plan participants ........ -- -- -- 12 -- 12
Excess of expense over cost of
treasury units issued for Restricted
Unit Plan ................................ -- 39 -- -- -- 39
----- -------- -------- -------- -------- --------
Partners' capital, December 31, 2001 ........ 8,625 31,361 648 -- -- 32,009
Net income .................................. -- 4,990 102 -- -- 5,092
Cash distributions .......................... -- (1,725) (35) -- -- (1,760)
Change in fair value of derivatives
used for hedging purposes ................ -- -- -- -- (39) 39
----- -------- -------- -------- -------- --------
Partners' capital, December 31, 2002 ........ 8,625 34,626 715 -- (39) 35,302
Net income .................................. -- 13,055 267 -- -- 13,322
Cash distributions .......................... -- (1,294) (27) -- -- (1,321)
Issuance of units ........................... 689 4,912 100 -- -- 5,012
Change in fair value of derivatives
used for hedging purposes ................ -- -- -- -- 39 39
----- -------- -------- -------- -------- --------
Partners' capital, December 31, 2003 ........ 9,313 $ 51,299 $ 1,055 $ -- $ -- $ 52,354
===== ======== ======== ======== ======== ========
The accompanying notes are an integral part of these
consolidated financial statements.
58
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
Organization
Genesis Energy, L.P. ("GELP" or the "Partnership") is a publicly traded
Delaware limited partnership engaged in gathering, marketing and transportation
of crude oil and wholesale marketing of carbon dioxide (CO2). We were formed
in December 1996 through an initial public offering of 8.6 million Common Units,
representing limited partner interests in GELP of 98%. The General Partner of
GELP is Genesis Energy, Inc. (the "General Partner") which owns a 2% general
partner interest in GELP. The General Partner is owned by Denbury Gathering &
Marketing, Inc. a subsidiary of Denbury Resources Inc. Denbury and its
subsidiaries are hereafter referred to as Denbury.
In November 2003, an additional 0.7 million Common Units were sold to our
general partner in a private placement. These Common Units are not registered
with the Securities and Exchange Commission. See Note 7.
Genesis Crude Oil, L.P. is the operating limited partnership and is owned
99.99% by GELP and 0.01% by the General Partner. Genesis Crude Oil, L.P. has two
subsidiary partnerships, Genesis Pipeline Texas, L.P. and Genesis Pipeline USA,
L.P. Genesis Crude Oil, L.P. and its subsidiary partnerships will be referred to
as GCOLP.
Basis of Presentation
The accompanying financial statements and related notes present the
consolidated financial position as of December 31, 2003 and 2002 for GELP and
its results of operations, cash flows and changes in partners' capital for the
years ended December 31, 2003, 2002 and 2001, and changes in comprehensive
income for the years ended December 31, 2003, 2002 and 2001.
All significant intercompany transactions have been eliminated. Certain
reclassifications were made to prior period amounts to conform to current period
presentation. Such reclassifications had no effect on reported net income, total
assets, total liabilities or partners' equity.
No provision for income taxes related to the operation of GELP is included
in the accompanying consolidated financial statements; as such income will be
taxable directly to the partners holding partnership interests in the
Partnership.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of consolidated financial statements in conformity
with accounting principles generally accepted in the United States of America
requires us to make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and liabilities,
if any, at the date of the consolidated financial statements and the reported
amounts of revenues and expenses during the reporting period. Significant
estimates that we make include: (1) estimated useful lives of assets, which
impacts depreciation and amortization, (2) accruals related to revenues and
expenses, (3) liability and contingency accruals, (4) estimated fair value of
assets and liabilities acquired, and (5) estimates of future net cash flows from
assets for purposes of determining whether impairment of those assets has
occurred. While we believe these estimates reasonable, actual results could
differ from these estimates.
Cash and Cash Equivalents
Cash and cash equivalents consist of all demand deposits and funds
invested in highly liquid instruments with original maturities of three months
or less. The Partnership has no requirement for compensating balances or
restrictions on cash.
59
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Inventories
Crude oil inventories held for sale are valued at the lower of
average cost or market. Fuel inventories are carried at the lower of cost or
market.
Fixed Assets
Property and equipment are carried at cost. Depreciation of property
and equipment is provided using the straight-line method over the respective
estimated useful lives of the assets. Asset lives are 5 to 15 years for
pipelines and related assets, 3 to 7 years for vehicles and transportation
equipment, and 3 to 10 years for buildings, office equipment, furniture and
fixtures and other equipment.
Long-lived assets are reviewed for impairment. In 2001, we recorded
a charge for impairment of our pipeline assets as we did not believe the
recorded values of the assets could be recovered through future cash flows. On
January 1, 2002, we adopted Statement of Financial Accounting Standards No. 144
"Accounting for the Impairment or Disposal of Long-Lived Assets." Under SFAS No.
144, an asset shall be tested for impairment when events or circumstances
indicate that its carrying value may not be recoverable. The carrying value of a
long-lived asset is not recoverable if it exceeds the sum of the undiscounted
cash flows expected to be generated from the use and ultimate disposal of the
asset. If the carrying value is determined to not be recoverable under this
method, an impairment charge equal to the amount the carrying value exceeds the
fair value is recognized. Fair value is generally determined from estimated
discounted future net cash flows.
Maintenance and repair costs are charged to expense as incurred.
Costs incurred for major replacements and upgrades are capitalized and
depreciated over the remaining useful life of the asset.
Certain volumes of crude oil are classified in fixed assets, as they
are necessary to ensure efficient and uninterrupted operations of the gathering
businesses. These crude oil volumes are carried at their weighted average cost.
We account for asset retirement obligations in accordance with SFAS
143. SFAS 143 requires that the cost for asset retirement obligations be
capitalized as part of the cost of the related long-lived asset and subsequently
allocated to expense systematically as with depreciation. With respect to our
pipelines, federal regulations will require us to purge the crude oil from our
pipelines when the pipelines are retired. Our right of way agreements do not
require us to remove pipe or otherwise perform remediation upon taking the
pipelines out of service. Many of our truck unload stations are on leased sites
that require that we remove our improvements upon termination of the lease term,
however the lease terms are continuous until a party to the lease gives notice
that it wishes the lease to terminate. However the fair value of the asset
retirement obligations cannot be reasonably estimated, as the settlement dates
are indeterminate. We will record such asset retirement obligations in the
period in which we determine the settlement dates.
In the third quarter of 2003, we recorded a liability in the amount
of $0.7 million representing the anticipated cost to remove a pipeline from
offshore waters of the State of Louisiana. The costs are expected to be incurred
before June 30, 2004.
CO2 and Other Assets
Other assets consist primarily of CO2 assets and intangibles. The
CO2 assets include a volumetric production payment and long-term contracts to
sell the CO2 volume. The contract value is being amortized on a
units-of-production method. See Note 5.
Intangibles included a covenant not to compete, which was amortized
over five years ending during 2003, and credit facility fees which are being
amortized over the period the facility is in effect.
Minority Interests
Minority interests represent a 0.01% general partner interest in
GCOLP held by the General Partner.
Environmental Liabilities
We provide for the estimated costs of environmental contingencies
when liabilities are likely to occur and reasonable estimates can be made.
Ongoing environmental compliance costs, including maintenance and monitoring
costs, are charged to expense as incurred.
60
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Revenue Recognition
Revenues from gathering and marketing of crude oil are recognized
when title to the crude oil is transferred to the customer. Revenues from
transportation of crude oil by our pipelines are recognized upon delivery of the
barrels to the location designated by the shipper. Pipeline loss allowance
revenues are recognized to the extent that pipeline loss allowances charged to
shippers exceed pipeline measurement losses for the period based upon the fair
market value of the crude oil upon which the allowance is based.
Revenues from CO2 activities are recorded when title transfers to
the customer at the inlet meter of the customer's facility.
Cost of Sales
Crude oil cost of sales consists of the cost of crude oil and field
and pipeline operating expenses. Field and pipeline operating expenses consist
primarily of labor costs for drivers and pipeline field personnel, truck rental
costs, fuel and maintenance, utilities, insurance and property taxes.
Cost of sales for the CO2 activities consists of a transportation
fee charged by Denbury (currently $0.16 per Mcf) to transport the CO2 to the
customer through Denbury's pipeline.
Derivative Instruments and Hedging Activities
We minimize our exposure to price risk by limiting our inventory
positions, therefore we rarely need to use derivative instruments. In 2003, we
used derivative instruments only once. However should we use derivative
instruments to hedge exposure to price risk, we would account for those
derivative transactions in accordance with Statement of Financial Accounting
Standards No. 133 "Accounting for Derivative Instruments and Hedging
Activities", as amended and interpreted. Derivative transactions, which can
include forward contracts and futures positions on the NYMEX, are recorded on
the balance sheet as assets and liabilities based on the derivative's fair
value. Changes in the fair value of derivative contracts are recognized
currently in earnings unless specific hedge accounting criteria are met. If the
derivatives meet those criteria, the derivative's gains and losses offset
related results on the hedged item in the income statement. We must formally
designate the derivative as a hedge and document and assess the effectiveness of
derivatives associated with transactions that receive hedge accounting.
SFAS No. 133 designates derivatives that hedge exposure to variable
cash flows of forecasted transactions as cash flow hedges and the effective
portion of the derivative's gain or loss is initially reported as a component of
other comprehensive income (outside earnings) and subsequently reclassified into
earnings when the forecasted transaction affects earnings. The ineffective
portion of the gain or loss is reported in earnings immediately. If a derivative
transaction qualifies for and is designated as a normal purchase and sale, it is
exempted from the fair value accounting requirements and is accounted for using
traditional accrual accounting.
Net Income Per Common Unit
Basic and diluted net income per Common Unit is calculated on the
weighted average number of outstanding Common Units, after exclusion of the 2
percent General Partner interest from net income. The weighted average number of
Common Units outstanding was 8,714,845, 8,624,554 and 8,623,741 for the years
ended December 31, 2003, 2002 and 2001, respectively. Diluted net income per
Common Unit did not differ from basic net income per Common Unit for any period
presented. See Note 7 for a computation of net income per Common Unit.
Recent Accounting Pronouncements
We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" on
January 1, 2003. See Fixed Assets above.
The FASB issued SFAS No. 145, "Rescission of FASB Statements 4, 44 and 64,
Amendment of FASB Statement No. 13, and Technical Corrections." This statement
revised accounting guidance related to the extinguishment of debt and accounting
for certain lease transactions. It also amended other accounting literature to
clarify its meaning, applicability and to make various technical corrections.
Our adoption of this standard effective January 1, 2003 had no impact on our
financial statements.
On January 1, 2003, we adopted SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities," which addresses accounting for
restructuring and similar costs. This statement requires that the liability for
costs associated with an exit or disposal activity be recognized when the
liability is incurred rather than at the
61
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
date of commitment to an exit plan. This adoption of this statement had no
material impact on our financial statements. During the third quarter of 2003,
we recorded termination benefits related to the sale of our Texas Gulf Coast
operations and, in the fourth quarter of 2003, recorded the sale of those
operations. See Note 11 for information regarding this sale.
We implemented FASB Interpretation No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others" as of December 31, 2002. This interpretation of SFAS No.
5, 57 and 107, and rescission of FASB Interpretation No. 34 elaborates on the
disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under certain guarantees that it has issued. It
also clarifies that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligation undertaken in
issuing the guarantee. The information required by this interpretation is
included in Note 18.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities," and amended the Interpretation in December 2003.
The interpretation states that certain variable interest entities (VIE) may be
required to be consolidated into the results of operations and financial
position of the entity that is the primary beneficiary. The provisions of the
interpretation were effective immediately for VIEs created after January 15,
2003. We do not have any VIEs. The adoption of this interpretation in 2003 had
no effect on our financial statements.
We adopted SFAS No. 148, "Accounting for Stock-Based
Compensation-Transition and Disclosure," as of January 1, 2003. This statement
provides alternative methods of transition from a voluntary change to the fair
value based method of accounting for stock-based employee compensation and
amends the disclosure requirements of SFAS No. 123 in both annual and interim
financial statements. As there are no outstanding grants of Partnership units
under any compensation plans of the Partnership, the adoption of this statement
had no effect on our financial position, results of operations, cash flows or
disclosure requirements.
On April 30, 2003, the FASB issued SFAS No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities." This statement amends and
clarifies accounting for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities under SFAS
No. 133. This statement is effective for contracts entered into or modified
after June 30, 2003, for hedging relationships designated after June 30, 2003,
and to certain preexisting contracts. We adopted SFAS No. 149 on July 1, 2003.
The adoption of this statement had no effect on our financial position, results
of operations or cash flows.
In May 2003, The FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity". SFAS
No. 150 establishes standards for how an issuer classifies and measures certain
freestanding instruments with characteristics of both liabilities and equity.
SFAS No. 150 requires that an issuer classify a financial instrument that is
within its scope as a liability (or asset in some circumstances). We adopted
SFAS No. 150 effective July 1, 2003. The adoption of this statement had no
effect on our financial position, results of operations or cash flows.
62
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. INVENTORIES
Inventories consisted of the following (in thousands).
December 31,
------------------------------
2003 2002
------------ ------------
Crude oil inventories, at lower of cost or market................ $ 1,476 $ 4,841
Fuel and supplies inventories, at lower of cost or market........ 70 111
------------ ------------
Total inventories.......................................... $ 1,546 $ 4,952
============ ============
4. FIXED ASSETS
Fixed assets consisted of the following (in thousands).
December 31,
------------------------------
2003 2002
------------ ------------
Land and buildings............................................... $ 1,481 $ 3,492
Pipelines and related assets..................................... 57,429 101,397
Vehicles and transportation equipment............................ 1,510 1,527
Office equipment, furniture and fixtures......................... 3,043 3,138
Other ........................................................... 7,232 8,864
------------ ------------
70,695 118,418
Less - Accumulated depreciation.................................. (36,724) (73,958)
------------- ------------
Net fixed assets................................................. $ 33,971 $ 44,460
============ ============
Depreciation expense, including discontinued operations, was $5,970,000,
$4,965,000 and $6,228,000 for the years ended December 31, 2003, 2002, and 2001,
respectively. In 2001, the Partnership recorded an impairment charge related to
its pipeline assets of $38,049,000. See Note 9.
5. CO2 AND OTHER ASSETS
Carbon Dioxide (CO2) Assets
We purchased the CO2 assets from Denbury for $24.4 million in cash in
November 2003. These assets included the assignment of an interest in 167.5
billion cubic feet (Bcf) of CO2, under a volumetric production payment and
Denbury's existing long-term CO2 supply agreements with three of its industrial
customers.
The volumetric production payment entitles us to a maximum daily quantity
of CO2 of 52,500 million cubic feet (Mcf) per day through December 31, 2009,
43,000 Mcf per day for the calendar years 2010 through 2012 and 25,000 Mcf per
day beginning in 2013 until we have received all volumes under the production
payment. Under the terms of a transportation agreement with Denbury, Denbury
will process and deliver this CO2 to our industrial customers and receive a
fee of $0.16 per Mcf, subject to inflationary adjustments, from us for those
transportation services.
The terms of the contracts with the industrial customers include minimum
take-or-pay and maximum delivery volumes. The three industrial contracts extend
through 2010, 2012 and 2015.
The CO2 assets are being amortized on a units-of-production method. After
purchase price adjustments, we had 164.9 Bcf of CO2 at acquisition, and the
$24.4 million cost is being amortized based on the volume of CO2 sold each
month. For the two months in 2003 when we owned the CO2 assets, we recorded
amortization of $328,000. Based on the historical deliveries of CO2 to the
customers (which have exceeded minimum take-or-pay volumes), we would expect
that amortization for the next five years to be approximately $2,147,000
annually.
63
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Other Assets
Other assets consisted of the following (in thousands).
December 31,
------------------------------
2003 2002
------------ ------------
Credit facility fees........................................ $ 1,117 $ 1,312
Covenant not to compete..................................... $ -- $ 4,238
Other....................................................... 40 42
------------ ------------
1,157 5,592
Less - Accumulated amortization............................. (297) (4,612)
------------- ------------
Net other assets............................................ $ 860 $ 980
============ ============
In 2001, the Partnership recorded an impairment charge related to goodwill
of $7,012,000, which reduced the net book value of goodwill to zero at December
31, 2001. See Note 11. In accordance with SFAS No. 142, "Goodwill and Other
Intangible Assets," which we adopted January 1, 2002, we test other intangible
assets periodically to determine if impairment has occurred. An impairment loss
is recognized for intangibles if the carrying amount of an intangible asset is
not recoverable and its carrying amount exceeds its fair value. As of December
31, 2003, no impairment has occurred of our remaining intangible assets.
Amortization expense for goodwill was $470,000 for the year ended December
31, 2001. Amortization expense for the covenant-not-to-compete was $205,000 for
the year ended December 31, 2003 and $848,000 for the each of the years ended
December 31, 2002 and 2001. Accumulated amortization of the
covenant-not-to-compete was $4,033,000 at December 31, 2002. The
covenant-not-to-compete was fully amortized and expired in 2003.
Amortization expense for the credit facility fees for the year ended
December 31, 2003 was $298,000. Additionally in 2003, we charged to expense
$733,000 of fees related to the facility that existed at the end of 2002. In
2002 and 2001, we recorded $456,000 and $23,000 of amortization of credit
facility fees, respectively.
6. DEBT
In March 2003, the Partnership entered into $65 million three-year credit
facility with a group of banks with Fleet National Bank as agent ("Fleet
Facility"). The Fleet Facility 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 Facility are as follows:
- Letter of credit fees are based on the usage of the Fleet
Facility in relation to the borrowing base and will range from
2.00% to 3.00%. At December 31, 2003, the rate was 2.00%.
- The interest rate on working capital borrowings is also based
on the usage of the Fleet Facility in relation to the
borrowing base. Loans may be 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%. At December 31, 2003, we borrowed at the prime rate
plus 1.00%.
- We pay a commitment fee on the unused portion of the $65
million commitment. This commitment fee is also based on the
usage of the Fleet Facility in relation to the borrowing base
and will range from 0.375% to 0.50%. At December 31, 2003, the
commitment fee rate was 0.375%.
- 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 is defined in
the Fleet Facility generally to include cash balances, net
accounts receivable and inventory, less deductions for certain
accounts payable, and is calculated monthly.
- Collateral under the Fleet Facility consists of our accounts
receivable, inventory, cash accounts, margin accounts and
fixed assets.
- The Fleet Facility contains covenants requiring a minimum
current ratio, a minimum leverage ratio, a minimum cash flow
coverage ratio, a maximum ratio of indebtedness to
capitalization, a minimum
64
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
EBITDA (earnings before interest, taxes, depreciation and
amortization), and limitations on distributions to
Unitholders.
Under the Fleet Facility, distributions to Unitholders and the General
Partner can only be made if the Borrowing Base exceeds the usage by certain
amounts. See additional discussion below under Note 7.
At December 31, 2003, we had $7.0 million outstanding under the Fleet
Facility. Due to the revolving nature of loans under the Fleet Facility,
additional borrowings and periodic repayments and re-borrowings may be made
until the maturity date of March 14, 2006. At December 31, 2003, we had letters
of credit outstanding under the Fleet Facility totaling $21.6 million, comprised
of $10.0 million and $10.8 million for crude oil purchases related to December
2003 and January 2004, respectively and $0.8 million related to other business
obligations. We were in compliance with the Fleet Facility covenants at December
31, 2003.
7. PARTNERS' CAPITAL AND DISTRIBUTIONS
Partners' Capital
During 2001, 2002 and the first ten months of 2003, partnership
equity consisted of the general partner interest of 2% and 8.6 million Common
Units representing limited partner interests of 98%. The Common Units were sold
to the public in an initial public offering in December 1996. In November 2003,
we issued 688,811 Common Units to our General Partner in exchange for
$4,925,000. We received $101,000 from the general partner for its proportionate
capital contribution. At December 31, 2003, a total of 9,313,811 Common Units
were outstanding.
The general partner interest is held by our General Partner. The
Partnership is managed by the General Partner. The General Partner also holds a
0.01% general partner interest in GCOLP, which is reflected as a minority
interest in the consolidated balance sheet at December 31, 2003.
The Partnership Agreement authorizes the General Partner to cause
GCOLP to issue additional limited partner interests and other equity securities,
the proceeds from which could be used to provide additional funds for
acquisitions or other GCOLP needs.
Distributions
Generally, 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 Cash consists generally of all of our cash receipts less cash
disbursements adjusted for net changes to reserves. The target minimum quarterly
distribution ("MQD") for each quarter is $0.20 per unit. For 2001, we paid
distributions of $0.20 per unit ($1.8 million in total) per quarter for the
first three quarters. For the fourth quarter of 2001 and for all of 2002, we did
not pay any regular quarterly distributions. We did pay a special distribution
of $0.20 per unit ($1.7 million in total) in December 2002 to help mitigate the
tax effects of income allocations for that year. Beginning with the distribution
for the first quarter of 2003, we paid a regular quarterly distribution of $0.05
per unit ($0.4 million in total per quarter). For the fourth quarter of 2003, we
increased our quarterly distribution to $0.15 per unit ($1.4 million in total),
which was paid in February 2004.
Under the Fleet Agreement, a provision requires that the Borrowing
Base exceed the usage under the Fleet Agreement by at least $10 million plus the
quarterly distribution, measured once each month, in order for us to make a
distribution for the quarter.
Our general partner is entitled to receive incentive distributions
if the amount we distribute with respect to any quarter exceeds levels specified
in our partnership agreement. Under the quarterly incentive distribution
provisions, the general partner generally is entitled to receive 13.3% of any
distributions in excess of $0.25 per unit, 23.5% of any distributions in excess
of $0.28 per unit and 49% of any distributions in excess of $0.33 per unit
without duplication. We have not paid any incentive distributions through
December 31, 2003.
65
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Net Income Per Common Unit
The following table sets forth the computation of basic net income
per Common Unit for 2003, 2002, and 2001 (in thousands, except per unit
amounts).
Year Ended December 31,
--------------------------------------
2003 2002 2001
-------- -------- --------
Numerators for basic and diluted net income per
common unit:
Income (loss) from continuing operations ............... $ (419) $ 1,010 $(13,776)
Less general partner 2% ownership ...................... (8) 20 (275)
-------- -------- --------
Income (loss) from continuing operations
available for common unitholders .................... $ (411) $ 990 $(13,501)
======== ======== ========
Income (loss) from discontinued operations ............. $ 13,741 $ 4,082 $(30,306)
Less general partner 2% ownership ...................... 275 82 (606)
-------- -------- --------
Income (loss) from continuing operations
available for common unitholders .................... $ 13,466 $ 4,000 $(29,700)
======== ======== ========
Cumulative effect of change in accounting
principle ........................................... $ -- $ -- $ 467
-------- -------- --------
Less general partner 2% ownership ...................... -- -- 9
-------- -------- --------
Cumulative effect of change in accounting
principle available for common unitholders .......... $ -- $ -- $ 458
======== ======== ========
Denominator for basic and diluted per Common Unit
- weighted average number of Common Units outstanding .... 8,715 8,625 8,623
======== ======== ========
Basic and diluted net income (loss) per Common
Unit:
Income (loss) from continuing operations ............... $ (0.05) $ 0.11 $ (1.57)
Income (loss) from discontinued operations ............. 1.55 0.47 (3.44)
Cumulative effect of change in accounting principle .... -- -- 0.05
-------- -------- --------
Net income (loss) ...................................... $ 1.50 $ 0.58 $ (4.96)
======== ======== ========
8. BUSINESS SEGMENT INFORMATION
Our operations consist of three operating segments: (1) Crude Oil
Gathering and Marketing - the purchase and sale of crude oil at various points
along the distribution chain; (2) Crude Oil Pipeline Transportation - interstate
and intrastate crude oil pipeline transportation; and (2) CO2 marketing - the
sale of CO2 acquired under a volumetric production payment to industrial
customers. Prior to 2003, we managed our crude oil gathering, marketing and
pipeline operations as a single segment. The tables below reflect all periods
presented as though the current segment designations had existed, and include
only continuing operations data.
We evaluate segment performance based on segment margin before
depreciation and amortization. All of our revenues are derived from, and all of
our assets are located in the United States.
66
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Crude Oil
----------------------------
Gathering and CO2
Marketing Pipeline Marketing Total
--------- -------- --------- -----
(in thousands)
Year Ended December 31, 2003
Revenues:
External Customers ............................................. $ 641,684 $ 11,799 $ 1,079 $ 654,562
Intersegment (a) ............................................... -- 3,335 -- 3,335
---------- ---------- ---------- ----------
Total revenues of reportable segments .......................... $ 641,684 $ 15,134 $ 1,079 $ 657,897
========== ========== ========== ==========
Segment margin excluding depreciation and amortization (b) ..... $ 7,908 5,108 $ 724 $ 13,740
Capital expenditures ........................................... $ 635 $ 2,302 $ 24,401 $ 27,338
Maintenance capital expenditures ............................... $ 635 $ 2,226 $ -- $ 2,861
Net fixed and other long-term assets ........................... $ 5,480 $ 29,351 $ 24,073 $ 58,904
Year Ended December 31, 2002
Revenues:
External Customers ............................................. $ 639,143 $ 10,214 $ -- $ 649,357
Intersegment (a) ............................................... -- 3,271 -- 3,271
---------- ---------- ---------- ----------
Total revenues of reportable segments .......................... $ 639,143 $ 13,485 $ -- $ 652,628
========== ========== ========== ==========
Segment margin excluding depreciation and amortization (b) ..... $ 11,177 5,409 $ -- $ 16,586
Capital expenditures ........................................... $ 690 $ 1,981 $ -- $ 2,671
Maintenance capital expenditures ............................... $ 690 $ 1,981 $ -- $ 2,671
Year Ended December 31, 2001
Revenues:
External Customers ............................................. $3,001,632 $ 7,809 $ -- $ 654,017
Intersegment (a) ............................................... -- 2,139 -- 2,139
---------- ---------- ---------- ----------
Total revenues of reportable segments .......................... $3,001,632 $ 9,948 $ -- $3,011,580
========== ========== ========== ==========
Segment margin excluding depreciation and amortization (b) ..... $ 9,728 2,910 $ -- $ 12,638
Capital expenditures ........................................... $ 388 $ 615 $ -- $ 1,003
Maintenance capital expenditures ............................... $ 388 $ 615 $ -- $ 1,003
(a) Intersegment sales were conducted on an arm's length basis.
(b) Segment margin was calculated as revenues less cost of sales and
operations expense. A reconciliation of segment margin to income from
continuing operations for each year presented is as follows:
67
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Year Ended December 31,
----------------------------------
2003 2002 2001
-------- -------- --------
(in thousands)
Segment margin excluding depreciation and
amortization ........................................ $ 13,740 $ 16,586 $ 12,638
General and administrative expenses ..................... 8,768 7,864 11,307
Depreciation, amortization and impairment ............... 4,641 4,603 14,929
Change in fair value of derivatives ..................... -- 1,279 (1,681)
Net gain on disposal of surplus assets .................. (236) (705) (167)
Interest expense, net ................................... 986 1,035 527
Other operating charges ................................. -- 1,500 1,500
Minority interests in continuing operations ............. -- -- (1)
-------- -------- --------
Income from continuing operations ....................... $ (419) $ 1,010 $(13,776)
======== ======== ========
9. IMPAIRMENT OF PIPELINE ASSETS
In the fourth quarter of 2001, as a result of declining revenues and
rising costs from its pipeline operations for operations and maintenance
combined with regulatory changes requiring additional testing for pipeline
integrity, the Partnership determined that the estimated undiscounted future
cash flows did not support the carrying value of its pipelines. Under Statement
of Financial Accounting Standard No. 121, "Accounting for the Impairment of
Long-Lived Assets and Long-Lived Assets to Be Disposed Of" (SFAS 121) (the
relevant accounting guidance at that time), the carrying value of the assets
must be reduced to the fair value of the assets. The estimated fair value of the
pipelines was determined by reducing the estimated undiscounted future cash
flows plus salvage value to its present value at December 31, 2001. Because the
goodwill on the consolidated balance sheet was generated from the acquisition of
the pipeline assets, the carrying value of the net goodwill was reduced to zero
with the remaining impairment allocated to the fixed assets. An impairment
charge totaling $45.1 million was recorded for the pipeline assets and goodwill.
$9.6 million of this impairment charge related to continuing operations, with
the remaining $35.5 million included in discontinued operations.
10. OTHER OPERATING CHARGES
In each of the third quarter of 2002 and the fourth quarter of 2001, the
Partnership recorded a charge of $1.5 million, for a total of $3.0 million,
related to environmental matters from the Mississippi spill that occurred in
1999. These charges are reflected as other operating charges on the consolidated
statement of operations for 2002 and 2001.
11. DISCONTINUED OPERATIONS
In the fourth quarter of 2003, we sold a significant portion of our Texas
Pipeline System and the related crude oil gathering and marketing operations to
TEPPCO Crude Oil, L.P. Additionally we sold other segments of our Texas Pipeline
System that had been idled in 2002 to Blackhawk Pipeline, L.P., an affiliate of
Multifuels, Inc., which plans to convert the segments to natural gas service.
Some remaining segments not sold to these parties were abandoned in place.
The sale of these assets was the result of an initiative started in 2002
to evaluate our pipeline systems to determine which segments, if any, should be
sold, idled or abandoned to reduce cost or risk of operation. We determined we
should consider selling these assets due to potential risks to the continuation
of our revenue stream that may result from consolidation of pipeline assets in
the area and projections of maintenance capital costs that may occur. We also
determined that other segments of the Texas Gulf Coast operations had little
value and should be abandoned in place or sold to reduce costs or risks.
TEPPCO paid us $21.6 million for the assets it acquired. TEPPCO also
assumed the responsibilities for unpaid royalties related to the crude oil
purchase and sale contracts it assumed and we transferred $0.6 million to TEPPCO
for those liabilities.
We entered into various agreements with TEPPCO including (a) a
transitional services agreement whereby GELP will provide the use of certain
assets that TEPPCO did not acquire and pipeline monitoring services at least
through April 30, 2004, and (b) a joint tariff agreement whereby TEPPCO will
invoice and collect and share with us
68
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the tariffs for transportation on the pipeline being sold and the segments we
retained at least through October 31, 2004. We also agreed not to compete with
TEPPCO in a 40-county area in Texas surrounding the pipeline for a five year
period.
We retained responsibility for environmental matters related to the
operations sold to TEPPCO for the period prior to October 31, 2003, subject to
certain conditions. TEPPCO will pay the first $25,000 for any environmental
claim up to an aggregate of $100,000. We would be responsible for any
environmental claim in excess of these amounts up to an aggregate total of $2
million. TEPPCO has purchased an environmental insurance policy for amounts in
excess of our $2 million responsibility and we reimbursed TEPPCO for one-half of
the policy premium. Our responsibility to indemnify TEPPCO will cease in ten
years.
During 2003, we recorded $0.4 million in termination benefits related to
the sale to TEPPCO. These benefits included retention bonuses and severance pay
for employees affected by the sale.
Under the terms of the sale to Blackhawk, we received no consideration
from Blackhawk for the sale and agreed to provide transition services through
March 31, 2004. We retained responsibility for any environmental matters related
to the pipeline segments acquired by Blackhawk through December 31, 2003,
however that responsibility will cease in ten years.
The assets we abandoned had been idle since 2002 or earlier. The net book
value of these assets was charged to impairment expense in 2001.
Operating results from the discontinued operations for the years ended
December 31, 2003, 2002 and 2001 were as follows:
Year Ended December 31,
----------------------------------------
2003 2002 2001
--------- --------- ---------
(in thousands)
Revenues:
Gathering and marketing ........................................ $ 263,930 $ 252,452 $ 324,371
Pipeline ....................................................... 6,480 6,726 4,247
--------- --------- ---------
Total revenues .............................................. 270,410 259,178 328,618
Costs and expenses:
Crude costs .................................................... 256,986 243,262 313,202
Field operating costs .......................................... 4,718 4,535 4,379
Pipeline operating costs ....................................... 5,846 4,852 3,859
General and administrative ..................................... 282 425 384
Depreciation and amortization .................................. 1,864 1,210 2,206
Change in fair value of derivatives ............................ -- 815 (578)
Net gain on disposal of surplus assets ......................... -- (3) --
Impairment of long-lived assets ................................ -- -- 35,472
--------- --------- ---------
Total costs and expenses .................................... 269,696 255,096 358,924
--------- --------- ---------
Operating income from discontinued operations ..................... 714 4,082 (30,306)
Gain on disposal of assets ........................................ 13,028 -- --
--------- --------- ---------
Income from operations from discontinued Texas
System before minority interests ............................... $ 13,742 $ 4,082 $ (30,306)
========= ========= =========
12. TRANSACTIONS WITH RELATED PARTIES
Except for below-market guaranty fees paid in 2001 and 2002 to Salomon
Smith Barney Holdings Inc. ("Salomon"), sales, purchases and other transactions
with affiliated companies, in the opinion of management, are conducted under
terms no more or less favorable than those conducted with unaffiliated parties.
Salomon was the owner of the General Partner until May 2002.
69
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Sales and Purchases of Crude Oil
Denbury became a related party in May 2002. Purchases of crude oil
from Denbury for the year ended December 31, 2003, were $59.7 million. Purchases
from Denbury during the year ended December 31, 2002, while it was a related
party (May to December) were $26.5 million and purchases during the period
before it became an affiliate were $10.9 million. Purchases from Denbury are
partially secured by letters of credit.
Genesis and Salomon ceased to be related parties in May 2002. During
the period in 2002 when Salomon was a related party, sales totaling $3.0 million
were made to Phibro, Inc., ("Phibro"), a subsidiary of Salomon. Purchases and
sales of $36.7 million and $29.8 million, respectively, were made in 2001 with
Phibro. These transactions were bulk and exchange transactions.
General and Administrative Services
We do not directly employ any persons to manage or operate our
business. Those functions are provided by the General Partner. We reimburse the
General Partner for all direct and indirect costs of these services. Total costs
reimbursed to the General Partner by us were $16,028,000, $17,280,000, and
$18,089,000 for the years ended December 31, 2003, 2002 and 2001, respectively.
Due to Related Parties
At December 31, 2003 and 2002, we owed Denbury $6.9 million and $4.1
million, respectively, for purchases of crude oil. Additionally, we owed Denbury
$0.1 million for CO2 transportation services at December 31, 2003. We owed the
General Partner $0.1 million and $0.6 million at December 31, 2003 and 2002,
respectively, for administrative services.
Directors' Fees
In 2003, we paid $120,000 to Denbury for the services of four of
Denbury's officers who serve as directors of the General Partner, the same rate
at which our independent directors were paid.
CO2 Volumetric Production Payment and Transportation
We acquired a volumetric production payment from Denbury in November
2003 for $24.4 million. Denbury charges us a transportation fee of $0.16 per Mcf
(adjusted for inflation) to deliver the CO2 for us to our customers. For
November and December 2003, we paid Denbury $355,000 for these transportation
services related to our sales of CO2. See Note 5.
Financing
Our general partner guarantees our obligations under the Fleet
Facility. Our general partner that guarantees the obligations is a wholly-owned
subsidiary of Denbury. The obligations are not guaranteed by Denbury or any of
its other subsidiaries.
Citicorp Credit Agreement
In December 2001, Citicorp began providing us with a working capital
and letter of credit facility. Citicorp and Salomon are both subsidiaries of
Citicorp, Inc. From January 1, 2002, until May 14, 2002, when Citicorp ceased to
be a related party, we incurred letter of credit fees, interest and commitment
fees totaling $396,000 under the Credit Agreement. In December 2001, we paid
Citicorp $900,000 as a fee for providing the facility. This facility fee was
being amortized to earnings over the two-year life of the Credit Agreement and
was included in interest expense on the consolidated statements of operations.
When the facility was replaced in March 2003, the unamortized balance of this
fee totaling $371,000 was charged to interest expense. In 2001, the Partnership
paid Citicorp for interest and commitment fees totaling $27,000.
Guaranty Fees
In 2001, Salomon provided a guaranty facility to the Partnership
and, from January 2002 to April 2002, Salomon provided guaranties under a
transition arrangement with Salomon, Citicorp and the Partnership. For the years
ended December 31, 2002 and 2001, the Partnership paid Salomon $61,000 and
$1,250,000, respectively, for guarantee fees. The guarantee fees are included as
a component in cost of crude on the consolidated statements of operations. These
guarantee fees were less than the cost of a letter of credit facility from a
bank.
70
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. SUPPLEMENTAL CASH FLOW INFORMATION
Cash received by us for interest during the years ended December 31, 2003,
2002 and 2001 was $34,000, $68,000, and $195,000, respectively. Cash payments
for interest were $1,194,000, $537,000, and $1,391,000 during the years ended
December 31, 2003, 2002 and 2001, respectively.
14. EMPLOYEE BENEFIT PLANS
We do not directly employ any of the persons responsible for managing or
operating our activities. Employees of the General Partner provide those
services and are covered by various retirement and other benefit plans.
In order to encourage long-term savings and to provide additional funds
for retirement to its employees, the General Partner sponsors a profit-sharing
and retirement savings plan. Under this plan, the General Partner's matching
contribution is calculated as an equal match of the first 3% of each employee's
annual pretax contribution and 50% of the next 3% of each employee's annual
pretax contribution. The General Partner also made a profit-sharing contribution
of 3% of each eligible employee's total compensation. The expenses included in
the consolidated statements of operations for costs relating to this plan were
$507,000, $564,000, and $603,000 for the years ended December 31, 2003, 2002 and
2001, respectively.
The General Partner also provided certain health care and survivor
benefits for its active employees. In 2003, 2002 and 2001, these benefit
programs were self-insured, with a catastrophic insurance policy to limit our
costs. The General Partner plans to continue self-insuring these plans in the
future. The expenses included in the consolidated statements of operations for
these benefits were $1,368,000, $1,360,000, and $1,526,000 in 2003, 2002 and
2001, respectively.
Stock Appreciation Rights Plan
In December 2003, the Board approved a Stock Appreciation Rights
(SAR) plan for all employees. Under the terms of this plan, all regular,
full-time active employees and the members of the Board are eligible to
participate in the plan. The plan is administered by the Compensation Committee
of the Board, who shall determine, in its full discretion, the number of rights
to award, the grant date of the units and the formula for allocating rights to
the participants and the strike price of the rights awarded. Each right is
equivalent to one Common Unit.
The rights have a term of 10 years from the date of grant. The
initial award to a participant will vest one-fourth each year beginning with the
first anniversary of the grant date of the award. Subsequent awards to
participants will vest on the fourth anniversary of the grant date. If the right
has not been exercised at the end of the ten year term and the participant has
not terminated his employment with us, the right will be deemed exercised as of
the date of the right's expiration and a cash payment will be made as described
below.
Upon vesting, the participant may exercise his rights and receive a
cash payment calculated as the difference between the average of the closing
market price of our Common Units for the ten days preceding the date of exercise
over the strike price of the right being exercised. The cash payment to the
participant will be net of any applicable withholding taxes required by law. If
the Committee determines, in its full discretion, that it would cause
significant financial harm to the Partnership to make cash payments to
participants who have exercised rights under the plan, then the Committee may
authorize deferral of the cash payments until a later date.
Termination for any reason other than death, disability or normal
retirement (as these terms are defined in the plan) will result in the
forfeiture of any non-vested rights Upon death, disability or normal retirement,
all rights will become fully vested. If a participant is terminated for any
reason within one year after the effective date of a change in control (as
defined in the plan) all rights will become fully vested.
On December 31, 2003 awards of 423,057 rights were allocated to
participants with a strike price of $9.26 per right. In 2003, we recorded
non-cash expense of $228,000 for the increase between the strike price of the
outstanding rights and the closing market price for Common Units on December 31,
2003. In 2001, we recorded expense of $55,000 related to a restricted unit plan
that has been terminated.
Bonus Plan
In March 2003, the Compensation Committee of the Board of Directors
of the General Partner approved a Bonus Plan (the "Bonus Plan") for all
employees of the General Partner. The Bonus Plan is designed to enhance the
71
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
financial performance of the Partnership by rewarding all employees for
achieving financial performance objectives. The Bonus Plan will be administered
by the Compensation Committee. Under this plan, amounts will be allocated for
the payment of bonuses to employees each time GCOLP earns $1.6 million of
Available Cash. The amount allocated to the bonus pool increases for each $1.6
million earned, such that a bonus pool of $2.0 million will exist if the
Partnership earns $14.6 million of Available Cash.
Bonuses will be paid to employees after the end of the year, but
only if distributions are made to the Common Unitholders. The amount in the
bonus pool will be allocated to employees based on the group to which they are
assigned. Employees in the first group can receive bonuses that range from zero
to ten percent of base compensation. The next group includes employees in the
professional group, who could earn a total bonus ranging from zero to twenty
percent. Certain members of the professional group that are part of management
or are exceptional performers are eligible to earn a total bonus ranging from
zero to thirty percent. Lastly, our officers and other senior management are
eligible for a total bonus ranging from zero to forty percent. The Bonus Plan
will be at the discretion of the Compensation Committee, and our General Partner
can amend or change the Bonus Plan at any time.
15. MAJOR CUSTOMERS AND CREDIT RISK
We derive our revenues from customers primarily in the crude oil industry.
This industry concentration has the potential to impact our overall exposure to
credit risk, either positively or negatively, in that our customers could be
affected by similar changes in economic, industry or other conditions. However,
we believe that the credit risk posed by this industry concentration is offset
by the creditworthiness of our customer base. Our portfolio of accounts
receivable is comprised in large part of major international corporate entities
with stable payment experience. The credit risk related to contracts which are
traded on the NYMEX is limited due to the daily cash settlement procedures and
other NYMEX requirements.
We have established various procedures to manage our credit exposure,
including initial credit approvals, credit limits, collateral requirements and
rights of offset. Letters of credit, prepayments and guarantees are also
utilized to limit credit risk to ensure that our established credit criteria are
met.
Marathon Ashland Petroleum LLC, ExxonMobil Corporation and Shell Oil
Company accounted for 22.5%, 15.4% and 11.0% of total revenues in 2003,
respectively. Marathon Ashland Petroleum LLC and ExxonMobil Corporation
accounted for 18.5% and 13.6% of total revenues in 2002, respectively. In 2001,
BP Amoco Corporation subsidiaries and Enron Corporation subsidiaries accounted
for 10.6% and 14.1% of total revenues, respectively. The majority of the
revenues from these five customers in all three years relate to our gathering
and marketing operations.
16. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying values of cash and cash equivalents, accounts receivable,
accounts payable and accrued liabilities in the Consolidated Balance Sheets
approximated fair value due to the short maturity of these instruments.
Additionally, the carrying value of the long-term debt approximated fair value
due to its floating rate of interest.
17. DERIVATIVES
Our market risk in the purchase and sale of its crude oil contracts is the
potential loss that can be caused by a change in the market value of the asset
or commitment. In order to hedge our exposure to such market fluctuations, we
may enter into various financial contracts, including futures, options and
swaps. Historically, any contracts we have used to hedge market risk were less
than one year in duration. During 2003 we did not use any hedging instruments.
We may utilize crude oil futures contracts and other financial derivatives
to reduce our exposure to unfavorable changes in crude oil prices. On January 1,
2001, we adopted the provisions of SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities", which established new accounting and
reporting guidelines for derivative instruments and hedging activities. Every
derivative instrument (including certain derivative instruments embedded in
other contracts) must be recorded in the balance sheet as either an asset or
liability measured at its fair value. Changes in the derivative's fair value
must be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a derivative's
gains and losses to offset
72
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
related results on the hedged item in the income statement. Companies must
formally document, designate and assess the effectiveness of transactions that
receive hedge accounting.
We mark to fair value our derivative instruments at each period end with
changes in fair value of derivatives not designated as hedges being recorded as
unrealized gains or losses. Such unrealized gains or losses will change, based
on prevailing market prices, at each balance sheet date prior to the period in
which the transaction actually occurs. Unrealized gains or losses on derivative
transaction qualifying as hedges are reflected in other comprehensive income.
In general, SFAS No. 133 requires that at the date of initial adoption,
the difference between the fair value of derivative instruments and the previous
carrying amount of those derivatives be recorded in net income or other
comprehensive income, as appropriate, as the cumulative effect of a change in
accounting principle. On January 1, 2001, recognition of our derivatives
resulted in a gain of $0.5 million, which was recognized in the consolidated
statement of operations as the cumulative effect of adopting SFAS No. 133.
Certain derivative contracts related to written option contracts had been
recorded on the balance sheet at fair value at December 31, 2000, so no
adjustment was necessary for those contracts upon adoption of SFAS No. 133.
We regularly review our contracts to determine if the contracts qualify
for treatment as derivatives. We had no contracts qualifying for treatment as
derivatives at December 31, 2003.
At December 31, 2002, we determined that the only contract qualifying as a
derivative was a qualifying cash flow hedge. The decrease of $39,000 in the fair
value of this hedge is recorded in other comprehensive income and as accumulated
other comprehensive income in the consolidated balance sheet. No hedge
ineffectiveness was recognized during 2002. The anticipated transaction (crude
oil sales) occurred in January 2003, and all related amounts held in other
comprehensive income at December 31, 2002, were reclassified to the consolidated
statement of operations in the first quarter of 2003.
We determined that all other derivative contracts qualified for the normal
purchase and sale exemption at December 31, 2003 and 2002. The decrease in fair
value of our net asset for derivatives not qualifying as hedges during 2002 was
$2.1 million. The increase in fair value of our net asset for derivatives not
qualifying as hedges during 2001 was $1.7 million. These changes in fair value
are recorded in the consolidated statements of operations under the caption
"Change in fair value of derivatives."
18 COMMITMENTS AND CONTINGENCIES
Commitments and Guarantees
We lease office space for our headquarters office under a long-term
lease. The lease extends until October 31, 2005. We lease office space for a
field office under a lease that expires in 2007. Ryder provides tractors and
trailers to us under an operating lease that also includes full-service
maintenance. Under the terms of the lease, we lease 46 tractors and 46 trailers.
We pay a fixed monthly rental charge for each tractor and trailer and a fee
based on mileage for the maintenance services. We have ordered an additional 5
tractors and trailers from Ryder that we expect to receive during the first
quarter of 2004. We lease three tanks for use in our pipeline operations. The
tank lease expires in 2004, however we have advised the lessor that we may want
to extend the lease. Additionally, we lease a segment of pipeline. Under the
terms of that lease, we make lease payments based on throughput, and we have no
minimum volumetric or financial requirements remaining. We also lease service
vehicles for our field personnel.
73
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The future minimum rental payments under all non-cancelable operating
leases as of December 31, 2003, were as follows (in thousands).
Office Tractors and Service
Space Trailers Tanks Vehicles Total
------ ------------ ------ -------- ------
2004 ........................................ $ 489 $1,734 $ 465 $ 360 $3,048
2005 ........................................ 410 2,338 -- 204 2,952
2006 ........................................ 18 559 -- 10 587
2007 ........................................ 15 531 -- -- 546
2008 ........................................ -- 528 -- -- 528
2009 and thereafter ......................... -- 935 -- -- 935
------ ------ ------ ------ ------
Total minimum lease obligations ............. $ 932 $6,625 $ 465 $ 574 $8,596
====== ====== ====== ====== ======
Total operating lease expense was as follows (in thousands).
Year ended December 31, 2003............................. $ 4,736
Year ended December 31, 2002............................. $ 4,713
Year ended December 31, 2001............................. $ 4,379
We have guaranteed $3.3 million of residual value related to the leases of
tractors and trailers. We believe the likelihood we would be required to perform
or otherwise incur any significant losses associated with this guaranty is
remote.
GELP has guaranteed crude oil purchases of GCOLP. These guarantees,
totaling $11.4 million, were provided to counterparties. To the extent
liabilities exist under the contracts subject to these guarantees, such
liabilities are included in the consolidated balance sheet.
GELP, the General Partner and the subsidiaries of GCOLP have guaranteed
the payments by GCOLP to Fleet under the terms of the Fleet Facility related to
borrowings and letters of credit. Borrowings at December 31, 2003 were $7.0
million and are reflected in the consolidated balance sheet. To the extent
liabilities exist under the letters of credit, such liabilities are included in
the consolidated balance sheet.
We have contractual commitments (forward contracts) arising in the
ordinary course of our crude oil marketing activities. At December 31, 2003, the
Partnership had commitments to purchase 1,854,000 barrels of crude oil in
January 2004, and 986,000 barrels of crude oil between February 2004, and
October 2004. We had commitments to sell 1,865,000 barrels of crude oil in
January 2004, and 690,000 barrels of crude oil between February 2004 and June
2004. All of these contracts are associated with market-price-related contracts.
The total commitment to purchase crude oil would be valued at $89.4 million,
using market prices at December 31, 2003. The total commitment to sell crude oil
would be valued at $82.0 million, using market prices at December 31, 2003.
In general, we expect to increase our expenditures in the future to comply
with higher industry and regulatory safety standards and Securities and Exchange
Commission (SEC) regulations. During 2004, we expect to spend between $0.5
million and $1.0 million related to compliance with the requirements of the
Sarbanes Oxley Act of 2002 as required by the SEC. While the total amount of
increased expenditures cannot be accurately estimated at this time, we
anticipate that we will expend a total of approximately $2.2 million in 2004 and
2005 for testing and rehabilitation under regulations requiring assessment of
the integrity of crude oil pipelines.
Pennzoil Litigation
We were named one of the defendants in a complaint filed on January 11,
2001, in the 125th District Court of Harris County, Texas, Cause No. 2001-01176.
Pennzoil-Quaker State Company ("PQS") was seeking property damages, loss of use
and business interruption suffered as a result of a fire and explosion that
occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on
January 18, 2000. PQS claimed the fire and explosion were caused, in part, by
Genesis selling to PQS crude oil that was contaminated with organic chlorides.
In December 2003, our insurance carriers settled this litigation for $12.8
million. We have recorded in Accrued Liabilities on our consolidated statement
of operations the obligation for this settlement, and in Insurance Receivable we
have recorded the insurance reimbursement for this obligation. The settlement
was funded in
74
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
February 2004, with certain insurance companies directly funding $5.9 million of
the payment and $6.9 million was funded by us. We will receive reimbursement of
the $6.9 million from the insurance company no later than May 2004.
PQS is also a defendant in five suits brought by neighbors living in
the vicinity of the PQS Shreveport, Louisiana refinery in the First Judicial
District Court, Caddo Parish, Louisiana, Cause Nos. 455,647-A. 455,658-B,
455,655-A, 456,574-A, and 458,379-C. PQS has brought third party demand against
Genesis and others for indemnity with respect to the fire and explosion of
January 18, 2000. We believe that the demand against Genesis is without merit
and intend to vigorously defend ourselves in this matter.
Environmental
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 nearby. A portion of the oil
then flowed into the Leaf River. The oil spill is covered by insurance and the
direct financial impact to us of the cost of the clean-up has not been material.
Included in insurance receivable on the consolidated balance sheet at December
31, 2003 is $2.8 million related to this spill. Management of the Partnership
has reached an agreement in principle with the US Environmental Protection
Agency and the Mississippi Department of Environmental Quality for the payment
of fines under environmental laws with respect to this oil spill. Based on this
agreement in principle, in 2001 and 2002, a total accrual of $3.0 million was
recorded for these fines. The fines will not be covered by insurance.
We are subject to various environmental laws and regulations.
Policies and procedures are in place to monitor compliance and to detect and
address any releases of crude oil from our pipelines or other facilities,
however no assurance can be made that such environmental releases may
substantially affect our business.
Other Matters
We have taken additional security measures since the terrorist
attacks of September 11, 2001 in accordance with guidance provided by the
Department of Transportation and other government agencies. We cannot assure you
that these security measures would prevent our facilities from a concentrated
attack. Any future attacks on us or our customers or competitors could have a
material effect on our business, whether insured or not. We believe we are
adequately insured for public liability and property damage to others and that
our coverage is similar to other companies with operations similar to ours. No
assurance can be made that we will be able to maintain adequate insurance in the
future at premium rates that we consider reasonable.
We are subject to lawsuits in the normal course of business and
examination by tax and other regulatory authorities. Such matters presently
pending are not expected to have a material adverse effect on our financial
position, results of operations or cash flows.
75
EXHIBIT INDEX
Exhibits
3.1 Certificate of Limited Partnership of Genesis Energy,
L.P. ("Genesis") (incorporated by reference to Exhibit
3.1 to Registration Statement, File No. 333-11545)
3.2 Third Amended and Restated Agreement of Limited
Partnership of Genesis (incorporated by reference to
Exhibit 4.1 of Form 8-K dated July 31, 2002)
3.3 Certificate of Limited Partnership of Genesis Crude Oil,
L.P. (the "Operating Partnership") (incorporated by
reference to Exhibit 3.3 to Form 10-K for the year
ended December 31, 1996)
3.4 Third Amended and Restated Agreement of Limited
Partnership of the Operating Partnership (incorporated
by reference to Exhibit 4.1 to Form 8-K dated July 31,
2002)
10.1 Purchase & Sale and Contribution & Conveyance Agreement
dated as of December 3, 1996 among Basis Petroleum,
Inc. ("Basis"), Howell Corporation ("Howell"), certain
subsidiaries of Howell, Genesis, the Operating
Partnership and Genesis Energy, L.L.C. (incorporated
by reference to Exhibit 10.1 to Form 10-K for the year
ended December 31, 1996)
10.2 First Amendment to Purchase & Sale and Contribution &
Conveyance Agreement (incorporated by reference to
Exhibit 10.2 to Form 10-K for the year ended December
31, 1996)
10.3 Office Lease at One Allen Center between Trizec Allen
Center Limited Partnership (Landlord) and Genesis
Crude Oil, L.P. (Tenant) (incorporated by reference to
Exhibit 10 to Form 10-Q for the quarterly period ended
September 30, 1997)
10.4 Credit Agreement dated as of March 14, 2003, between
Genesis Crude Oil, L.P., Genesis Energy, Inc. Genesis
Energy, L.P., Fleet National Bank and Certain
Financial Institutions (incorporated by reference to
Exhibit 10.10 to Form 10-K for the year ended December
31, 2002)
10.5 Pipeline Sale and Purchase Agreement between TEPPCO
Crude Pipeline, L.P. and Genesis Crude Oil, L.P. and
Genesis Pipeline, L.P. (incorporated by reference to
Exhibit 10.1 to Form 8-K dated October 31, 2003)
10.6 Purchase and Sale Agreement between TEPPCO Crude
Pipeline, L.P. and Genesis Crude Oil, L.P. (incorporated
by reference to Exhibit 10.2 to Form 8-K dated October
31, 2003)
*10.7 Production Payment Purchase and Sale Agreement between
Denbury Resources, Inc. and Genesis Crude Oil, L.P.
executed November 14, 2003
*10.8 Carbon Dioxide Transportation Agreement between Denbury
Resources, Inc. and Genesis Crude Oil, L.P.
*10.9+ Genesis Energy, Inc. Stock Appreciation Rights Plan.
11.1 Statement Regarding Computation of Per Share Earnings
(See Notes 2 and 7 to the Consolidated Financial
Statements)
*21.1 Subsidiaries of the Registrant
*31.1 Certification by Chief Executive Officer Pursuant to
Rule 13a-14(a) under the Securities Exchange Act of
1934.
*31.2 Certification by Chief Financial Officer Pursuant to
Rule 13a-14(a) under the Securities Exchange Act of
1934.
*32.1 Certification by Chief Executive Officer Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2 Certification by Chief Financial Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
----------
* Filed herewith
+ A management contract or compensation plan or arrangement.