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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the fiscal year ended December 31, 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.
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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
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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.
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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