Back to GetFilings.com
================================================================================
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the fiscal year ended December 31, 2004
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.
[ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Securities Exchange Act of 1934).
[X]
The aggregate market value of the Common Units held by non-affiliates of the
Registrant on June 30, 2004 (the last business day of Registrant's most recently
completed second fiscal quarter), was approximately $96,293,000 based on $11.25
per unit, the closing price of the Common Units as reported on the American
Stock Exchange on such date. At March 1, 2005, 9,313,811 Common Units were
outstanding.
================================================================================
GENESIS ENERGY, L.P.
2004 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
Page
----
PART I
Items 1. Business and Properties............................................................................... 4
and 2
Item 3. Legal Proceedings..................................................................................... 13
Item 4. Submission of Matters to a Vote of Security Holders................................................... 14
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities........................................................................................... 14
Item 6. Selected Financial Data............................................................................... 15
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................. 17
Item 7A. Quantitative and Qualitative Disclosures about Market Risks........................................... 40
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
Item 9B. Other Information..................................................................................... 43
PART III
Item 10. Directors and Executive Officers of the Registrant.................................................... 43
Item 11. Executive Compensation................................................................................ 45
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters........ 48
Item 13. Certain Relationships and Related Transactions........................................................ 49
Item 14. Principal Accountant Fees and Services................................................................ 50
PART IV
Item 15. Exhibits and Financial Statement Schedules............................................................ 51
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," "continue," "believe,"
"estimate," "expect," "plan," "may," :will," or "intend" or the negative of
those terms and similar expressions and statements regarding our business
strategy, plans and objectives of our management for future operations. We make
these statements based on our 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.
Forward-looking statements are not guarantees of performance. They involve
risks, uncertainties and assumptions. Future actions, conditions or events and
future results of operations may differ materially from those expressed in these
forward-looking statements. Many of the factors that will determine these
results are beyond our ability to control or predict. Specific factors that
could cause actual results to differ from those in the forward-looking
statements include:
- demand for the supply of, changes in forecast data for, and price trends
related to crude oil, liquid petroleum, natural gas and natural gas
liquids in the United States, all of which may be affected by economic
activity, capital expenditures by energy producers, weather, alternative
energy sources, international events, conservation and technological
advances;
- throughput levels and rates;
- changes in, or challenges to, our tariff rates;
- our ability to successfully identify and consummate strategic
acquisitions, make cost saving changes in operations and integrate
acquired assets or businesses into our existing operations;
- service interruptions in our pipeline transportation systems;
- shut-downs or cutbacks at refineries, petrochemical plants, utilities or
other businesses for which we transport crude oil or to whom we sell crude
oil;
- changes in laws or regulations to which we are subject;
- our inability to borrow or otherwise access funds needed for operations,
expansions or capital expenditures as a result of existing debt agreements
that contain restrictive covenants;
- loss of key personnel;
- the effects of competition;
- hazards and operating risks that may not be covered fully by insurance;
- the condition of the capital markets in the United States;
- the political and economic stability of the oil producing nations of the
world; and
- general economic conditions, including rates of inflation and interest
rates.
You should not put undue reliance on any forward-looking statements. When
considering forward-looking statements, please review the risk factors described
under "Risk Factors" 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.
3
PART I
ITEMS 1 AND 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"). During 2004, we were engaged
primarily in three operations - crude oil gathering and marketing, pipeline
transportation and carbon dioxide (CO2) marketing. Beginning in 2005, we will
also began providing pipeline transportation services for natural gas and carbon
dioxide (CO2). See additional discussion below.
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 51
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 pipeline 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.
Beginning in November 2003, we acquired assets enabling us to start a
wholesale CO2 operation. We acquired a volumetric production payment ("VPP")
from Denbury Resources Inc. ("Denbury") that provides us with 167.5 billion
cubic feet (Bcf) of CO2. We also acquired from Denbury three of their long-term
industrial supply contracts for CO2. In September 2004, we acquired another VPP
from Denbury that provides us with an additional 33.0 Bcf of CO2, and two
long-term industrial supply contracts with a customer. 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 expire at various dates between 2010 and
2016.
We constructed a 10 mile CO2 pipeline in Mississippi that connects to a
CO2 pipeline owned by Denbury. Denbury will use this pipeline to transport CO2
to the Brookhaven field in Mississippi for tertiary recovery of crude oil. We
also constructed a crude oil pipeline to carry the crude oil to our existing
Mississippi System.
In January 2005, we acquired fourteen natural gas pipeline and gathering
systems located in Texas, Louisiana and Oklahoma from Multifuels Energy Asset
Group, L.P. These fourteen systems are comprised of 60 miles of pipeline and
related assets.
On February 3, 2005, we entered into a definitive agreement to acquire a
50% interest in a partnership that owns a syngas manufacturing facility located
in Texas City, Texas. The acquisition of this interest is subject to a right of
first refusal by the holder of the other 50% interest in the partnership that
must be exercised within 60 days.
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.,
Genesis Pipeline USA, L.P., Genesis CO2 Pipeline, L.P., Genesis Natural Gas
Pipeline, L.P. and
4
Genesis Syngas Investments, L.P. The General Partner is owned by Denbury
Gathering & Marketing, Inc., a subsidiary of Denbury Resources Inc.
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 any 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. We do not 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, market price changes can impact us.
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 2004, our
bulk and exchange transactions averaged 14,500 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 51 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 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 2004, we distributed payments to approximately
13,000 interest owners.
5
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 we will extend 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 we sell 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. During 2004, more than ten percent of our crude oil sales were
made to each of three customers. We do not believe that the loss of any of these
customers would have a material adverse effect on us as crude oil is a readily
marketable commodity.
Our largest competitors in the purchase of leasehold crude oil production
are Plains Marketing, 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. ("TEPPCO"), 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.
Pipeline Transportation
Through the pipeline systems we own and operate, we 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, if the products tendered for transportation satisfy the
conditions and specifications contained in the applicable tariff. Pipeline
revenues are a function of the level of throughput and the 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
6
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, we hold them as
inventory at the lower of cost or market value. When the volumes are sold, we
recognize any difference between the carrying amount and the sale price 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 90-mile Texas system, the
100-mile Jay System, and the 280-mile Mississippi System.
In 2003, we sold portions of our Texas system to TEPPCO and to Blackhawk
Pipeline, L.P. ("Blackhawk"), an affiliate of MultiFuels, Inc. TEPPCO also
acquired our crude oil gathering and marketing operations in the 40-county area
surrounding the pipeline segments it purchased. The segments we sold to
Blackhawk had been idle since 2002. During 2003 we also abandoned in place
segments that had been idled in 2002.
The segments of the Texas system that we continue to operate extend from
West Columbia to Webster, Webster to Texas City and Webster to Houston. These
segments include approximately 90 miles of pipe. We entered into a joint tariff
with TEPPCO to receive oil from their system at West Columbia and a joint tariff
with TEPPCO and ExxonMobil Pipeline Company ("Exxon") to receive oil from their
systems at Webster. We also continue to receive barrels from a connection with
Seminole Pipeline Company at Webster.
We own approximately 110,000 barrels of storage capacity associated with
the Texas pipeline system. We lease approximately 165,000 barrels of storage
capacity for the Texas System in Webster. We have a tank rental reimbursement
agreement effective January 1, 2005 with the primary shipper on the Texas System
to reimburse us for the lease of this storage capacity at 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 out of service since
February 1, 2002. A connecting carrier tested its pipeline and decided not to
reactivate its pipeline. During the second quarter of 2004, we displaced the
crude oil in this segment with inhibited water. In 2004 and 2003, this segment
did not contribute to pipeline revenues. In the third quarter of 2004, we wrote
this segment down to its estimated salvage value, recording an impairment charge
of $0.9 million.
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.
During 2004, we constructed a 10 mile CO2 pipeline that is connected to
Denbury's 183 mile pipeline that transports CO2 from their Jackson Dome CO2
reservoir. Our pipeline will move the CO2 to the Brookhaven oil field to be used
by Denbury in tertiary recovery. We constructed an 11-mile extension to our
Mississippi oil pipeline next to the CO2 pipeline to transport the crude oil
from the Brookhaven field to our existing pipeline. We also constructed a 5 mile
extension from our existing Mississippi crude oil pipeline to Denbury's Olive
field during 2004.
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 majority of the volumes on our systems are shipped by large oil companies.
Under the joint tariffs with TEPPCO and Exxon for the Texas system, TEPPCO
invoices and collects the tariff from the shipper and remits to us our share of
the joint tariff.
The only shippers on our Mississippi System as of December 31, 2004 are
Genesis Crude Oil, L.P. and Denbury. In September 2004, Denbury started shipping
its production to Liberty for sale to third parties. Prior to that time, Genesis
purchased and shipped their production as well as the production from
third-party producers. Now Genesis buys production from third-party producers
and ships it on the pipeline for sale at Liberty.
7
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 VPP from Denbury consisting of 167.5 Bcf of CO2. We also acquired
from Denbury three long-term CO2 agreements with industrial customers to supply
CO2 through 2015. In September 2004, we acquired another VPP from Denbury
consisting of 33.0 Bcf of CO2 and two agreements with an industrial customer.
Denbury transports the CO2 to the customers, charging us a fee. We then sell the
CO2 to the customers who treat the CO2 and sell it to end users for use for
beverage carbonation and food chilling and freezing. At December 31, 2004, we
have 178.7 Bcf of CO2 remaining under the VPPs. Denbury owns 2.7 trillion cubic
feet of estimated proved reserves of CO2 in the Jackson Dome area near Jackson,
Mississippi.
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 that may be used in food processing than
does the CO2 that is a by-product of other chemical processes. 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, 2004, 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 ("SEC") 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 requirements to make filings with the SEC available
on our website. Additional rules include disclosures
8
regarding audit committee financial experts and committee 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 are required to include in this 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 have also been 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
joint tariffs with TEPPCO and Exxon. Approximately 13% 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 stringent federal, state and local laws and regulations
governing the discharge of materials into the environment or otherwise relating
to environmental protection. These laws and regulations may require the
acquisition of permits for regulated activities, limit or prohibit operations on
environmentally sensitive lands such as wetlands or wilderness areas, result in
capital expenditures to limit or prevent emissions or discharges, and place
burdensome restrictions on the management and disposal of wastes. Failure to
comply with these laws and regulations may result in the assessment of
administrative, civil and criminal penalties, the imposition of remedial
obligations, and even the issuance of injunctive relief. Changes in
environmental laws and regulations occur frequently, and any changes that result
in more stringent and costly waste handling, disposal or cleanup requirements
have the potential to have a material adverse effect on our operations. While we
believe that we are in substantial compliance with current environmental laws
and regulations and that continued compliance with existing requirements would
not materially affect us, there is no assurance that this trend will continue in
the future.
The Comprehensive Environmental Response, Compensation, and Liability Act,
as amended, ("CERCLA"), also known as the "Superfund" law, and analogous state
laws impose 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
"responsible persons" 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. We also may incur liability under the Resource
Conservation and Recovery Act, as amended ("RCRA"), which imposes requirements
relating to the management and disposal of solid and hazardous wastes.
9
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 discharged into surface water. 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 clean up and related
costs are covered by insurance and the financial impact to us for the cost of
the clean-up has not been material. During 2004, we finalized agreements with
the US Environmental Protection Agency ("EPA") and the Mississippi Department of
Environmental Quality ("MDEQ") pursuant to which we paid a $3.0 million fine
with respect to this spill. The fine was recorded to expense in 2001 and 2002.
Because we currently own or lease, and have in the past owned or leased,
properties that have been in use for many years by various persons including
third parties over whom we have no control in connection with the gathering and
transportation of hydrocarbons including crude oil, and further because we may
generate, handle and dispose of materials in the course of our operations that
fall within the definition of "hazardous substances" or "Hazardous wastes," we
may incur liability under CERCLA, RCRA and analogous state laws for hydrocarbons
or other wastes that may have been disposed of or released on or under those
properties or under other locations where such wastes have been taken for
disposal. Under these laws, we could be required to remove previously disposed
wastes, remediate environmental contamination, restore affected properties, or
undertake measures to prevent future contamination.
The Federal Water Pollution Control Act, as amended, also known as the
"Clean Water Act" and analogous state laws impose restrictions and controls
regarding the discharge of pollutants, including crude oil, into federal and
state waters. The Clean Water Act provides civil and even criminal penalties for
any discharges of oil in harmful quantities and imposes liabilities for the
costs of removing an oil spill. Federal and state permits for water discharges
also may be required. The Oil Pollutions Act, as amended ("OPA"), requires
operators of offshore facilities and certain onshore facilities near or crossing
waterways to provide financial assurance ranging from $10 million in state
waters to $35 million in federal waters to cover potential environmental cleanup
and restoration costs, and this amount can be increased to a maximum of $150
million under certain limited circumstances where the Minerals Management
Service believes such a level is justified based on the worst case spill risks
posed by the operations. We have developed an Integrated Contingency Plan to
satisfy components of the OPA as well as the federal Department of
Transportation, the federal Occupational Safety Health Act ("OSHA") and state
regulations. This plan meets regulatory requirements as to notification,
procedures, response actions, response resources and spill impact considerations
in the event of an oil spill.
The Clean Air Act, as amended, restricts the emission of air pollutants
including volatile organic compounds or "VOCs" that contribute to the formation
of ozone. These VOC 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.
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 primary effect of NEPA
may be to delay or prevent construction or to alter the proposed location,
design or method of construction.
Safety and Security Regulations
Our crude oil pipelines are subject to construction, installation,
operation and safety regulation by the Department of Transportation ("DOT") and
various other federal, state and local agencies. The Pipeline Safety Act of
1992, among other things, amends the Hazardous Liquid Pipeline Safety Act of
1979 ("HLPSA") in several important respects. It requires the Research and
Special Programs Administration ("RSPA") of DOT to consider environmental
impacts, as well as its traditional public safety mandates, when developing
pipeline safety regulations. In addition, the Pipeline Safety Improvement Act of
2002 mandates the establishment by DOT of pipeline operator qualification rules
requiring minimum training requirements for operators, the development of
standards and criteria to evaluate contractor's methods to qualify their
employees and requires that pipeline operators provide maps and other records to
the DOT. It also authorizes the DOT to require that pipelines be modified to
accommodate internal inspection devices, to mandate the evaluation of emergency
flow restricting devices for pipelines in populated or sensitive areas, and to
order other changes to the operation and maintenance of
10
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 DOT 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 ("HCA") including
certain populated areas and environmentally sensitive areas.. 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 integrity of these
pipelines must be assessed by internal inspection, pressure test, or equivalent
alternative new technology.
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
impact 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 to 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 OSHA and
comparable state statutes. We believe that our crude oil pipelines and trucking
operations have been operated in substantial compliance with OSHA requirements,
including general industry standards, record keeping requirements and monitoring
of occupational exposure to regulated substances. Various other federal and
state regulations require that we train all employees in pipeline and trucking
operations in HAZCOM and disclose information about the hazardous materials used
in our operations. Certain information must be reported to employees, government
agencies and local citizens upon request.
In general, we expect to increase our expenditures in the future to comply
with higher industry and regulatory safety standards such as those described
above. While the total amount of increased expenditures cannot be accurately
estimated at this time, we anticipate that we will spend a total of
approximately $2.0 million in 2005 and 2006 for testing and improvements 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 Interstate Commerce Commission, 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
11
("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 unitholder's 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.
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.
12
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. Recent
legislation treats net income derived from the ownership of certain publicly
traded partnerships (including us) as qualifying income to a regulated
investment company. However, this legislation is only effective for taxable
years beginning after October 22, 2004, the date of enactment. For taxable years
beginning on or before the date of enactment, very little of our income will be
qualifying income to a regulated investment company. Furthermore, 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.
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. (See
Note 17. Commitments and Contingencies.)
13
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 EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
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)
-------- -------- ----------------
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
2004
First Quarter............................................... $ 12.65 $ 9.65 $ 0.15
Second Quarter.............................................. $ 13.19 $ 8.80 $ 0.15
Third Quarter............................................... $ 12.50 $ 10.66 $ 0.15
Fourth Quarter.............................................. $ 12.80 $ 11.30 $ 0.15
- ---------------------
(1) Cash distributions are shown in the quarter paid and are based on the prior
quarter's activities.
At December 31, 2004, there were 9,313,811 Common Units outstanding,
including 688,811 Common Units held by our General Partner. As of December 31,
2004, there were approximately 5,000 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.
We did not pay regular distributions for the fourth quarter of 2001 or for
2002. In 2003, we began paying quarterly distributions again with distributions
for the first quarter of 2003 of $0.05 per unit. Beginning in the fourth quarter
of 2003, we increased our distribution to $0.15 per unit (which was paid in
February 2004).
14
ITEM 6. SELECTED FINANCIAL DATA
The table below includes selected financial data for the Partnership for
the years ended December 31, 2004, 2003, 2002, 2001, and 2000 (in thousands,
except per unit and volume data).
Year Ended December 31,
----------------------------------------------------------------------------------
2004 2003 2002 2001 2000
---------- ----------- ------------ ------------ ------------
INCOME STATEMENT DATA:
Revenues:
Crude oil gathering & marketing....... $ 901,902 $ 641,684 $ 639,143(1) $ 3,001,632 $ 3,897,799
Pipeline transportation............... 16,680 15,134 13,485 9,948 10,728
CO2 marketing......................... 8,561 1,079 - - -
---------- ----------- ------------ ------------ ------------
Total revenues..................... 927,143 657,897 652,628 3,011,580 3,908,527
Costs and expenses:
Crude oil and field operating......... 897,868 633,776 627,966(1) 2,991,904 3,887,474
Pipeline operating.................... 8,137 10,026 8,076 7,038 5,342
CO2 marketing transportation costs.... 2,799 355 - - -
General and administrative expenses... 11,031 8,768 7,864 11,307 10,623
Depreciation and amortization......... 7,298(2) 4,641 4,603 14,929(2) 6,023
Change in fair value of derivatives... - - 1,279 (1,681) -
Loss (gain) from sales of surplus
assets.............................. 33 (236) (705) (167) (1,148)
Other operating charges............... - - 1,500 1,500 1,387
---------- ----------- ------------ ------------ ------------
Total costs and expenses........... 927,166 657,330 650,583 3,024,830 3,909,701
---------- ----------- ------------ ------------ ------------
Operating (loss) income from continuing
operations.......................... (23) 567 2,045 (13,250) (1,174)
Interest expense, net..................... (926) (986) (1,035) (527) (1,010)
Minority interests effects................ - - - 1 223
---------- ----------- ------------ ------------ ------------
(Loss) income in continuing operations
before cumulative effect of change
in accounting principle............. (949) (419) 1,010 (13,776) (1,961)
(Loss) income from discontinued
operations.......................... (463) 13,741 4,082 (30,303)(2) 2,142
Cumulative effect of change in accounting
principle, net of minority interest
effect.............................. - - - 467 -
---------- ----------- ------------ ------------ ------------
Net (loss) income......................... $ (1,412) $ 13,322 $ 5,092 $ (43,612) $ 181
========== =========== ============ ============ ============
Net (loss) income per common unit-basic
and diluted:
Continuing operations................. $ (0.10) $ (0.05) $ 0.12 $ (1.57) $ (0.22)
Discontinued operations............... (0.05) 1.55 0.46 (3.44) 0.24
Cumulative effect of change in
accounting principle................ - - - 0.05 -
---------- ----------- ------------ ------------ ------------
Net (loss) income..................... $ (0.15) $ 1.50 $ 0.58 $ (4.96) $ 0.02
========== =========== ============ ============ ============
Cash distributions per common unit:....... $ 0.60 $ 0.15 $ 0.20 $ 0.80 $ 2.28
15
Year Ended December 31,
----------------------------------------------------------------------------------
2004 2003 2002 2001 2000
---------- ----------- ------------ ------------ ------------
BALANCE SHEET DATA (AT END OF PERIOD):
Current assets.......................... $ 77,396 $ 88,211 $ 92,830 $ 182,100 $ 350,604
Total assets .......................... 143,154 147,115 137,537 230,113 449,343
Long-term liabilities................... 15,460 7,000 5,500 13,900 -
Minority interests...................... 517 517 515 515 520
Partners' capital....................... 45,239 52,354 35,302 32,009 82,615
OTHER DATA:
Maintenance capital expenditures(3)..... $ 939 $ 4,178 $ 4,211 $ 1,882 $ 1,685
Volumes-continuing operations:
Crude oil gathering and marketing:
Wellhead (bpd).................... 45,919 45,015 47,819 67,373 94,995
Bulk and exchange (bpd)........... 14,500 11,790 25,610(1) 253,159 264,235
Crude oil pipeline (bpd)............ 63,441 66,959 71,870 80,408 82,092
CO2 marketing (Mcf per day)......... 45,312 36,332(4) - - -
(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 2004, we recorded an impairment charge of $0.9 million related to our
pipeline operations. 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 in 2003 that we
owned the assets.
The table below summarizes our quarterly financial data for 2004 and 2003
(in thousands, except per unit data).
2004 Quarters
--------------------------------------------------
First Second Third Fourth
---------- ---------- ---------- ----------
Revenues - continuing operations................ $ 198,912 $ 232,107 $ 250,736 $ 245,388
Operating (loss) income - continuing
operations..................................... $ (612) $ 1,488 $ (156) $ (743)
(Loss) income from continuing
operations..................................... (782) 1,160 (359) (968)
Loss from discontinued operations............... (223) (61) (35) (144)
Net (loss) income............................... $ (1,005) $ 1,099 $ (394) $ (1,112)
Net (loss) income per Common Unit-basic and
diluted........................................ $ (0.11) $ 0.12 $ (0.04) $ (0.12)
2003 Quarters
--------------------------------------------------
First Second Third Fourth
---------- ---------- ---------- ----------
Revenues - continuing operations................ $ 175,682 $ 146,670 $ 157,094 $ 178,451
Operating income (loss) - continuing
operations.................................... $ 924 $ 907 $ (1,409) $ 145
Income (loss) from continuing operations........ 382 749 (1,565) 15
Income from discontinued operations............. 497 1,141 352 11,751
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
16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATION
Included in Management's Discussion and Analysis are the following
sections:
- Overview of 2004
- Acquisitions in 2005
- Critical Accounting Policies
- Results of Operations and Outlook for 2005 and Beyond
- Liquidity and Capital Resources
- Commitments and Off-Balance Sheet Arrangements
- Other Matters
- New Accounting Pronouncements
- Risk Factors
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
9 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 "Liquidity and
Capital Resources - Non-GAAP Financial Measure" below.
OVERVIEW OF 2004
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., Genesis
Pipeline, USA, L.P., Genesis CO2 Pipeline, L.P. and Genesis Natural Gas
Pipeline, 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,
pipeline transportation and CO2 marketing. We generate revenues by selling crude
oil and CO2 and by charging fees for the transportation of crude oil, natural
gas and CO2 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, natural gas 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. During 2004, we
generated Available Cash before reserves that exceeded the amount we distributed
by more than ten percent. In 2004, we improved our ability to meet this goal by:
- Expanding our credit facility to include an acquisition component;
- Purchasing a CO2 volumetric production payment and related marketing
contracts; and
- Building three new pipeline segments for crude oil and CO2
transportation.
Additionally, in 2005, we have entered into two transactions to acquire
assets to increase Available Cash for distribution to our unitholders.
17
In June 2004, we replaced our existing bank credit facility with a group
of banks led by Bank of America as agent with a $100 million senior secured bank
credit facility (the "Credit Agreement"). The Credit Agreement consists of a $50
million revolving line of credit for acquisitions and a $50 million working
capital revolving credit facility.
During the third quarter of 2004, we acquired a 33 Bcf volumetric
production payment and related industrial sales contracts from Denbury for $4.7
million, further expanding our CO2 marketing business.
Our continuing gathering and marketing segment did not perform as well as
expected in 2004. Volatility in P-Plus market prices for crude oil continued to
create fluctuations in our crude oil gathering and marketing segment margin.
Higher field costs due to increased fuel prices and increases in payroll and
fleet repair costs also contributed to reduce our margin in this segment.
Our pipeline transportation segment showed improvement in 2004. Revenues
from our pipeline transportation operations increased primarily due to tariff
increases and the sale of crude oil volumes deducted from shippers as pipeline
loss allowances that exceeded actual losses. The high crude oil prices in 2004
increased our segment margin from these sales.
During 2004, we incurred expenses totaling $1.3 million for professional
services to assist us in the internal control documentation and assessment
provisions of the Sarbanes-Oxley Act including additional audit fees related to
this process.
ACQUISITIONS IN 2005
Gas Gathering and Marketing Assets
In January 2005, we acquired fourteen natural gas pipeline and gathering
systems located in Texas, Louisiana and Oklahoma from Multifuels Energy Asset
Group, L.P. for $3.1 million. These fourteen systems total to 60 miles of
pipeline and related assets. This acquisition was financed through our Credit
Agreement. This acquisition will enable us to complement our existing operations
enabling us to provide gas gathering and marketing services in areas where we
have existing operations and relationships with oil and gas producers.
Syngas Investment
On February 3, 2005 we entered into a definitive agreement with TCHI Inc.,
a wholly owned subsidiary of ChevronTexaco Global Energy Inc., to purchase its
50% partnership interest in T & P Syngas Supply Company (T&P Syngas) for $13.5
million, subject to normal closing conditions. The acquisition is subject to a
right of first refusal held by Praxair Hydrogen Supply, Inc. ("Praxair"), which
holds the other 50% interest in the partnership. Praxair must exercise the right
of first refusal within 60 days of February 4, 2005.
T&P Syngas is a partnership that owns a syngas manufacturing facility
located in Texas City, Texas. This facility processes natural gas to produce
syngas (a combination of carbon monoxide and hydrogen) and high pressure steam.
All of the syngas and steam produced by the facility is sold to Praxair under a
long-term processing agreement.
The acquisition, if concluded, will be financed through our Credit
Agreement.
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. We discuss these policies below.
18
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.
The provisions of SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities, as amended and interpreted, 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. We refer to these
deductions as pipeline loss allowances.
We compare these allowances 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, we reduce any recorded
inventory on hand and record a liability for the purchase of crude oil that we
must make to replace the lost volumes. We reflect inventories in the financial
statements at the lower of the recorded value or the market value at the balance
sheet date. We value liabilities to replace crude oil 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.
We cannot predict future pipeline loss allowance revenue because these
revenues depend 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.
We base our calculation of the useful life of an asset 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.
19
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, we make accruals. We base our estimates on all known facts
at the time and our assessment of the ultimate outcome, including consultation
with external experts and counsel. We revise these estimates 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, we increased this estimate to a total of $3.0 million in
2002. We paid fines totaling $3.0 million in 2004.
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. We sometimes make these estimates with the assistance of third
parties involved in monitoring the remediation effort.
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. We based this estimate 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 recorded a receivable from the insurers for a similar amount.
We believe our estimates for contingent liabilities are reasonable, but we
cannot assure you that actual amounts will not vary from estimated amounts.
RESULTS OF OPERATIONS AND OUTLOOK FOR 2005 AND BEYOND
CRUDE OIL GATHERING AND MARKETING OPERATIONS
The key factors affecting our crude oil gathering and marketing segment
margin include production volumes, volatility of P-Plus, volatility of grade
differentials, inventory management, field operating costs 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 costs of sales by equivalent
amounts. Because period-to-period variations in revenues and costs of sales are
not generally meaningful in analyzing the variation in segment margin for
gathering and marketing operations, these 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
generally enter into exchange transactions with third parties 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. We do not 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
20
amount of crude oil that is available to be gathered and marketed by us and our
competitors. During the last three years, posted prices for West Texas
Intermediate crude oil have ranged from a low near $16 per barrel to a high of
almost $50 per barrel. The volatility in prices over the last three 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. The pricing in the
majority of our purchase contracts contain the market price component, a bonus
that is not fixed, but instead is based on another market factor and a deduction
to cover the cost of transporting the crude oil and to provide us with a margin.
This floating bonus is usually the price quoted by Platt's for WTI "P-Plus".
Typically the pricing in a contract to sell crude oil will consist of the market
price component and P-Plus. The margin on individual transactions is then
dependent on our ability to manage our transportation costs.
The pricing in some contracts 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. When 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 as well as our management of transportation costs.
P-Plus does not consistently 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 that can cause the variance from
current changes in crude oil prices.
A few of our purchase contracts and some sale contracts also include a
component for grade differentials. The grade refers to the type of crude oil.
Crude oil 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. This volatility in grade differentials can affect the volatility of our
gathering and marketing segment margin.
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. As a result, this time requirement for
notice, 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. Accordingly, 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 the crude oil 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. In some cases, our sales contracts 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. We hold these volumes as inventory
and sell them in a later month. If the market price of crude oil declines below
its cost while we have these inventory volumes, then we recognize a loss in our
financial statements. If the market price rises, then we realize a gain when we
sell the unexpected volume of inventory in a later month at higher prices.
During 2004, we changed many of our sales
21
contract arrangements so that volumes sold are the same as the volumes purchased
in an effort to limit our exposure to these price fluctuations by minimizing
inventory builds and draws.
Field operating costs primarily consist of the costs to operate our fleet
of 53 trucks (51 leased and 2 owned) used to transport crude oil, and the costs
to maintain the trucks and assets used in the crude oil gathering operation.
Approximately 54% of these costs are variable and increase or decrease with
volumetric changes. These 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. Fuel costs also
fluctuate based on changes in the market price of diesel fuel. Fixed costs
include the base lease payment for the vehicle, insurance costs and costs for
environmental and safety related operations.
Operating results from continuing operations for our crude oil gathering
and marketing segment were as follows.
Years Ended December 31,
------------------------------------------------------
2004 2003 2002
------------- -------------- -------------
(in thousands)
Revenues................................................ $ 901,902 $ 641,684 $ 639,143
Crude oil costs......................................... 883,988 622,279 616,050
Field operating costs................................... 13,880 11,497 11,916
Change in fair value of derivatives..................... - - 1,279
------------- -------------- -------------
Segment margin..................................... $ 4,034 $ 7,908 $ 9,898
============= ============== =============
Volumes per day from continuing operations:
Crude oil wellhead - barrels....................... 45,919 45,015 47,819
Crude oil total - barrels.......................... 60,419 56,805 73,429
Year Ended December 31, 2004 as Compared to Year Ended December 31, 2003
Gathering and marketing segment margins decreased $3.9 million or 49% to
$4.0 million for the year ended December 31, 2004, as compared to $7.9 million
for the year ended December 31, 2003.
Contributing to this reduction in segment margin were two primary factors
as follows:
- A $2.9 million 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. The decrease on the margin between the sales and
purchase prices of the crude oil is attributable primarily to
increases in P-Plus in the first half of 2003 that we benefited from
significantly. In response to the decline in P-Plus during the
latter half of 2003, we changed many of our fixed bonus contracts to
fluctuating bonuses based on P-Plus, and as a result, we did not
experience the same increases in margin when P-plus increased in
2004.
- A $2.4 million increase in field operating costs, from increased
fuel costs to operate our tractor/trailers, additional employee
compensation and benefit costs due to additional volumes, and higher
insurance costs and higher vehicle maintenance costs. Although we
reduced operations in 2004 from 2003 levels with the sale of a large
part of our Texas operations, our insurance, safety and other fixed
costs did not decline proportionately. Competitive pressures made it
difficult to reduce crude oil purchase prices to offset the
increases in field operating costs.
Partially offsetting these decreases was a 6% increase in daily wellhead, bulk
and exchange purchase volumes between 2003 and 2004, resulting in a $1.3 million
increase in segment margin. Additionally credit costs declined by $0.1 million
as we reduced the number of letters of credit we issued.
Year Ended December 31, 2003 as Compared to Year Ended December 31, 2002
Gathering and marketing segment margins decreased $2.0 million or 20% to
$7.9 million for the year ended December 31, 2003, as compared to $9.9 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.
22
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. 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; 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.
- a $1.3 million change in the fair value of our net asset for
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 in 2002.
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, we cancelled contracts. These volume
reductions began in late 2001 and continued into the first half of 2002. Volumes
beginning in the third quarter of 2002 remained relatively stable at an average
of 55,000 to 60,000 barrels per day.
Outlook for 2005 and Beyond
Based on past experience and knowledge of the crude oil gathering and
marketing segment, we continue to expect volatility from this segment. We
continue to take steps to improve the performance of this segment. These steps
include effectively managing relationships with suppliers; inventory management;
controlling field costs; and improving operational efficiency in the field.
Additionally, we will continue to evaluate opportunities to dispose of or to
make further investments in components of this segment in order to improve its
performance.
PIPELINE OPERATIONS
We operate three common carrier crude oil 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 2004 2003 2002
- --------------- ------- ------- -------
Texas 36,413 43,388 47,987
Mississippi 12,589 8,443 7,426
Jay 14,440 15,128 16,455
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, from Webster to Texas City, and from 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 36,413 barrels per day during 2004.
The crude oil that enters our system comes to us at West Columbia where we have
a connection to TEPPCO's South Texas System and at Webster where we have
connections to two other pipelines. One of these connections at Webster is with
ExxonMobil Pipeline and is used to receive volumes that originate from TEPPCO's
pipelines. Under the terms of our 2003 sale of portions of the Texas System to
TEPPCO, we had a joint tariff with TEPPCO through October 2004 under which we
earned $0.40 per barrel on the majority of the barrels we deliver to the
shipper's facilities.
23
This tariff declined to $0.20 per barrel in November 2004. Most of the volume
being shipped on our Texas System goes to two refineries on the Texas Gulf
Coast.
The Mississippi System begins in Soso, Mississippi and extends to Liberty,
Mississippi. 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 system has 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
intend to make further improvements. See Capital Expenditures under "Liquidity
and Capital Resources" below.
Beginning in September 2004, Denbury became a shipper on the Mississippi
System, under an incentive tariff, designed to encourage shippers to increase
volumes shipped on the pipeline. Prior to this point, Denbury sold its
production to us before it entered the pipeline.
The second segment of the pipeline from Liberty to near Baton Rouge,
Louisiana has been out of service since February 1, 2002. A connecting carrier
tested its pipeline and decided not to reactivate its pipeline. During the
second quarter of 2004 we displaced the crude oil in this segment with inhibited
water. In 2004 and 2003, this segment made no contribution to pipeline revenues.
In the third quarter of 2004, we wrote this segment down to its estimated
salvage value, recording an impairment charge of $0.9 million.
In the fourth quarter of 2004, we constructed two segments of crude oil
pipeline to connect producing fields operated by Denbury to our Mississippi
System. One of these segments was placed in service in 2004 and the other will
begin operation in the first quarter of 2005. Denbury will pay us a minimum
payment each month for the right to use these pipeline segments. We account for
these arrangements as direct financing leases.
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 16,455 in 2002 to 15,128 in 2003 and to 14,440 barrels per day
in 2004, although the decline in 2004 can be attributed to Hurricane Ivan that
hit the panhandle of Florida in mid-September. While our facilities experienced
minimal damage from the storm, power outages in the area shut down our crude oil
pipeline transportation operations through the end of September. If volumes in
September and October 2004 had been the same as in the last two months of 2004,
the overall volume for 2004 would have been the same as 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 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. Increases in crude oil prices in 2004 resulted in greater profit
from the sale of pipeline loss allowance volumes.
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 and to minimize cost increases.
In the fourth quarter of 2004 we constructed a CO2 pipeline in Mississippi
to transport CO2 from Denbury's main CO2 pipeline to an oil field to which we
also constructed an oil pipeline to bring the oil from the field to our existing
Mississippi pipeline. Denbury has the exclusive right to use this CO2 pipeline.
This arrangement has been accounted for as a direct financing lease.
Operating results from continuing operations for our pipeline
transportation segment were as follows.
Years Ended December 31,
------------------------------------------------------
2004 2003 2002
------------- -------------- -------------
(in thousands)
Revenues, including revenues from direct
financing leases................................... $ 16,680 $ 15,134 $ 13,485
Pipeline operating costs................................ 8,137 10,026 8,076
------------- ------------- -------------
Segment margin..................................... $ 8,543 $ 5,108 $ 5,409
============= ============= =============
Volumes per day from continuing operations:
Crude oil pipeline - barrels....................... 63,441 66,959 71,870
24
Year Ended December 31, 2004 Compared with Year Ended December 31, 2003
Pipeline segment margin increased $3.4 million to $8.5 million for 2004,
as compared to $5.1 million for 2003. The increase in pipeline segment margin is
attributable to the following factors:
- A $1.2 million increase in pipeline revenues from volumetric gain
barrels due to higher sales prices for crude oil;
- A $0.3 million increase in tariff revenues due to higher average
tariff rates partially offset by lower volumes; and
- A $1.9 million decrease in pipeline operating costs. In 2003, we
recorded a charge of $0.7 million for an accrual for the removal of
an abandoned offshore pipeline. In 2004, we received permission to
abandon the pipeline in place. As a result we reversed $0.1 million
of the amounts previously accrued. The charges and reversal resulted
in a change of $0.8 million in pipeline operating costs between the
periods. Additionally, repairs, right-of-way maintenance and
regulatory testing and compliance expenses in the 2004 period were
$0.9 million less than in 2003. Changes in other operating costs
resulted in another $0.2 million of decreased costs.
The CO2 pipeline, which was operational for one month in 2004, contributed
approximately $25,000 of the segment margin in 2004.
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 seven 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
additions of operations and engineering staff, and $0.1 million for
costs associated with work vehicles for the new staff. Costs
associated with maintenance of right-of ways 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.
Outlook for 2005 and Beyond
Volumes on the Texas System declined 16% in 2004 from 2003 levels. We
anticipate that volumes on the Texas System may continue to decline as refiners
on the Texas Gulf Coast compete for crude oil with other markets connected to
TEPPCO's pipeline systems.
In November 2004, our share of the joint tariff with TEPPCO and ExxonMobil
was reduced to $0.20 per barrel. Based on volumes shipped in the fourth quarter
of 2004, we expect that this change will reduce tariff revenues by $1.9 million
annually. Under a tank rental reimbursement arrangement with the largest shipper
on the Texas System that begins in January 2005, we will receive a reimbursement
for the costs of renting tankage at Webster. This tank reimbursement is expected
to increase revenues from the Texas System by $0.5 million annually, offsetting
a portion of the expected decrease in tariff revenues.
25
We completed a hydrotest in the first quarter of 2005 that we believe will
allow us to continue to operate the West Columbia to Webster segment of pipeline
for service in heavy oil. This oil will be shipped under a joint tariff with
TEPPCO. The shippers agreed to an increase in this tariff during the fourth
quarter of 2004 if we would continue to provide this service which will provide
us with additional return on our investment in this segment. We expect an annual
increase in tariff revenues, based on volumes shipped in the fourth quarter of
2004, of $0.6 million.
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 are mutual benefits to Denbury and us due to this
common production and transportation area. As Denbury continues to acquire and
develop old oil fields using CO2 based tertiary recovery operations, Denbury
expects to add crude oil gathering and CO2 supply infrastructure to these
fields. Further, as the fields are developed over time, it may create increased
demand for our crude oil transportation services. Beginning in September 2004,
Denbury began shipping on our Mississippi pipeline rather than selling the crude
oil to us to market and ship on our Mississippi System. We also restructured our
tariffs to provide additional return on the investments we have made and will
continue to make in the Mississippi System.
We built a CO2 pipeline to connect Denbury's existing CO2 pipeline to the
Brookhaven oil field in Mississippi. The agreement with Denbury provides for a
minimum capacity charge that will provide $0.6 million of annual payments to us
for eight years with a commodity charge for volumes in excess of a threshold
volume. The segments of crude oil pipeline we constructed to Denbury's Olive and
Brookhaven fields also have agreements providing for minimum capacity charges
for ten years with commodity charges for volumes in excess of threshold volumes.
The annual payments under these crude oil agreements will provide a combined
total of $0.6 million of annual payments to us. The Brookhaven CO2 and Olive
pipelines went into service in 2004 and the Brookhaven oil pipeline is expected
to begin service in the first quarter of 2005. We account for these arrangements
as direct financing leases.
The production shipped from oil fields surrounding our Jay System comes
from a combination of new fields with estimated short production lives and older
fields that have been producing for 20 to 30 years and are in the latter stages
of their economic lives. 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
opportunities to effect such a conversion. 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 2005 or 2006.
We will continue to evaluate opportunities to dispose of or to make
further investments in components of this segment in order to improve its
performance.
CARBON DIOXIDE (CO2) MARKETING OPERATIONS
In November 2003, we acquired a volumetric production payment ("VPP") of
167.5 Bcf of CO2 from Denbury and in September 2004 we acquired an additional
33.0 Bcf VPP. Denbury owns 2.7 trillion cubic feet of estimated proved reserves
of CO2 in the Jackson Dome area near Jackson, Mississippi. In addition to the
production payments, Denbury also assigned to us five 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 volumetric production payments entitle us to a maximum daily quantity
of CO2 of 65,250 million cubic feet (Mcf) per day through December 31, 2009,
55,750 Mcf per day for the calendar years 2010 through 2012, and 37,750 Mcf per
day beginning in 2013 until we have received all volumes under the production
payments. Under the terms of transportation agreements 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 adjustments for inflation, for those
transportation services.
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 and our
experience in 2003 and 2004, we can expect some seasonality in our sales of CO2.
The dominant months for beverage carbonation and freezing food are from April to
October, when warm weather increases demand for beverages and the approaching
holidays increase demand for frozen foods.
26
The average daily sales (in mcfs) of CO2 for each quarter in 2004 and 2003
under these contracts were as follows:
Quarter 2004 2003
- ------- ------- -------
First 45,671 45,038
Second 51,164 49,982
Third 53,095 50,679
Fourth 48,217 42,468
The terms of our 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 61,500 Mcf. Under the minimum take-or-pay
volumes, the customers must purchase a total of 31,292 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 the minimum requirement
is met in that year. In the three years ended December 31, 2004, all three
customers have purchased more than their minimum take-or-pay quantities, as
shown in the table above.
Our five industrial contracts expire at various dates beginning in 2010
and extending through 2016. The sales contracts contain provisions for
adjustments for inflation to sales prices based on the Producer Price Index,
with a minimum price.
Operating results from continuing operations for our CO2 marketing
segment were as follows.
Years Ended December 31,
------------------------------------------------------
2004 2003 2002
------------- -------------- -------------
(in thousands)
Revenues........................................... $ 8,561 $ 1,079 $ -
Marketing costs.................................... 2,799 355 -
------------- -------------- -------------
Segment margin................................ $ 5,762 $ 724 $ -
============= ============== =============
Volumes per day from continuing operations:
Co2 marketing - Mcf........................... 45,312 36,332 -
The revenues, segment margin and average daily volumes reflected above for
2003 are for the two months that we owned the assets.
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 abandoned in place other remaining segments not sold to
these parties in 2003.
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 joint tariff agreements whereby TEPPCO invoices, collects
and shares with us the tariffs for transportation on the pipeline being sold and
the segments we retained. 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.
27
Under the terms of the sale to Blackhawk, we retained responsibility
for any environmental matters related to the pipeline segments acquired by
Blackhawk that are attributable to operations through December 31, 2003.
Operating results from the discontinued operations for the years ended
December 31, 2004, 2003 and 2002 were as follows:
Year Ended December 31,
-------------------------------------------------------
2004 2003 2002
-------------- -------------- -------------
(in thousands)
Gathering and marketing and pipeline revenues............... $ - $ 270,410 $ 259,178
Costs and expenses:
Crude costs and field operating costs...................... 5 256,986 243,262
Pipeline operating costs................................... 458 10,564 9,387
General and administrative................................. - 282 425
Depreciation and amortization.............................. - 1,864 1,210
Change in fair value of derivatives and other.............. - - 812
-------------- -------------- -------------
Total costs and expenses............................... 463 269,696 255,096
-------------- -------------- -------------
Operating (loss) income from discontinued operations....... (463) 714 4,082
-------------- -------------- -------------
Gain on disposal of assets.................................. - 13,028 -
-------------- -------------- -------------
(Loss) income from operations from discontinued Texas
System before minority interests........................... $ (463) $ 13,742 $ 4,082
============== ============== =============
During 2004, we incurred costs totaling $0.5 million related to the
dismantlement of assets that we abandoned in 2003.
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 two 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.
OTHER COSTS AND INTEREST
General and administrative expenses were as follows.
Years Ended December 31,
------------------------------------------------------
2004 2003 2002
------------- -------------- -------------
(in thousands)
Expenses excluding the effect of stock appreciation
rights plan............................................ $ 9,880 $ 8,540 $ 7,864
Stock appreciation rights plan expense.................. 1,151 228 -
------------- -------------- -------------
Total general and administrative expenses.......... $ 11,031 $ 8,768 $ 7,864
============= ============== =============
Year Ended December 31, 2004 Compared with Year Ended December 31, 2003
General and administrative expenses, excluding the effects of our stock
appreciation rights (SAR) plan, increased $1.3 million in 2004 from the 2003
level. In 2004, we incurred expenses of $1.3 million for professional services
to assist us in the internal control documentation and assessment provisions of
the Sarbanes-Oxley Act including additional audit fees related to this process.
Legal fees were $0.2 million less in the 2004 period, primarily due to a charge
that we took in the 2003 period for unamortized legal and consultant costs
related to a credit facility that was replaced. Other administrative costs
increased $0.2 million.
The SAR plan for employees and directors is a long-term incentive plan
whereby rights are granted for the grantee to receive cash equal to the
difference between the grant price and Common Unit price at date of exercise.
The rights vest over several years. Our unit price rose 29% from $9.80 at
December 31, 2003 to $12.60 at December 31, 2004 resulting in a $1.2 million
non-cash increase to the accrual for this liability in 2004. (See Note 13 to the
consolidated financial statements.)
Year Ended December 31, 2003 Compared with Year Ended December 31, 2002
General and administrative expenses, excluding the effects of the SAR
plan, increased $0.7 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. Another factor contributing to this increase
was the write-off of $0.2 million of unamortized legal and consultant costs
related to credit agreement with Citicorp.
The write-off of unamortized costs was necessitated by the replacement of
the Citicorp credit facility in 2003 with a credit facility with Bank of
America. Under our bonus program, bonuses were eliminated unless distributions
were being paid, which resulted in no accrual in 2002.
We recorded a non-cash charge of $0.2 million in 2003 related to our SAR
plan.
Depreciation, amortization and impairment expense increased by $2.7
million in 2004 from the 2003 and 2002 levels of $4.6 million, due to two main
factors. In 2004, we wrote-down the value of the segment of our Mississippi
System from Liberty to Baton Rouge to its estimated salvage value, recording a
charge of $0.9 million. We also had a full-year of amortization of the CO2
contracts in 2004, which increased expense by $2.1 million. Offsetting this
increase was the cessation of depreciation on assets that were fully-depreciated
during 2003 and 2004.
29
Interest expense, net was as follows
Years Ended December 31,
------------------------------------------------------
2004 2003 2002
------------- -------------- -------------
(in thousands)
Interest expense, including commitment fees............. $ 743 $ 341 $ 662
Capitalized interest.................................... (76) - -
Amortization and write-off of facility fees............. 303 679 442
Interest income......................................... (44) (34) (69)
------------- -------------- -------------
Net interest expense............................... $ 926 $ 986 $ 1,035
============= ============== =============
In 2004, our net interest expense decreased by $0.1 million. Interest
expense and commitment fees increased due to variances in outstanding debt,
increases in interest rates, and a June 1, 2004 increase in the size of our
credit facility to $100 million which increased commitment fees. This increase
was offset by a reduction in facility fees amortization and write-off. In 2003,
we wrote-off the unamortized facility fees related to a credit facility that was
replaced in March 2003.
In 2003, our net interest expense decreased by $0.1 million from the 2002
amount. 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.
We expect our interest costs to increase in 2005 due to higher levels of
outstanding debt and increases in market interest rates. All of our debt is at
variable rates based on market interest rates.
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. This
agreement was finalized in 2004 and we paid a fine of $3.0 million. In the
fourth quarter of 2001 we accrued $1.5 million for this fine and in the third
quarter of 2002, we accrued an additional $1.5 million.
Net gain/loss on disposal of surplus assets. In 2004 and 2003 we sold
surplus assets no longer in use in our operations. 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.
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL RESOURCES
In June 2004, we replaced our existing bank credit facility with a group
of banks led by Bank of America as agent with a $100 million senior secured bank
credit facility (the "Credit Agreement") with a group of five lenders including
three of the previous banks. The Credit Agreement consists of a $50 million
revolving line of credit for acquisitions and a $50 million working capital
revolving credit facility. The facility matures in June 2008.
The working capital portion of the Credit Agreement has a sub-limit of $15
million for working capital loans with the remainder of the $50 million portion
available for letters of credit, subject to a borrowing base calculation.
Interest rates and fees under the Credit Agreement are slightly better
than the terms of the prior facility. The interest rates and fees under the
working capital portion vary with the percentage of the facility being used in
relation to the borrowing base.
At December 31, 2004, we had borrowed $5 million under the working capital
portion of the Credit Agreement and $10.3 million under the acquisition portion.
Due to the revolving nature of loans under the Credit Agreement, additional
borrowings and periodic repayments and re-borrowings may be made until the
maturity date of June 1, 2008. At December 31, 2004, we had letters of credit
outstanding under the Credit Agreement totaling $12.6 million, comprised of $6.5
million and $5.3 million for crude oil purchases related to December 2004 and
January 2005, respectively, and $0.8 million related to other business
obligations. As we no longer purchase crude oil from Denbury for shipment, we no
longer provide Denbury with letters of credit.
We were in compliance with the Credit Agreement covenants at December 31,
2004.
30
We have no limitations on making distributions in our Credit
Agreement, except as to the effects of distributions in covenant calculations.
The Credit Agreement requires we maintain a cash flow coverage ratio of 1.1 to
1.0. In general, this calculation compares operating cash inflows, as adjusted
in accordance with the Credit Agreement, less maintenance capital expenditures,
to the sum of interest expense and distributions. At December 31, 2004, the
calculation resulted in a ratio of 1.1 to 1.0. The Credit Agreement also
requires that the level of operating cash inflows, as adjusted in accordance
with the Credit Agreement, be at least $8.5 million. At December 31, 2004, the
result of this calculation was $9.0 million.
We will distribute our Available Cash to our Unitholders each
quarter if we are not in default of these covenants.
CAPITAL EXPENDITURES
A summary of our capital expenditures in the three years ended
December 31, 2004, 2003, and 2002 is as follows:
Year Ended December 31,
-----------------------------------------------
2004 2003 2002
------------ ----------- ------------
(in thousands)
Maintenance capital expenditures:
Texas pipeline system................................. $ 122 $ 1,588 $ 1,638
Mississippi pipeline system........................... 505 1,684 1,838
Jay pipeline system................................... 28 213 43
Crude oil gathering assets............................ 159 307 241
Administrative and other assets....................... 125 384 451
------------ ----------- ------------
Total maintenance capital expenditures............. 939 4,176 4,211
Growth capital expenditures (including construction in
progress):
Mississippi oil and CO2 pipeline systems.............. 7,371 76 -
Crude oil gathering and other assets.................. 161 658 -
CO2 marketing assets.................................. 4,723 24,401 -
------------ ----------- ------------
Total growth capital expenditures.................. 12,255 25,135 -
------------ ----------- ------------
Total capital expenditures...................... $ 13,194 $ 29,311 $ 4,211
============ =========== ============
Maintenance capital expenditures in 2004 included station
improvements in Mississippi to handle increased volumes. Administrative assets
included computer software and hardware.
In the 2003 period, maintenance capital expenditures included
installation of pipeline satellite monitoring equipment on all three pipelines,
and an upgrade to 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 release had occurred in
December 1999, to restore this segment to service. In 2003, 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 2004 related to the acquisition in
Mississippi of right-of-way and the construction costs for a ten mile extension
of our Mississippi crude oil pipeline and a CO2 pipeline extending from
Denbury's CO2 pipeline to the Brookhaven field. This extension was completed
during the fourth quarter of 2004. We also completed an approximately four-mile
extension from our existing crude oil pipeline to move crude oil from Denbury's
Olive/McComb fields. We also started construction of a 55,000 barrel tank at our
Mallalieu station to accommodate the additional volumes. We acquired a second
CO2 volumetric production payment and related industrial sales contracts during
the third quarter of 2004.
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 maintenance capital expenditures for 2005 will be approximately $2.4
million. These expenditures are expected to relate primarily to our Mississippi
System, including corrosion control
31
expenditures, minor facility improvements and improvements of the pipeline as a
result of integrity management test results.
Complying with Department of Transportation Pipeline Integrity
Management Program ("IMP") regulations has been and will be a significant factor
in determining the amount and timing of our capital expenditure requirements.
The IMP regulations required that a 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 $0.1 million in 2005 and $0.2 million in 2006 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 through 2004, we have estimated capital expenditures to be made
during the IMP assessment period from 2005 through 2009. These capital
expenditure projections are based on very preliminary data regarding the cost of
rehabilitation. We will update these projections as we obtain additional
information. As we rehabilitate the Mississippi System as a result of IMP
testing, we will also make improvements to handle the increased volumes more
efficiently. Overall we expect to spend approximately $2.0 million in 2005
through 2007 for these improvements. We do not expect to incur any
rehabilitation expenditures on the other systems during this period.
Expenditures for capital assets to grow the partnership distribution
will depend on our access to debt and capital discussed below in "Sources of
Future Capital." We will look for opportunities to acquire assets from other
parties that meet our criteria for stable cash flows such as the two
acquisitions discussed in "Acquisitions in 2005" above.
SOURCES OF FUTURE CAPITAL
Prior to 2003, we funded our capital commitments from operating cash
and borrowings under our bank facilities. In 2003, we issued common units to our
general partner for cash and sold assets to fund growth. During 2004, we used
our Credit Agreement to fund our capital expenditures. Our plans for the future
include a combination of borrowings and the issuance of additional common units
to the public.
The Credit Agreement provides us with $50 million of capacity for
acquisitions. We expect to use our acquisition facility for the projects
discussed under Capital Expenditures as well as other future projects. The
acquisition portion of the Credit Agreement is a revolving facility.
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 is as follows:
Year Ended December 31,
-----------------------------------------------
2004 2003 2002
------------ ----------- ------------
(in thousands)
Cash provided by (used in):
Operating activities............. $ 9,702 $ 4,693 $ 7,417
Investing activities............. $ (12,805) $ (6,994) $ (1,963)
Financing activities............. $ 2,312 $ 4,099 $ (10,160)
32
Operating. Net cash from operating activities for each year have
been comprised of the following:
Year Ended December 31,
-----------------------------------------------
2004 2003 2002
------------ ----------- ------------
(in thousands)
Net income........................................... $ (1,412) $ 13,322 $ 5,092
Depreciation, amortization and impairment............ 7,635 7,535 6,549
Loss (gain) on sales of assets....................... 33 (13,264) (708)
Derivative related non-cash adjustments.............. - 39 2,055
Payments received under direct financing leases...... 75 - -
Other non-cash items................................. 1,151 229 1,500
Changes in components of working capital, net........ 2,220 (3,168) (7,071)
------------ ----------- ------------
Net cash from operating activities................ $ 9,702 $ 4,693 $ 7,417
============ =========== ============
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.
Additionally, in 2004, we paid the $3.0 million in fines assessed in connection
with the Mississippi oil release in 1999, which utilized our cash flows. The
accrual for this payment was made in 2001 and 2002. The timing of capital
expenditures and the related effect on our recorded liabilities also affects
operating cash flows.
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 $69.3 million aggregate
receivables on our consolidated balance sheet at December 31, 2004,
approximately $67.7 million, or 97.7%, were less than 30 days past the invoice
date.
Investing. Cash flows used in investing activities in 2004 were
$12.8 million as compared to $7.0 million in 2003. Capital expenditures for
construction of pipeline assets and the acquisition of a second volumetric
payment from Denbury were the primary uses of cash for investing.
Cash flows used in investing activities in 2003 were $7.0 million.
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 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.
Financing. In 2004, financing activities provided net cash of $2.3
million. Borrowings provided $8.8 million of cash flow. We utilized $0.8 million
of these funds to pay fees related to the Credit Agreement we obtained in June
2004. Distributions to our partners utilized $5.7 million.
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 for $4.9 million. We also increased our outstanding debt by $1.5 million.
We utilized $1.1 million of these funds to pay credit facility issuance fees.
Distributions to our partners utilized $1.3 million.
Net cash expended for financing activities was $10.2 million in
2002. 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.
DISTRIBUTIONS
As a master limited partnership, the key consideration of our
Unitholders is the amount and reliability of our distribution, and our prospects
for distribution increases. We are required by our Partnership Agreement to
33
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 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). Beginning
with the distribution for the fourth quarter of 2003, which was paid in February
2004, we increased our quarterly distribution to $0.15 per unit ($1.4 in total).
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 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. 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
2005.
We believe we will be able to sustain a regular quarterly
distribution at $0.15 per unit during 2005. Our ability to increase
distributions during 2005 will depend in part on our success in developing and
executing capital projects and making accretive acquisitions, the results of our
integrity management program testing, and our ability to generate sustained
improvements in the gathering and marketing segment.
Available Cash before reserves for the year ended December 31, 2004
is as follows (in thousands):
Net loss............................................................ $ (1,412)
Depreciation, amortization and impairment........................... 7,298
Cash received from direct financing leases not included in income... 39
Cash effects from sales of certain asset sales...................... 145
Non-cash charges.................................................... 1,151
Maintenance capital expenditures.................................... (939)
-----------
Available Cash before reserves...................................... $ 6,282
===========
We have reconciled Available Cash (a non-GAAP liquidity measure) to
cash flow from operating activities (the GAAP measure) for the year ended
December 31, 2004 below.
NON-GAAP FINANCIAL MEASURE
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 accrual for our stock appreciation rights plan expense and the value of
financial instruments; and (3) the subtraction of maintenance capital
expenditures. 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. See "Distributions" above.
34
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, 2004, is as follows (in thousands):
Year
Ended
December 31,
2004
------------
Cash flows from operating activities................................. $ 9,702
Adjustments to reconcile operating cash flows to Available Cash:
Maintenance capital expenditures................................. (939)
Proceeds from sales of certain assets, net of gains and losses
recorded...................................................... 112
Amortization of credit facility issuance fees.................... (373)
Net effect of changes in operating accounts not included in
calculation of Available Cash................................. (2,220)
----------
Available Cash before reserves....................................... $ 6,282
==========
COMMITMENTS AND OFF-BALANCE SHEET ARRANGEMENTS
CONTRACTUAL OBLIGATION AND COMMERCIAL COMMITMENTS
In addition to the Credit Agreement 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, 2004.
Payments Due by Period
---------------------------------------------------------
2006 and 2008 and After
Contractual Cash Obligations 2005 2007 2009 2009 Total
- ---------------------------- ---------- ---------- ---------- --------- ----------
(in thousands)
Long-term Debt........... $ - $ - $ 15,300 $ - $ 15,300
Interest Payments (1).... 958 1,916 399 - 3,273
Operating Leases......... 2,879 2,763 1,445 672 7,759
Unconditional Purchase
Obligations (2)...... 173,421 76,464 - - 249,885
---------- ---------- ---------- --------- ----------
Total Contractual Cash
Obligations.......... $ 177,258 $ 81,143 $ 17,144 $ 672 $ 276,217
========== ========== ========== ========= ==========
(1) Interest on our long-term debt is at market-based rates. Amount shown for
interest payments represents interest that would be paid if the debt
outstanding at December 31, 2004 remained outstanding through the maturity
date of June 1, 2008 and interest rates remained at the December 31, 2004
market levels through June 1, 2008.
(2) The unconditional purchase obligations included above are contracts to
purchase crude oil, generally at market-based prices. For purposes of this
table, market prices at December 31, 2004, were used to value the
obligations. Actual obligations may differ from the amounts included
above.
OFF-BALANCE SHEET ARRANGEMENTS
We have no off-balance sheet arrangements, special purpose entities,
or financing partnerships, other than as disclosed under Contractual Obligation
and Commercial Commitments above, nor do we have any debt or equity triggers
based upon our unit or commodity prices.
OTHER MATTERS
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
35
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. The settlement of this litigation had no effect on our
results of operations.
PQS is also a defendant in five consolidated class action/mass tort
actions 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 claims demand against Genesis and others for
indemnity with respect to the fire and explosion of January 18, 2000. We believe
that the claims against Genesis are 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, we cannot
assure you that an event not fully insured or indemnified against will not
materially and adversely affect our operations and financial condition.
Additionally, we cannot assure you that we will be able to maintain insurance in
the future at rates that we consider reasonable.
NEW AND PROPOSED ACCOUNTING PRONOUNCEMENTS
EITF NO. 04-13
The Emerging Issues Task Force (EITF) of the Financial Accounting
Standards Board (FASB) is currently considering the issue of accounting for
buy/sell arrangements as part of its EITF Issue No. 04-13, "Accounting for
Purchases and Sales of Inventory with the Same Counterparty" (Issue 04-13). As
part Issue 04-13, the EITF is considering a requirement that all buy/sell
arrangements be reflected on a net basis, such that the purchase and sale are
netted and shown as either a net purchase or a net sale in the income statement.
Should this requirement be adopted, the revenues and costs of crude oil
reflected on our statements of operations will be reduced. Our reported crude
oil gathering and marketing revenues from unrelated parties for the year ended
December 31, 2004 would be reduced by $296 million to $605 million. Our reported
crude oil costs from unrelated parties for the year ended December 31, 2004,
would be reduced by $295 million to $511 million.
SFAS 151
On November 30, 2004, the FASB issued SFAS No. 151, "Inventory
Costs." This statement clarifies the accounting for abnormal amounts of idle
facility expense, freight, handling costs, and wasted material (spoilage). This
statement requires that these items be charged to expense regardless of whether
they meet the "so abnormal" criterion outlined in Accounting Research Bulletin
43. This statement is effective for inventory costs incurred during fiscal years
beginning after June 15, 2005. The adoption of this statement is not expected to
have any effect on our financial position, results of operations or cash flows.
SFAS 153
In December 2004, the FASB issued SFAS No. 153, "Exchanges of
Nonmonetary Assets", which amends Accounting Principles Board Opinion No. 29
(APB 29). SFAS No. 153 provides a general exception from fair value measurement
for exchanges of nonmonetary assets that do not have commercial substance. A
nonmonetary exchange has commercial substance if the future cash flows of the
entity are expected to change significantly as a result of the exchange. This
general exception replaces the exception from fair value measurement in APB 29
for nonmonetary exchanges of similar productive assets. This statement is
effective for nonmonetary asset exchanges
36
occurring in fiscal periods beginning after June 15, 2005. At this time we do
not expect the adoption of this statement to have any effect on our financial
position, results of operations or cash flows.
SFAS 123(R)
In December 2004, the FASB issued SFAS No. 123 (revised December
2004), "Share-Based Payment". This statement replaces SFAS No. 123 and requires
that compensation costs related to share-based payment transactions be
recognized in the financial statements. This statement is effective for public
entities as of the first interim reporting period that begins after June 15,
2005. The adoption of this statement is not expected to have a material effect
on our financial position, results of operations or cash flows.
RISK FACTORS
RISK FACTORS RELATED TO OUR BUSINESS
We may not have sufficient cash from operations to pay the current
level of quarterly distribution following the establishment of cash reserves and
payment of fees and expenses, including payments to our general partner.
The amount of cash we distribute on our units principally depends
upon margins we generate from our crude oil gathering and marketing operations,
margins from the pipeline transportation operations and sales of CO2, which will
fluctuate from quarter to quarter based on, among other things:
- the prices at which we purchase and sell crude oil;
- the volumes of crude oil, CO2 and natural gas we transport;
- the volumes of CO2 we sell;
- the level of our operating costs;
- the level of our general and administrative costs; and
- prevailing economic conditions.
In addition, the actual amount of cash we will have available for
distribution will depend on other factors that include:
- the costs of acquisitions, if any;
- our debt service requirements;
- fluctuations in our working capital;
- the level of capital expenditures we make;
- restrictions on distributions contained in our debt
instruments;
- our ability to borrow under our working capital facility to
pay distributions; and
- the amount of cash reserves established by our general partner
in its sole discretion in the conduct of our business.
You should also be aware that our ability to pay quarterly
distributions each quarter depends primarily on our cash flow, including cash
flow from financial reserves and working capital borrowings, and is not solely a
function of profitability, which will be affected by non-cash items. As a
result, we may make cash distributions during periods when we record losses and
we may not make distributions during periods when we record net income.
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.
37
The profitability of our crude oil gathering and marketing
operations depends primarily on the volumes of crude oil we purchase and gather.
We must replace natural declines in crude oil production from
depleting wells or volumes lost to competitors with contracts for new supplies
of crude oil to maintain the volumes of crude oil we purchase. The ability of
producers to maintain or increase production depends upon the prevailing market
price of oil, the exploration budgets of major and independent oil producers,
the depletion rate of existing reservoirs, the success of new wells drilled,
environmental concerns, regulatory initiatives and other matters beyond our
control. We cannot assure you that production of crude oil will rise to
sufficient levels to allow us to maintain or increase the amounts of crude oil
transported on our pipeline and gathering assets.
Our operations are dependent upon demand for crude oil by refiners
in the Midwest and on the Gulf Coast.
Any decrease in this demand could adversely affect our business.
Demand for crude oil also 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 other crude oil pipelines, the major
integrated oil companies, their marketing affiliates and independent gatherers,
brokers and marketers of widely varying sizes, financial resources and
experience. Some of these competitors have capital resources many times greater
than ours and control substantially 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 activities.
In those cases where we provide division order services for crude
oil purchased at the wellhead, we may be responsible for distribution of
proceeds to all parties. In other cases, we pay all of 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. As a
result, we must determine that operators have sufficient financial resources to
make such payments and distributions and to indemnify and defend us in case of a
protest, action or complaint. Even if our credit review and analysis mechanisms
work properly, 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 cash flows and results of operations.
Fluctuations in demand for crude oil, such as those 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 transportation services.
In addition, 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 our margin and profitability if our
volumes decrease.
Our operations are subject to federal and state environmental and
safety regulations and laws related to environmental protection and operational
safety.
38
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 claims for damages to property or persons resulting from our operations. If
we are unable to recover such resulting costs through higher tariffs or
insurance reimbursements, our cash flows and distributions to our unitholders
could be materially affected.
The transportation and storage of crude oil involves a risk that
crude oil and related hydrocarbons may be suddenly or gradually released into
the environment, which may result in 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.
Our CO2 operations are exposed to risks related to Denbury
Resources' operation of their CO2 fields, equipment and pipeline.
Because Denbury Resources produces the CO2 and transports the CO2 to
our customers, any major failure of its 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.
The CO2 supplied by Denbury Resources 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 required by
our contracts.
Fluctuations in demand for CO2 by our industrial customers could
materially impact our profitability.
Our customers are not obligated to purchase volumes in excess of
specified minimum amounts in our contracts. As a result, fluctuations in our
customers' demand due to market forces or operational problems could result in a
reduction in our revenues from our sales of CO2.
Our wholesale CO2 industrial marketing operations are dependent on
three customers.
If one or more of those customers experience financial difficulties
such that they fail to purchase their required minimum take-or-pay volumes, our
cash flows could be adversely affected. We believe these three customers are
credit worthy, but we can not assure you that an unanticipated deterioration in
their ability to meet their obligations to us might not occur.
The terms of our credit facility may limit our ability to borrow
additional funds, make distributions to unitholders, or capitalize on business
opportunities.
As of December 31, 2004, our total outstanding long-term debt was
approximately $15,300,000. Our credit facility includes limitations on our
ability to make distributions to our unitholders, through covenant requirements,
and requires approval of lenders to take certain actions. Any refinancing of our
current indebtedness or any new indebtedness could have similar or greater
restrictions.
Terrorist attacks aimed at the Partnership's facilities could
adversely affect the business.
On September 11, 2001, the United States was the target of terrorist
attacks of unprecedented scale. Since the September 11 attacks, the U.S.
government has issued warnings that energy assets, specifically the nation's
pipeline infrastructure, may be the future targets of terrorist organizations.
These developments have subjected our operations to increased risks. Any future
terrorist attack at our facilities, those of our customers and, in some cases,
those of other pipelines, could have a material adverse effect on our business.
39
TAX RISKS TO COMMON UNITHOLDERS
The IRS could treat us as a corporation far tax purposes, which
would substantially reduce the cash available for distribution to our
unitholders.
The after-tax economic benefit of an investment in the common units
depends largely on our being treated as a partnership for federal income tax
purposes. We have not requested, and do not plan to request, a ruling from the
IRS on this or any other tax matter affecting us.
If we were treated as a corporation for federal income tax purposes,
we would pay federal income tax on our income at the corporate tax rate, which
is currently a maximum of 35%. Distributions to you may be taxed again as
corporate dividends, and no income, gains, losses or deductions would flow
through to our unitholders. Because a tax would be imposed upon us as a
corporation, our cash available for distribution to our unitholders would be
substantially reduced. If we were treated as a corporation, there would be a
material reduction in the after-tax return to the unitholders, likely causing a
substantial reduction in the value of our common units. Moreover, treatment of
us as a corporation would materially and adversely affect our ability to make
payments on our debt securities.
Current law may change so as to cause us to be treated as a
corporation for federal income tax purposes or otherwise subject us to
entity-level taxation. In addition, because of widespread state budget deficits,
several states are evaluating ways to subject partnerships to entity-level
taxation through the imposition of state income, franchise or other forms of
taxation. If any state were to impose a tax upon us as an entity, the cash
available for distribution to our unitholders would be reduced. The partnership
agreement provides that if a law is enacted or existing law is modified or
interpreted in a manner that subjects us to taxation as a corporation or
otherwise subjects us to entity-level taxation for federal, state or local
income tax purposes, the minimum quarterly distribution amount and the target
distribution amounts will be adjusted to reflect the impact of that law on us.
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risks primarily related to volatility in crude
oil prices and interest rates.
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, 2004,
we had no financial instruments or contracts outstanding to hedge commodity
risks.
We are also exposed to market risks due to the floating interest rates on
our credit facility. Our debt bears interest at the LIBOR or prime rate plus the
applicable margin. We do not hedge our interest rates. The average interest rate
presented below is based upon rates in effect at December 31, 2004. The carrying
value of our debt in our credit facility approximates fair value primarily
because interest rates fluctuate with prevailing market rates, and the credit
spread on outstanding borrowings reflects market.
40
Expected Year
Of Maturity
2008
(in thousands)
------------
Long-term debt - variable rate 15,300
Average interest rate 6.3%
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 55.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
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, with the participation of our management, 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 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.
Management's Report on Internal Control over Financial Reporting
Management of the Partnership is responsible for establishing and
maintaining effective internal control over financial reporting as defined in
Rules 13a-15(f) under the Securities and Exchange Act of 1934. The Partnership's
internal control over financial reporting is designed to provide reasonable
assurance to the Partnership's management and board of directors regarding the
preparation and fair presentation of published financial statements.
Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect to
financial statement preparation and presentation.
Management assessed the effectiveness of the Partnership's internal
control over financial reporting as of December 31, 2004. In making this
assessment, management used the criteria set forth by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control
Integrated Framework. Based on our assessment, we believe that, as of December
31, 2004, the Partnership's internal control over financial reporting is
effective based on those criteria.
Management's assessment of the effectiveness of internal control over
financial reporting as of December 31, 2004, has been audited by Deloitte &
Touche LLP, the independent registered public accounting firm who also audited
the Partnership's consolidated financial statement. Deloitte & Touche's
attestation report on management's assessment of the Partnership's internal
control over financial reporting appears below.
41
Report of Independent Registered Public Accounting Firm on Internal Control
over Financial Reporting
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Genesis Energy, Inc. and Unitholders of
Genesis Energy, L.P.
Houston, Texas
We have audited management's assessment, included in the accompanying
Management's report on Internal Control over Financial Reporting, that Genesis
Energy, L.P. and subsidiaries (the "Partnership") maintained effective internal
control over financial reporting as of December 31, 2004, based on criteria
established in Internal Control -- Integrated Framework issued by the Committee
of Sponsoring Organizations of the Treadway Commission. The Partnership's
management is responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal
control over financial reporting. Our responsibility is to express an opinion on
management's assessment and an opinion on the effectiveness of the Partnership's
internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, evaluating management's assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed by,
or under the supervision of, the company's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
company's board of directors, management, and other personnel to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial
reporting, including the possibility of collusion or improper management
override of controls, material misstatements due to error or fraud may not be
prevented or detected on a timely basis. Also, projections of any evaluation of
the effectiveness of the internal control over financial reporting to future
periods are subject to the risk that the controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In our opinion, management's assessment that the Partnership maintained
effective internal control over financial reporting as of December 31, 2004, is
fairly stated, in all material respects, based on the criteria established in
Internal Control -- Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Also in our opinion, the Partnership
maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2004, based on the criteria established in Internal
Control -- Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
42
We have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the consolidated financial
statements as of and for the year ended December 31, 2004 of the Partnership and
our report dated March 14, 2005, expressed an unqualified opinion on those
financial statements.
/s/ DELOITTE & TOUCHE LLP
- --------------------------
Houston, Texas
March 14, 2005
ITEM 9B. OTHER INFORMATION
None.
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................ 52 Director and Chairman of the Board
Mark J. Gorman................ 50 Director, Chief Executive Officer and President
Ronald T. Evans............... 42 Director
Herbert I. Goodman............ 82 Director
Susan O. Rheney............... 45 Director
Phil Rykhoek.................. 48 Director
J. Conley Stone............... 73 Director
Mark A. Worthey............... 47 Director
Ross A. Benavides............. 51 Chief Financial Officer, General Counsel and Secretary
Kerry W. Mazoch............... 58 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 been employed by
Denbury since 1992.
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 been employed by Denbury 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.
43
Herbert I. Goodman has served as a director of the General Partner
since January 1997. 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. He was
Chairman of IQ Holdings, Inc., a manufacturer and marketer of
petrochemical-based consumer products until 2004. From 1988 until 1996 he was
Chairman and Chief Executive Officer of Applied Trading Systems, Inc., a trading
and consulting business.
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 Cenveo, Inc.., a supplier of printing
services and products, where she serves on the audit and governance and
nominating committees. Additionally, she currently serves as interim Chairman of
the Board of Directors of Cenveo, Inc.
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 been employed by Denbury 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 employed by 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 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.
44
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. A Form 4 reporting the receipt of 2,576 stock appreciation
rights on August 25, 2004 by Phil Rykhoek, a director, was filed late during
2004.
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 2004, 2003, and 2002 to the Chief
Executive Officer and each of our three other executive officers (the "Named
Officers").
Long-Term
Compensation
Awards
Annual Compensation ----------------
-------------------------------------- Securities
Other Annual underlying All Other
Salary Bonus Compensation SARs Granted (2) Compensation
Name and Principal Position Year $ $ $ (1) # $
- --------------------------- ---- ------- ----- ------------ ---------------- ------------
Mark J. Gorman 2004 275,000 6,793 66,810 5,615 15,150 (3)
Chief Executive Officer 2003 275,000 4,070 12,755 23,620 15,174 (4)
and President 2002 270,000 5,193 - - 11,644 (5)
Ross A. Benavides 2004 185,000 4,570 44,942 3,777 14,230 (6)
Chief Financial Officer, 2003 185,000 2,738 8,580 15,889 13,977 (7)
General Counsel and 2002 180,000 3,462 - - 11,644 (5)
Secretary
Kerry W. Mazoch 2004 175,000 4,323 42,513 3,573 13,392 (8)
Vice President, Crude 2003 175,000 2,590 8,116 15,030 13,197 (9)
Oil Acquisitions 2002 170,000 3,270 - - 11,622 (10)
Karen N. Pape 2004 141,500 3,495 34,375 2,889 10,920 (11)
Vice President and 2003 141,500 2,094 6,563 12,153 10,707 (12)
Controller 2002 136,000 2,616 - - 10,262 (13)
(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, $6,000 of profit-sharing contributions to a defined
contribution plan and $150 for annual term life insurance premiums.
(4) Includes $9,000 of Company-matching contributions to a defined
contribution plan, $6,000 of profit-sharing contributions to a defined
contribution plan and $174 for annual term life insurance premiums.
45
(5) Includes $5,500 of Company-matching contributions to a defined
contribution plan, $6,000 of profit-sharing contributions to a defined
contribution plan and $144 for annual term life insurance premiums.
(6) Includes $8,448 of Company-matching contributions to a defined
contribution plan, $5,632 of profit-sharing contributions to a defined
contribution plan and $150 for annual term life insurance premiums.
(7) Includes $8,282 of Company-matching contributions to a defined
contribution plan, $5,521 of profit-sharing contributions to a defined
contribution plan and $174 for annual term life insurance premiums.
(8) Includes $7,914 of Company-matching contributions to a defined
contribution plan, $5,328 of profit-sharing contributions to a defined
contribution plan and $150 for annual term life insurance premiums.
(9) Includes $7,802 of Company-matching contributions to a defined
contribution plan, $5,221 of profit-sharing contributions to a defined
contribution plan and $174 for annual term life insurance premiums.
(10) Includes $5,500 of Company-matching contributions to a defined
contribution plan, $5,978 of profit-sharing contributions to a defined
contribution plan and $144 for annual term life insurance premiums.
(11) Includes $6,462 of Company-matching contributions to a defined
contribution plan, $4,308 of profit-sharing contributions to a defined
contribution plan and $150 for annual term life insurance premiums.
(12) Includes $6,320 of Company matching contributions to a defined
contribution plan, $4,213 of profit-sharing contributions to a defined
contribution plan and $174 for annual term life insurance premiums.
(13) Includes $5,059 of Company-matching contributions to a defined
contribution plan, $5,059 of profit-sharing contributions to a defined
contribution plan and $144 for annual term life insurance premiums.
Stock Appreciation Rights Plan
In December 2003, the Board approved a Stock Appreciation Rights
plan (SAR) 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.
We have had our legal counsel review the SAR plan in light of the
recently adopted section 409A of the Internal Revenue Code and applicable
guidance ("409A"). The new rules generally apply to any arrangement that
provides for the deferral of compensation, with the most significant provision
affecting the timing of the taxation of the benefits to participants. Certain
tax favored retirement plans are expressly excluded from the new rules. We
believe there are good arguments that the SAR plan should be covered by an
exception which excludes existing stock appreciation rights plans from the new
rules. Recent guidance under 409A excludes from the definition of "deferred
compensation" under 409A stock appreciation rights plans under which (i) the
stock appreciation rights exercise price may never be less than the fair market
value of the underlying stock on the date the stock appreciation
46
rights are granted and (ii) the stock appreciation rights do not include any
feature for the deferral of compensation other than delaying the recognition of
income until the exercise of the stock appreciation rights.
If any provisions of the SAR plan are insufficient for the plan to
qualify for the exclusion, it appears that the guidance provides transition
relief for stock appreciation rights plans that allows such plans to be amended
to bring them within the exclusion from the new law, as long as those amendments
are adopted by December 31, 2005. When the next round of guidance is issued, we
will re-evaluate the terms of the SAR plan in light of any changes in that
guidance.
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, 2004. Information on rights granted to non-employee
directors is included in the section entitled Director Compensation.
SAR Grants During the Year Ended December 31, 2004
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% ($)
- ----------------- ---------- -------------- -------- ------- ---------- ---------------------------
Mark J. Gorman 5,615 5.5% 12.48 12.60 12/31/2014 44,070 111,682
Ross A. Benavides 3,777 3.7% 12.48 12.60 12/31/2014 29,644 75,124
Kerry W. Mazoch 3,573 3.5% 12.48 12.60 12/31/2014 28,043 71,067
Karen N. Pape 2,889 2.8% 12.48 12.60 12/31/2014 22,675 57,462
December 31, 2004 SAR Values (1)
Number of Common Units Value of
underlying unexercised unexercised in-the-money
SARs at December 31, 2004 (#) SARs at December 31, 2004 ($)
-------------------------------- -------------------------------
Name Exercisable Unexercisable Exercisable Unexercisable
- ----------------- ----------- ------------- ----------- -------------
Mark J. Gorman 5,905 23,330 19,723 59,842
Ross A. Benavides 3,972 15,694 13,266 40,256
Kerry W. Mazoch 3,757 14,846 12,548 38,081
Karen N. Pape 3,038 12,004 10,147 30,791
(1) None of the executive officers exercised any SARs during 2004.
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 $2.3 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 who could earn a total bonus ranging from zero to twenty percent.
Certain members 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.
Our legal counsel has also reviewed the bonus plan in light of the
new 409A. As with the SAR plan, we believe that, based on the way the bonus plan
has historically been administered, there is good argument that amounts paid
under the bonus plan do not constitute deferred compensation, but some
amendments to the bonus
47
plan will likely be required to ensure this result. The guidance issued by the
Internal Revenue Service under 409A will allow these amendments to be made at
any time before December 31, 2005. We are currently evaluating the terms of the
bonus plan in light of the recent guidance.
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 2004
were:
Number of
Securities
underlying Exercise
SARs price Expiration
Name granted (#) $/Unit date
- ------------------ ---------- -------- -----------
Gareth Roberts 612 12.48 12/31/2014
Ronald T. Evans 612 12.48 12/31/2014
Herbert I. Goodman 735 12.48 12/31/2014
Susan O. Rheney 816 12.48 12/31/2014
Phil Rykhoek 2,576 11.00 8/25/2014
Phil Rykhoek 612 12.48 12/31/2014
J. Conley Stone 735 12.48 12/31/2014
Mark A. Worthey 612 12.48 12/31/2014
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
Beneficial Ownership of Partnership Units
The following table sets forth certain information as of February 28,
2005, 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.
48
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 2,500 *
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) 65,663 *
- -------------
* 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 by his 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 2004, these reimbursements totaled $14.1 million. At December 31,
2004, the general partner owed us $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.
Our general partner also owns 688,811 limited partner units and has the
same rights and is entitled to receive distributions as the other limited
partners with respect to those units.
Relationship with Denbury Resources, Inc.
Through its control of our general partner, Denbury has the ability to
control our management. During 2004 and 2003, we acquired CO2 volumetric
production payments and related wholesale marketing contracts from Denbury for
$4.7 million and $24.4 million, respectively. Additionally we enter into
transactions with Denbury in the ordinary course of its operations. During 2004,
these transactions included:
- Purchases of crude oil from Denbury totaling $78.0 million.
- Provision of transportation services for crude oil by truck
(beginning in September 2004) totaling $0.2 million.
49
- Provision of crude oil pipeline transportation services
(beginning in September 2004) totaling $1.1 million.
- Provision of CO2 transportation to the Brookhaven field
(beginning in December 2004).
- Provision of CO2 transportation services to our wholesale
industrial customers by Denbury's pipeline. The fees for this
service totaled $2.7 million in 2004.
- Provision of pipeline monitoring services to Denbury for its
CO2 pipelines totaling $22,000 in 2004.
- Provision of services by Denbury officers as directors of our
general partner. We paid Denbury $120,000 for these services
in 2004.
At December 31, 2004, we owed Denbury $0.7 million for purchases of crude
oil and $0.5 million related to CO2 transportation services. Denbury owed us
$0.4 million for crude oil trucking and pipeline 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. Denbury also has the right to purchase the
Mississippi CO2 pipeline to Brookhaven field at 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.
2004 2003
--------- ---------
(in thousands)
Audit Fees (a).................... $ 665 $ 211
Audit-Related Fees (b)............ 36 92
--------- ---------
Total............................. $ 701 $ 303
========= =========
(a) Fees for audit services billed in 2004 consisted of:
Audit of our annual financial statements Sarbanes-Oxley Section 404 audit
work Audit of our General Partner financial statements Reviews of our
quarterly financial statements
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.
(b) Fees for audit-related services in 2004 and 2003 consisted of:
Financial accounting and reporting consultations Sarbanes-Oxley Act,
Section 404 advisory services Employee benefit plan audits.
50
Deloitte provided no tax services or other services to us in 2004 or 2003,
however, in 2005 Deloitte will begin providing tax services, consisting of tax
compliance and tax advice. 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.
Pre-Approval Policy
The services by Deloitte in 2004 and 2003 were pre-approved in accordance
with the pre-approval policy and procedures adopted by the Audit Committee. 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.
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 meetings.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) and (2) Financial Statements and Financial Statement Schedules
See "Index to Consolidated Financial Statements" set forth on page 54.
(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 June 1, 2004, 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 10.1 to Form 8-K dated
June 1, 2004)
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)
51
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 (incorporated by reference to
Exhibit 10.7 to Form 10-K for the year ended December
31, 2003)
10.8 Carbon Dioxide Transportation Agreement between Denbury
Resources, Inc. and Genesis Crude Oil, L.P.
(incorporated by reference to Exhibit 10.8 to Form 10-K
for the year ended December 31, 2003)
*10.9+ Genesis Energy, Inc. Stock Appreciation Rights Plan
*10.10+ Form of Stock Appreciation Rights Plan Grant Notice
*10.11+ Summary of Director Compensation
*10.12+ Summary of Genesis Energy, Inc. Bonus Plan
10.13 Second Production Payment Purchase and Sale Agreement
between Denbury Onshore, LLC. and Genesis Crude Oil,
L.P. executed August 26, 2004 (incorporated by reference
to Exhibit 99.1 to Form 8-K dated August 26, 2004)
10.14 Second Carbon Dioxide Transportation Agreement between
Denbury Onshore, LLC. and Genesis Crude Oil, L.P.
(incorporated by reference to Exhibit 99.1 to Form 8-K
dated August 26, 2004)
11.1 Statement Regarding Computation of Per Share Earnings (See
Notes 2 and 8 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.
52
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 15th day of
March, 2005.
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 15, 2005
- ----------------------- and President
Mark J. Gorman (Principal Executive Officer)
/s/ ROSS A. BENAVIDES Chief Financial Officer, March 15, 2005
- ----------------------- General Counsel and Secretary
Ross A. Benavides (Principal Financial Officer)
/s/ KAREN N. PAPE Vice President and Controller March 15, 2005
- ----------------------- (Principal Accounting Officer)
Karen N. Pape
/s/ GARETH ROBERTS Chairman of the Board and March 15, 2005
- ----------------------- Director
Gareth Roberts
/s/ RONALD T. EVANS Director March 15, 2005
- -----------------------
Ronald T. Evans
/s/ HERBERT I. GOODMAN Director March 15, 2005
- -----------------------
Herbert I. Goodman
/s/ SUSAN O. RHENEY Director March 15, 2005
- -----------------------
Susan O. Rheney
/s/ PHIL RYKHOEK Director March 15, 2005
- -----------------------
Phil Rykhoek
/s/ J. CONLEY STONE Director March 15, 2005
- -----------------------
J. Conley Stone
/s/ MARK A. WORTHEY Director March 15, 2005
- -----------------------
Mark A. Worthey
53
GENESIS ENERGY, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
Report of Independent Registered Public Accounting Firm.............................................. 55
Consolidated Balance Sheets, December 31, 2004 and 2003.............................................. 56
Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003 and 2002........... 57
Consolidated Statements of Comprehensive (Loss) Income for the Years Ended December 31, 2004, 2003
and 2002.......................................................................................... 58
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002........... 59
Consolidated Statements of Partners' Capital for the Years Ended December 31, 2004, 2003 and 2002.... 60
Notes to Consolidated Financial Statements........................................................... 61
54
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Genesis Energy, Inc. and Unitholders of
Genesis Energy, L.P.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Genesis Energy,
L.P. and subsidiaries (the "Partnership") as of December 31, 2004 and 2003, 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, 2004. These financial statements are the responsibility of
the Partnership's management. Our responsibility is to express an opinion on the
financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Genesis Energy, L.P. and
subsidiaries at December 31, 2004 and 2003, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2004, in conformity with accounting principles generally accepted in the
United States of America.
We have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the effectiveness of the
Partnership's internal control over financial reporting as of December 31, 2004,
based on the criteria established in Internal Control -- Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission
and our report dated March 14, 2005 expressed an unqualified opinion on
management's assessment of the effectiveness of the Partnership's internal
control over financial reporting and an unqualified opinion on the effectiveness
of the Partnership's internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
- --------------------------
Houston, Texas
March 14, 2005
55
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31, December 31,
2004 2003
------------ ------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents...................................... $ 2,078 $ 2,869
Accounts receivable:
Trade....................................................... 68,737 66,732
Related party............................................... 584 -
Inventories.................................................... 1,866 1,546
Net investment in direct financing leases, net of unearned
income - current portion.................................... 318 -
Insurance receivable........................................... 2,125 15,524
Other.......................................................... 1,688 1,540
---------- ----------
Total current assets........................................ 77,396 88,211
FIXED ASSETS, at cost............................................. 73,023 70,695
Less: Accumulated depreciation................................ (39,237) (36,724)
---------- ----------
Net fixed assets............................................ 33,786 33,971
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned
income......................................................... 4,247 -
CO2 ASSETS, net of amortization................................... 26,344 24,073
OTHER ASSETS, net of amortization................................. 1,381 860
---------- ----------
TOTAL ASSETS...................................................... $ 143,154 $ 147,115
========== ==========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable -
Trade....................................................... $ 74,176 $ 60,108
Related party............................................... 1,239 7,067
Accrued liabilities............................................ 6,523 20,069
---------- ----------
Total current liabilities................................... 81,938 87,244
LONG-TERM DEBT.................................................... 15,300 7,000
OTHER LONG-TERM LIABILITIES....................................... 160 -
COMMITMENTS AND CONTINGENCIES (Note 17)
MINORITY INTERESTS................................................ 517 517
PARTNERS' CAPITAL
Common unitholders, 9,314 units issued and outstanding......... 44,326 51,299
General partner................................................ 913 1,055
---------- ----------
Total partners' capital..................................... 45,239 52,354
---------- ----------
TOTAL LIABILITIES AND PARTNERS' CAPITAL........................... $ 143,154 $ 147,115
========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
56
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
Year Ended December 31,
-----------------------------------------------
2004 2003 2002
------------ ----------- ------------
REVENUES:
Crude oil gathering and marketing:
Unrelated parties (including revenues from
buy/sell arrangements of $296,329, $177,244,
and $222,752 in 2004, 2003 and 2002,
respectively)..................................... $ 901,689 $ 641,684 $ 636,107
Related parties...................................... 213 - 3,036
Pipeline transportation:
Unrelated parties.................................... 15,506 15,134 13,485
Related parties...................................... 1,174 - -
CO2 marketing revenues.................................. 8,561 1,079 -
------------ ----------- ------------
Total revenues.................................... 927,143 657,897 652,628
COSTS AND EXPENSES:
Crude oil costs:
Unrelated parties (including crude oil costs from
buy/sell arrangements of $295,380, $176,953,
and $222,708 in 2004, 2003 and 2002,
respectively)..................................... 805,990 562,626 589,598
Related parties...................................... 77,998 59,653 26,452
Field operating...................................... 13,880 11,497 11,916
Pipeline operating costs................................ 8,137 10,026 8,076
CO2 marketing costs:
Transportation costs - related party................. 2,694 355 -
Other costs.......................................... 105 - -
General and administrative.............................. 11,031 8,768 7,864
Depreciation and amortization........................... 7,298 4,641 4,603
Change in fair value of derivatives..................... - - 1,279
Net loss (gain) on disposal of surplus assets........... 33 (236) (705)
Other operating charges................................. - - 1,500
------------ ----------- ------------
Total costs and expenses.......................... 927,166 657,330 650,583
------------ ----------- ------------
OPERATING (LOSS) INCOME.................................... (23) 567 2,045
OTHER INCOME (EXPENSE):
Interest income......................................... 44 34 69
Interest expense........................................ (970) (1,020) (1,104)
------------ ----------- ------------
(LOSS) INCOME FROM CONTINUING OPERATIONS................... (949) (419) 1,010
Discontinued operations:
(Loss) income from operations from discontinued
Texas System (including gain on disposal of
$13,028 in 2003) before minority interests.............. (463) 13,742 4,082
Minority interests in discontinued operations.............. - 1 -
------------ ----------- ------------
(LOSS) INCOME FROM DISCONTINUED OPERATIONS................. (463) 13,741 4,082
------------ ----------- ------------
NET (LOSS) INCOME.......................................... $ (1,412) $ 13,322 $ 5,092
============ =========== ============
57
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS-CONTINUED
(In thousands, except per unit amounts)
Year Ended December 31,
-----------------------------------------------
2004 2003 2002
------------ ----------- ------------
NET (LOSS) INCOME PER COMMON UNIT-
BASIC AND DILUTED:
(Loss) income from continuing operations.......... $ (0.10) $ (0.05) $ 0.11
(Loss) income from discontinued operations........ (0.05) 1.55 0.47
------------ ----------- ------------
NET (LOSS) INCOME.............................. $ (0.15) $ 1.50 $ 0.58
============ =========== ============
Weighted average number of common units
outstanding.......................................... 9,314 8,715 8,625
============ =========== ============
The accompanying notes are an integral part of these consolidated financial
statements.
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
(In thousands)
Year Ended December 31,
---------------------------------------
2004 2003 2002
---------- --------- ---------
NET (LOSS) INCOME................................................... $ (1,412) $ 13,322 $ 5,092
OTHER COMPREHENSIVE INCOME (LOSS):
Change in fair value of derivatives used for hedging purposes.. - 39 (39)
---------- --------- ---------
COMPREHENSIVE (LOSS) INCOME......................................... $ (1,412) $ 13,361 $ 5,053
========== ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
58
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Year Ended December 31,
---------------------------------------
2004 2003 2002
---------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income................................................. $ (1,412) $ 13,322 $ 5,092
Adjustments to reconcile net income to net cash provided by
operating activities -
Depreciation................................................... 4,846 5,970 4,965
Amortization of CO2 contracts and covenant not-to-compete...... 2,452 534 848
Amortization and write-off of credit facility issuance costs... 373 1,031 736
Amortization of unearned income on direct financing leases..... (36) - -
Payments received under direct financing leases................ 75 - -
Change in fair value of derivatives............................ - 39 2,055
Loss (gain) on disposal of assets.............................. 33 (13,264) (708)
Minority interests equity in earnings (losses)................. - 1 -
Other non-cash charges......................................... 1,151 228 1,500
Changes in components of working capital -
Accounts receivable......................................... (2,589) 13,932 81,134
Inventories................................................. (1,170) 3,758 (1,051)
Other current assets........................................ 13,251 (11,654) 3,909
Accounts payable............................................ 7,525 (20,211) (86,159)
Accrued liabilities......................................... (14,797) 11,007 (4,904)
---------- --------- ---------
Net cash provided by operating activities........................... 9,702 4,693 7,417
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment............................... (8,322) (4,910) (4,211)
CO2 contracts acquisition......................................... (4,723) (24,401) -
Proceeds from disposal of assets.................................. 112 22,341 2,243
Other, net........................................................ 128 (24) 5
---------- --------- ---------
Net cash used in investing activities............................... (12,805) (6,994) (1,963)
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank borrowings (repayments), net................................. 8,300 1,500 (8,400)
Other, net........................................................ 541 - -
Credit facility issuance fees..................................... (826) (1,093) -
Issuance of limited and general partner interests................. - 5,012 -
Minority interests contributions.................................. - 1 -
Distributions to common unitholders............................... (5,589) (1,294) (1,725)
Distributions to General Partner.................................. (114) (27) (35)
---------- --------- ---------
Net cash provided by (used in) financing activities............... 2,312 4,099 (10,160)
Net increase (decrease) in cash and cash equivalents................ (791) 1,798 (4,706)
Cash and cash equivalents at beginning of period.................... 2,869 1,071 5,777
---------- --------- ---------
Cash and cash equivalents at end of period.......................... $ 2,078 $ 2,869 $ 1,071
========== ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
59
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(In thousands)
Partners' Capital
----------------------------------------------------------------------------
Accumulated
Number of Other
Common Common General Comprehensive
Units Unitholders Partner Income Total
---------- ----------- ---------- ------------- -----------
Partners' capital, January 1, 2002 ...... 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..... 9,314 51,299 1,055 - 52,354
Net loss ................................ - (1,384) (28) - (1,412)
Cash distributions ...................... - (5,589) (114) - (5,703)
---------- ----------- ---------- ------------- -----------
Partners' capital, December 31, 2004..... 9,314 $ 44,326 $ 913 $ - $ 45,239
========== =========== ========== ============= ===========
The accompanying notes are an integral part of these
consolidated financial statements.
60
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 8.
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, 2004 and 2003 for GELP and
its results of operations, cash flows and changes in partners' capital for the
years ended December 31, 2004, 2003 and 2002, and changes in comprehensive
income for the years ended December 31, 2004, 2003 and 2002.
All significant intercompany transactions have been eliminated.
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 are 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.
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.
61
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.
Interest is capitalized in connection with the construction of major
facilities. The capitalized interest is recorded as part of the asset to which
it relates and is amortized over the asset's estimated useful life.
Long-lived assets are reviewed for impairment. An asset is 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. 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.
Direct Financing Leasing Arrangements
We lease two pipelines to Denbury under direct financing leases. The
lease to Denbury of a segment of crude oil pipeline will expire in ten years,
and the lease of a segment of CO2 pipeline will expire in eight years.
When a direct financing lease is consummated, we record the gross
finance receivable, unearned income and the estimated residual value of the
leased pipelines. Unearned income represents the excess of the gross receivable
plus the estimated residual value over the costs of the pipelines. Unearned
income is recognized as financing income using the interest method over the term
of the transaction and is included in pipeline revenue in the Consolidated
Statements of Operations. The pipeline cost is not included in fixed assets. See
Note 5.
CO2 and Other Assets
Other assets consist primarily of CO2 assets and intangibles. The CO2
assets include two volumetric production payments and long-term contracts to
sell the CO2 volume. The contract values are being amortized on a
units-of-production method. See Note 6.
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.
62
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.
Stock Appreciation Rights Plan
Upon exercise, a participant in our stock appreciation rights plan
receives 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. We accrue a
liability for the difference between the market price at the balance sheet date
and the strike price of each outstanding stock appreciation right, to the extent
that the difference is positive. See Note 13.
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.
Income from direct financing leases is being recognized ratably over the
term of the leases and is included in pipeline revenues.
Revenues from CO2 marketing 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.
We enter into buy/sell arrangements that are accounted for on a gross
basis in our statements of operations as revenues and costs of crude. These
transactions are contractual arrangements that establish the terms of the
purchase of a particular grade of crude oil at a specified location and the sale
of a particular grade of crude oil at a different location at the same or at
another specified date. These arrangements are detailed either jointly, in a
single contract, or separately, in individual contracts that are entered into
concurrently or in contemplation of one another with a single counterparty. Both
transactions require physical delivery of the crude oil and the risk and reward
of ownership are evidenced by title transfer, assumption of environmental risk,
transportation scheduling, credit risk and counterparty nonperformance risk. We
believe that requirements of EITF No. 03-11, "Reporting Realized Gains and
Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and
Not "Held for Trading Purposes" as Defined in Issue No. 02-3", and Derivatives
Implementation Group Statement 13 Implementation Issue No. K1, "Miscellaneous:
Determining Whether Separate Transactions Should be Viewed as a Unit" support
the presentation of these transactions on a gross basis. Additionally FASB
Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts" (FIN
39) prohibits a receivable from being netted against a payable when the
receivable is subject to credit risk unless a right of offset exists that is
enforceable by law; therefore, netting the separate purchase and sales
transactions on the statements of operations seems inconsistent with the gross
presentation of the payables and receivables in the balance sheet as required
under FIN 39.
Cost of sales for the CO2 marketing activities consists of a
transportation fee charged by Denbury ($0.16 per Mcf, adjusted annually for
inflation) to transport the CO2 to the customer through Denbury's pipeline and
insurance costs.
Derivative Instruments and Hedging Activities
We minimize our exposure to price risk by limiting our inventory
positions, therefore we rarely use derivative instruments. In 2003 and 2004, 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
63
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 9,313,811, 8,714,845 and 8,624,554 for the years
ended December 31, 2004, 2003 and 2002, respectively. Diluted net income per
Common Unit did not differ from basic net income per Common Unit for any period
presented. See Note 8 for a computation of net (loss) income per Common Unit.
Recent and Proposed Accounting Pronouncements
The Emerging Issues Task Force (EITF) of the Financial Accounting
Standards Board (FASB) is currently considering the issue of accounting for
buy/sell arrangements as part of its EITF Issue No. 04-13, "Accounting for
Purchases and Sales of Inventory with the Same Counterparty" (Issue 04-13). As
part Issue 04-13, the EITF is considering a requirement that all buy/sell
arrangements be reflected on a net basis, such that the purchase and sale are
netted and shown as either a net purchase or a net sale in the income statement.
Should this requirement be adopted, the revenues and costs of crude oil
reflected on our statements of operations will be reduced. Our reported crude
oil gathering and marketing revenues from unrelated parties for the year ended
December 31, 2004 would be reduced by $296 million to $605 million. Our reported
crude oil costs from unrelated parties for the year ended December 31, 2004,
would be reduced by $295 million to $511 million.
On November 30, 2004, the FASB issued SFAS No. 151, "Inventory Costs."
This statement clarifies the accounting for abnormal amounts of idle facility
expense, freight, handling costs, and wasted material (spoilage). This statement
requires that these items be charged to expense regardless of whether they meet
the "so abnormal" criterion outlined in Accounting Research Bulletin 43. This
statement is effective for inventory costs incurred during fiscal years
beginning after June 15, 2005. The adoption of this statement is not expected to
have any effect on our financial position, results of operations or cash flows.
In December 2004, the FASB issued SFAS No. 153, "Exchanges of
Nonmonetary Assets", which amends Accounting Principles Board Opinion No. 29
(APB 29). SFAS No. 153 provides a general exception from fair value measurement
for exchanges of nonmonetary assets that do not have commercial substance. A
nonmonetary exchange has commercial substance if the future cash flows of the
entity are expected to change significantly as a result of the exchange. This
general exception replaces the exception from fair value measurement in APB 29
for nonmonetary exchanges of similar productive assets. This statement is
effective for nonmonetary asset exchanges occurring in fiscal periods beginning
after June 15, 2005. At this time we do not expect the adoption of this
statement to have any effect on our financial position, results of operations or
cash flows.
In December 2004, the FASB issued SFAS No. 123 (revised December 2004),
"Share-Based Payment". This statement replaces SFAS No. 123 and requires that
compensation costs related to share-based payment transactions be recognized in
the financial statements. This statement is effective for public entities as of
the first interim reporting period that begins after June 15, 2005. The adoption
of this statement is not expected to have a material effect on our financial
position, results of operations or cash flows.
64
3. INVENTORIES
Inventories consisted of the following (in thousands).
December 31,
------------------------------
2004 2003
------------ ------------
Crude oil inventories, at lower of cost or market................ $ 1,802 $ 1,476
Fuel and supplies inventories, at lower of cost or market........ 64 70
------------ ------------
Total inventories.......................................... $ 1,866 $ 1,546
============ ============
4. FIXED ASSETS
Fixed assets consisted of the following (in thousands).
December 31,
------------------------------
2004 2003
------------ ------------
Land and buildings......................................... $ 1,167 $ 1,481
Pipelines and related assets............................... 60,296 57,429
Vehicles and transportation equipment...................... 1,416 1,510
Office equipment, furniture and fixtures................... 2,791 3,043
Construction in progress................................... 841 -
Other ..................................................... 6,512 7,232
------------ ------------
73,023 70,695
Less - Accumulated depreciation............................ (39,237) (36,724)
------------ ------------
Net fixed assets........................................... $ 33,786 $ 33,971
============ ============
In 2004, $76,000 of interest cost was capitalized related to the
construction of pipelines and related assets. No interest was capitalized in
2003 or 2002.
Depreciation expense, including discontinued operations, was $4,846,000,
$5,970,000 and $4,965,000 for the years ended December 31, 2004, 2003, and 2002,
respectively. In 2004, depreciation expense included $933,000 of impairment
recorded to value the Liberty to Baton Rouge segment of our Mississippi System
at its estimated salvage value.
In 2003, we recorded a charge of $700,000 for an accrual for the removal of
an abandoned offshore pipeline. In 2004, we received permission to abandon the
pipeline in place, and reversed the amount of the accrual that had not been
spent. Additionally, in 2004, we agreed to remove certain pipeline facilities
from land we sold. We expect to complete this obligation in the second quarter
of 2005. A reconciliation of our liability for these asset retirement
obligations is as follows (in thousands):
Asset retirement obligations as of December 31, 2003..................... $ 700
Asset retirement liability obligations incurred during 2004.............. 96
Asset retirement obligations settled during 2004......................... (566)
Revisions to asset retirement obligations................................ (84)
----------
Asset retirement obligations as of December 31, 2004..................... $ 146
==========
5. NET INVESTMENT IN DIRECT FINANCING LEASES
In the fourth quarter of 2004, we constructed a segment of pipeline to
connect a producing field operated by Denbury to our Mississippi System. Denbury
will pay us a minimum payment each month for the right to use this pipeline
segment. This arrangement has been accounted for as a direct financing lease.
In the fourth quarter of 2004 we constructed a CO2 pipeline in Mississippi
to transport CO2 from Denbury's main CO2 pipeline to an oil field to which we
also constructed an oil pipeline to bring the oil from the field to our existing
Mississippi pipeline. Denbury has the exclusive right to use this CO2 pipeline.
This arrangement has been accounted for as a direct financing lease.
The following table lists the components of the net investment in direct
financing leases as of December 31, 2004 (in thousands):
65
Total minimum lease payments to be received................................. $ 6,806
Estimated residual values of leased property (unguaranteed)................. 1,092
Less: Unearned income...................................................... (3,333)
----------
Net investment in direct financing leases................................... $ 4,565
==========
At December 31, 2004, minimum lease payments to be received for each of the
five succeeding fiscal years are $0.8 million per year.
6. CO2 AND OTHER ASSETS
Carbon Dioxide (CO2) Assets
CO2 assets consisted of the following (in thousands).
December 31,
------------------------------
2004 2003
------------ ------------
CO2 volumetric production payments.......................... $ 29,124 $ 24,401
Less - Accumulated amortization (2,780) (328)
------------ ------------
Net CO2 assets.............................................. $ 26,344 $ 24,073
============ ============
In November 2003, we purchased CO2 assets from Denbury for $24.4 million in
cash and, in September 2004, we purchased additional CO2 assets for $4.7
million. These assets included the assignment of an interest in 167.5 and 33.0
billion cubic feet (Bcf) of CO2, under two volumetric production payments and
Denbury's existing long-term CO2 supply agreements with three of its industrial
customers.
The volumetric production payments entitle us to a maximum daily quantity
of CO2 of 65,250 million cubic feet (Mcf) per day through December 31, 2009,
55,750 Mcf per day for the calendar years 2010 through 2012 and 37,750 Mcf per
day beginning in 2013 until we have received all volumes under the production
payments. Under the terms of transportation agreements 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 five industrial contracts expire
at various dates between 2010 and 2016.
The CO2 assets are being amortized on a units-of-production method. After
purchase price adjustments, we had 197.5 Bcf of CO2 at acquisition, and the
total $29.1 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. For 2004, we recorded amortization of $2,452,000. We
have 178.7 Bcf of CO2 remaining under the volumetric production payments at
December 31, 2004. 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 $2,677,000 annually.
Other Assets
Other assets consisted of the following (in thousands).
December 31,
------------------------------
2004 2003
------------ ------------
Credit facility fees........................................ $ 1,491 $ 1,117
Other....................................................... 108 40
------------ ------------
1,599 1,157
Less - Accumulated amortization............................. (218) (297)
------------ ------------
Net other assets............................................ $ 1,381 $ 860
============ ============
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, 2004, no
impairment has occurred of our remaining intangible assets.
66
Amortization expense of credit facility fees for the years ended December
31, 2004, 2003 and 2002 was $373,000, $298,000 and $456,000, respectively
Additionally, in 2003, we charged to expense $733,000 of fees related to the
facility that existed at the end of 2002.
We had a covenant-not-to compete that was amortized over a five-year period
that expired in 2003. Amortization expense for the covenant-not-to-compete was
$205,000 and $848,000 for the years ended December 31, 2003 and December 31,
2002, respectively.
7. DEBT
On June 1, 2004, we finalized a $100 million senior secured bank credit
facility with a group of five lenders (Credit Facility). The Credit Facility
consists of a $50 million revolving line of credit for acquisitions and a $50
million working capital revolving credit facility. The facility matures in June
2008. This facility replaced our then existing $65 million facility.
The working capital portion of the Credit Facility has a sublimit of $15
million for working capital loans with the remainder of the $50 million portion
available for letters of credit.
The key terms of the Credit Facility are as follows:
- Letter of credit fees are based on the usage of the working capital
portion of the Credit Facility in relation to the borrowing base and
will range from 1.75% to 2.75%. The rate can fluctuate daily. At
December 31, 2004, the rate was 1.75%.
- The interest rate on working capital borrowings is also based on the
usage of the Credit 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 0.25% to the prime rate plus 1.25%. The interest
rate for LIBOR-based loans can range from the LIBOR rate plus 1.75%
to the LIBOR rate plus 2.75%. The rate can fluctuate daily. At
December 31, 2004, we borrowed at the prime rate plus 0.25%.
- The interest rate on acquisition borrowings may be based on the
prime rate or the LIBOR rate, at our option. The interest rate on
prime rate loans will be the prime rate plus 1.50%. The interest
rate for LIBOR-based loans will be the LIBOR rate plus 3.00%. The
rate can fluctuate daily. At December 31, 2004, we borrowed at the
prime rate plus 1.50% under this portion of the Credit Facility.
- We pay a commitment fee on the unused portion of the $100 million
commitment. The commitment fee on the working capital portion is
based on the usage of that portion of the Credit Facility in
relation to the borrowing base and will range from 0.375% to 0.50%.
At December 31, 2004, the commitment fee rate was 0.375%. The
commitment fee rate on the acquisition portion is 0.50%.
- 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 Credit
Facility generally to include cash balances, net accounts receivable
and inventory, less deductions for certain accounts payable. The
Borrowing Base is limited to $50 million and is calculated monthly.
At December 31, 2004, the Borrowing Base was $39.5 million.
- Collateral under the Credit Facility consists of our accounts
receivable, inventory, cash accounts, margin accounts and fixed
assets.
- The Credit 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, and a minimum
EBITDA (earnings before interest, taxes, depreciation and
amortization).
At December 31, 2004, we had $5.0 million outstanding under the working
capital portion and $10.3 million outstanding under the acquisition portion of
the Credit Facility. Due to the revolving nature of loans under both portions of
the Credit Facility, additional borrowings and periodic repayments and
re-borrowings may be made until the maturity date of June 1, 2008. At December
31, 2004, we had letters of credit outstanding under the Credit Facility
totaling $12.6 million, comprised of $6.5 million and $5.3 million for crude oil
purchases related to December 2004 and January 2005, respectively and $0.8
million related to other business obligations.
67
We have no limitations on making distributions in our Credit Agreement,
except as to the effects of distributions in covenant calculations. The Credit
Agreement requires we maintain a cash flow coverage ratio of 1.1 to 1.0. In
general, this calculation compares operating cash inflows, as adjusted in
accordance with the Credit Agreement, less maintenance capital expenditures, to
the sum of interest expense and distributions. At December 31, 2004, the
calculation resulted in a ratio of 1.1 to 1.0.
8. PARTNERS' CAPITAL AND DISTRIBUTIONS
Partners' Capital
During 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 and 2004, 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, 2004.
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 (as defined by
our 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 reserves. The target minimum quarterly distribution ("MQD") for each
quarter is $0.20 per unit. During 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. We paid distributions of $0.15 per unit ($1.4 million in
total) for each quarter of 2004.
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, 2004.
68
Net (Loss) Income Per Common Unit
The following table sets forth the computation of basic net (loss)
income per Common Unit for 2004, 2003, and 2002 (in thousands, except per unit
amounts).
Year Ended December 31,
-----------------------------------------------
2004 2003 2002
------------ ----------- ------------
Numerators for basic and diluted net (loss) income
per common unit:
(Loss) income from continuing operations.......... $ (949) $ (419) $ 1,010
Less general partner 2% ownership................. (19) (8) 20
------------ ----------- ------------
(Loss) income from continuing operations
available for common unitholders............... $ (930) $ (411) $ 990
============ =========== ============
(Loss) income from discontinued operations........ $ (463) $ 13,741 $ 4,082
Less general partner 2% ownership................. (9) 275 82
------------ ----------- ------------
(Loss) income from discontinued operations
available for common unitholders............... $ (454) $ 13,466 $ 4,000
============ =========== ============
Denominator for basic and diluted per Common Unit
- weighted average number of Common Units
outstanding............................................ 9,314 8,715 8,625
============ =========== ============
Basic and diluted net (loss) income per Common
Unit:
(Loss) income from continuing operations.......... $ (0.10) $ (0.05) $ 0.11
(Loss) income from discontinued operations........ (0.05) 1.55 0.47
------------ ----------- ------------
Net (loss) income................................. $ (0.15) $ 1.50 $ 0.58
============ =========== ============
9. 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) Pipeline Transportation - interstate and intrastate
crude oil, natural gas and CO2 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. The pipeline transportation segment
information includes the revenue, segment margin and assets of the direct
financing leases. See Note 5.
69
Crude Oil
Gathering and Pipeline CO2
Marketing Transportation Marketing Total
------------- -------------- --------- ----------
(in thousands)
Year Ended December 31, 2004
Revenues:
External Customers...................... $ 901,902 $ 13,212 $ 8,561 $ 923,675
Intersegment (a)........................ - 3,468 - 3,468
------------- -------------- --------- ----------
Total revenues of reportable segments... $ 901,902 $ 16,680 $ 8,561 $ 927,143
============= ============== ========= ==========
Segment margin excluding
depreciation and amortization (b).... $ 4,034 8,543 $ 5,762 $ 18,339
Capital expenditures.................... $ 284 $ 8,187 $ 4,723 $ 13,194
Maintenance capital expenditures........ $ 284 $ 655 $ - $ 939
Net fixed and other long-term
assets (c).......................... $ 6,067 $ 33,347 $ 26,344 $ 65,758
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 (c)........................... $ 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).... $ 9,898 5,409 $ - $ 15,307
Capital expenditures.................... $ 690 $ 1,981 $ - $ 2,671
Maintenance capital expenditures........ $ 690 $ 1,981 $ - $ 2,671
(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:
70
Year Ended December 31,
-------------------------------------------------
2004 2003 2002
------------ ------------- ------------
(in thousands)
Segment margin excluding depreciation and
amortization.................................. $ 18,339 $ 13,740 $ 15,307
General and administrative expenses............. 11,031 8,768 7,864
Depreciation, amortization and impairment....... 7,298 4,641 4,603
Net loss (gain) on disposal of surplus assets... 33 (236) (705)
Other operating charges......................... - - 1,500
Interest expense, net........................... 926 986 1,035
------------ ------------- ------------
(Loss) income from continuing operations........ $ (949) $ (419) $ 1,010
============ ============= ============
(c) Net fixed and other long-term assets are the measure used by management in
evaluating the results of its operations on a segment basis. Current assets
are not allocated to segments as the amounts are shared by the segments or
are not meaningful in evaluating the success of the segment's operations.
10. 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 asset base 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 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. 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.
71
Operating results from the discontinued operations for the years ended
December 31, 2004, 2003 and 2002 were as follows:
Year Ended December 31,
-------------------------------------------------
2004 2003 2002
------------ ------------- ------------
(in thousands)
Revenues:
Gathering and marketing.............................. $ - $ 263,930 $ 252,452
Pipeline............................................. - 6,480 6,726
------------ ------------- ------------
Total revenues.................................... - 270,410 259,178
Costs and expenses:
Crude costs and field operating costs................ 5 261,704 247,797
Pipeline operating costs............................. 458 5,846 4,852
General and administrative........................... - 282 425
Depreciation and amortization........................ - 1,864 1,210
Change in fair value of derivatives.................. - - 815
Net gain on disposal of surplus assets............... - - (3)
------------ ------------- ------------
Total costs and expenses.......................... 463 269,696 255,096
------------ ------------- ------------
Operating (loss) income from discontinued operations.... (463) 714 4,082
Gain on disposal of assets.............................. - 13,028 -
------------ ------------- ------------
(Loss) income from operations from discontinued
Texas System before minority interests............... $ (463) $ 13,742 $ 4,082
============ ============= ============
11. TRANSACTIONS WITH RELATED PARTIES
Except for below-market guaranty fees paid in 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.
Sales and Purchases of Crude Oil
Denbury became a related party in May 2002. Purchases of crude oil from
Denbury for the years ended December 31, 2004 and 2003 were $78.0 million and
$59.7 million, respectively. 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. Denbury began shipping its own crude oil on our Mississippi System in
September 2004, so our purchases of crude oil from Denbury will be significantly
less in the future.
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., a subsidiary of Salomon. These transactions were bulk
and exchange transactions.
Transportation Services
In September 2004, we entered into an agreement with Denbury where we
would provide truck transportation services to Denbury to move their crude oil
from the wellhead to our Mississippi pipeline. Previously we had purchased
Denbury's crude oil and trucked the oil for ourselves. Denbury pays us a fee for
this trucking service. For the four months in 2004 when we provided this
service, we received fees from Denbury totaling $0.2 million. These fees are
reflected in the statement of operations as gathering and marketing revenues.
In September 2004, Denbury also became a shipper on our Mississippi
pipeline. Fees for this transportation service totaled $1.1 million for the four
month period. We also billed Denbury $76,000 under the direct financing lease
arrangements for the Olive crude oil pipeline and the Brookhaven CO2 pipeline
and recorded $36,000 of pipeline transportation income from these arrangements.
See Note 5.
72
We also provide pipeline monitoring services to Denbury for which we
charged $22,000 in 2004. This revenue is included in pipeline revenues in the
statement of operations.
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 $14,065,000, $16,028,000, and
$17,280,000 for the years ended December 31, 2004, 2003 and 2002, respectively.
Due to and from Related Parties
At December 31, 2004 and 2003, we owed Denbury $0.7 million and $6.9
million, respectively, for purchases of crude oil. Additionally, we owed Denbury
$0.5 million and $0.1 million, respectively, for CO2 transportation services at
December 31, 2004 and 2003. Denbury owed us $0.4 million for transportation
services at December 31, 2004. The General Partner owed us $0.1 million at
December 31, 2004. We owed the General Partner $0.1 million at December 31, 2003
for administrative services.
Directors' Fees
In 2004 and 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 volumetric production payments from Denbury in 2004 and 2003
for $4.7 million and $24.4 million, respectively. Denbury charges us a
transportation fee of $0.16 per Mcf (adjusted for inflation) to deliver the CO2
for us to our customers. For 2004 and the last two months of 2003, we paid
Denbury $2.7 million and $0.4 million for these transportation services related
to our sales of CO2. See Note 6.
Financing
Our general partner guarantees our obligations under the Credit
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.
Guaranty Fees
From January 2002 to April 2002, Salomon provided guaranties under a
transition arrangement with Salomon and Citicorp to the Partnership. For the
year ended December 31, 2002, the Partnership paid Salomon $61,000 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.
12. SUPPLEMENTAL CASH FLOW INFORMATION
Cash received by us for interest during the years ended December 31, 2004,
2003 and 2002 was $44,000, $34,000, and $68,000, respectively. Cash payments for
interest were $674,000, $1,194,000, and $537,000 during the years ended December
31, 2004, 2003 and 2002, respectively.
For the year ended December 31, 2004, the partnership incurred liabilities
for fixed asset additions totaling $0.2 million that had not been paid at the
end of the year and, therefore, are not included in the caption "Additions to
property and equipment" on the Consolidated Statements of Cash Flows.
73
13. 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
$635,000, $507,000, and $564,000 for the years ended December 31, 2004, 2003 and
2002, respectively.
The General Partner also provided certain health care and survivor benefits
for its active employees. In 2004, 2003 and 2002, 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 $1,219,000, $1,368,000, and $1,360,000 in 2004, 2003 and 2002,
respectively.
Stock Appreciation Rights Plan
In December 2003, the Board approved a Stock Appreciation Rights (SAR)
plan for all employees of our General Partner. 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.
At December 31, 2004, awards of 558,697 rights were outstanding, of
which 96,438 vested on December 31, 2004. The value of the total rights
outstanding at December 31, 2004 was $1.4 million. The vested rights had a value
to participants of $0.3 million at December 31, 2004. In 2004 and 2003, we
recorded non-cash expense of $1,151,000 and $228,000 for the increase between
the strike price of the outstanding rights and the closing market price for
Common Units on December 31, 2004 and 2003, respectively.
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 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
74
allocated to the bonus pool increases for each $1.6 million earned, such that a
bonus pool of $2.3 million will exist if the Partnership earns $14.6 million of
Available Cash. We accrued $0.2 million for the bonus pool for 2004.
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 who could earn a
total bonus ranging from zero to twenty percent. Certain members 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.
14. 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.
Occidental Energy Marketing, Inc., Marathon Ashland Petroleum LLC and
Plains Marketing, L.P. accounted for 20.4%, 12.8% and 10.0% of total revenues in
2004, respectively. 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. The
majority of the revenues from these five customers in all three years relate to
our gathering and marketing operations.
15. 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.
The carrying value of the direct financing leases in the Consolidated
Balance Sheets approximated fair value as these leases began at the end of 2004
when the assets were constructed.
16. DERIVATIVES
Our market risk in the purchase and sale of our 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 2004, we used financial contracts minimally,
and at December 31, 2004 there were no derivative contracts outstanding. 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. 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 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.
75
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.
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, 2004.
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, 2004 and 2003. The decrease in fair
value of our net asset for derivatives not qualifying as hedges during 2002 was
$2.1 million. The change in fair value in 2002 related to continuing operations
was $1.3 million and is recorded in the consolidated statements of operations
under the caption "Change in fair value of derivatives." The remaining change in
2002 related to discontinued operations.
17. 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 two
field offices under leases that expire in 2007 and 2009. 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 51 tractors and 51 trailers.
We pay a fixed monthly rental charge for each tractor and trailer and a fee
based on mileage for the maintenance services. We lease three tanks for use in
our pipeline operations. Beginning in 2005, we are reimbursed for the costs of
the tank lease by a customer, under a reimbursement agreement covering the
period of the tank 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.
The future minimum rental payments under all non-cancelable operating
leases as of December 31, 2004, were as follows (in thousands).
Office Tractors and Service
Space Trailers Tanks Vehicles Total
------- ------------ --------- --------- ---------
2005.......................... $ 441 $ 1,639 $ 479 $ 320 $ 2,879
2006.......................... 49 761 493 88 1,391
2007.......................... 46 732 508 86 1,372
2008.......................... 32 728 - - 760
2009.......................... 23 662 - - 685
2010 and thereafter........... - 672 - - 672
------- ------------ --------- --------- ---------
Total minimum lease
obligations................ $ 591 $ 5,194 $ 1,480 $ 494 $ 7,759
======= ============ ========= ========= =========
Total operating lease expense was as follows (in thousands).
Year ended December 31, 2004................................... $ 3,824
Year ended December 31, 2003................................... $ 4,736
Year ended December 31, 2002................................... $ 4,713
76
We have guaranteed $3.6 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 $13.7 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 the banks under the terms of the New Credit Facility
related to borrowings and letters of credit. Borrowings at December 31, 2004
were $15.3 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.
In general, we expect to incur expenditures in the future to comply with
increasing levels of regulatory safety standards. While the total amount of
increased expenditures cannot be accurately estimated at this time, we
anticipate that we will expend a total of approximately $2.0 million in 2005 and
2006 for testing and improvements under regulations requiring assessment of the
integrity of crude oil pipelines.
Pennzoil Litigation
We were named a defendant in a complaint filed on January 11, 2001, in
the 125th District Court of Harris County, Texas, Cause No. 2001-01176. From
Genesis, 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. The settlement was funded in February 2004, with certain insurance
companies directly funding $5.9 million of the payment and $6.9 million was
funded by us. We received reimbursement of the $6.9 million from the insurance
company on May 3, 2004.
PQS is also a defendant in five consolidated class action/mass tort
actions 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 a third party demand against Genesis and others for indemnity
with respect to the fire and explosion of January 18, 2000. We believe that the
demand against Genesis is without merit and intend to vigorously defend
ourselves in this matter. We currently have no reason to believe that this
matter would have a material financial effect on our financial position, results
of operations, or cash flows.
Environmental
On December 20, 1999, we had a release of crude oil from our Mississippi
System. Approximately 8,000 barrels of oil were released from the pipeline near
Summerland, Mississippi, and entered a creek nearby. A portion of the oil then
flowed into the Leaf River. The clean up of the release 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, 2004 and 2003 is $2.1 million and $2.8 million, respectively,
related to this release. Management of the Partnership reached an agreement with
the US Environmental Protection Agency and the Mississippi Department of
Environmental Quality for the payment of fines of $3.0 million under
environmental laws with respect to this oil spill. The consent order to these
fines was entered on July 27, 2004. In 2001 and 2002, a total accrual of $3.0
million was recorded for these fines, and was paid in the third quarter of 2004.
The fines were not covered by insurance. In addition to the fines, we have other
obligations under the consent order to restore the environment to a condition it
was in prior to the release. Management believes such costs are covered by
insurance and are included in the insurance receivable described above.
In 1992, Howell Crude Oil Company (Howell) entered into a sublease (the
Sublease) with Koch Industries, Inc., (Koch) of land located in Santa Rosa
County, Florida to operate a crude oil trucking station (the Jay Station). The
Sublease provided that Howell would indemnify Koch for environmental
contamination on the property under certain circumstances. Howell operated Jay
Station from 1992 until December of 1996 when this operation was sold to us. We
operated Jay Station as a crude oil trucking station until 2003. Koch has
indicated that they may make a claim against us under the indemnification
provisions of the Sublease for environmental contamination on the site and
surrounding areas.
77
Genesis and Howell, now a subsidiary of Anadarko Petroleum Corporation,
are investigating whether Genesis and/or Howell may have liability for this
contamination, and if so, to what extent. Based upon the early stage of this
investigation, and subject to resolution of the allocation of responsibility
between us and Howell and the method and timing of any required remediation, we
currently have no reason to believe that this matter would have a material
financial effect on our financial position, results of operations, or cash
flows.
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 not 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.
18. SUBSEQUENT EVENTS
Gas Gathering and Marketing Assets
In January 2005, we acquired fourteen natural gas pipeline and gathering
systems located in Texas, Louisiana and Oklahoma from Multifuels Energy Asset
Group, L.P. for $3.1 million. These fourteen systems total 60 miles of pipeline
and related assets. This acquisition was financed through our Credit Agreement.
This acquisition will enable us to complement our existing operations enabling
to provide gas gathering and marketing services in areas where we have existing
operations and relationships with oil and gas producers.
Syngas Investment
On February 3, 2005 we entered into a definitive agreement with TCHI
Inc., a wholly owned subsidiary of ChevronTexaco Global Energy Inc., to purchase
its 50% partnership interest in T & P Syngas Supply Company (T&P Syngas) for
$13.5 million, subject to normal closing conditions. The acquisition is subject
to a right of first refusal held by Praxair Hydrogen Supply, Inc. ("Praxair"),
that must be exercised within 60 days. Praxair holds the other 50% interest in
T&P Syngas. The acquisition, if concluded, will be financed through our Credit
Agreement.
T&P Syngas is a partnership that owns a syngas manufacturing facility
located in Texas City, Texas. The facility processes natural gas to produce
syngas (a combination of carbon monoxide and hydrogen) and high pressure steam.
All of the syngas and steam produced by the facility is sold to Praxair under a
long-term processing agreement.
Distribution
On January 21, 2005, the Board of Directors of the General Partner
declared a cash distribution of $0.15 per Unit for the quarter ended December
31, 2004. This distribution was paid on February 14, 2005 to the General Partner
and all Common Unitholders of record as of the close of business on January 31,
2005.
78
EXHIBIT INDEX
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 June 1, 2004, 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 10.1 to Form 8-K dated
June 1, 2004)
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 (incorporated by reference to Exhibit 10.7 to Form
10-K for the year ended December 31, 2003)
10.8 Carbon Dioxide Transportation Agreement between Denbury
Resources, Inc. and Genesis Crude Oil, L.P. (incorporated by
reference to Exhibit 10.8 to Form 10-K for the year ended
December 31, 2003)
*10.9+ Genesis Energy, Inc. Stock Appreciation Rights Plan
*10.10+ Form of Stock Appreciation Rights Plan Grant Notice
*10.11+ Summary of Director Compensation
*10.12+ Summary of Genesis Energy, Inc. Bonus Plan
10.13 Second Production Payment Purchase and Sale Agreement between
Denbury Onshore, LLC. and Genesis Crude Oil, L.P. executed
August 26, 2004 (incorporated by reference to Exhibit 99.1 to
Form 8-K dated August 26, 2004)
10.14 Second Carbon Dioxide Transportation Agreement between Denbury
Onshore, LLC. and Genesis Crude Oil, L.P. (incorporated by
reference to Exhibit 99.1 to Form 8-K dated August 26, 2004)
79
11.1 Statement Regarding Computation of Per Share Earnings (See
Notes 2 and 8 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.
80