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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, 2005

[ ] 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 if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Exchange Act of 1934.

Yes [ ] No [X]

Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act.

Yes [ ] No [X]

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Act during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past 90 days.

Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.

[X]

Indicate by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or an non-accelerated filer. See definition of "accelerated
filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.

Large accelerated filer [ ] Accelerated filer [X] Non-accelerated filer [ ]

Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2) of the Act).

Yes [ ] No [X]

The aggregate market value of the common units held by non-affiliates of the
Registrant on June 30, 2005 (the last business day of Registrant's most recently
completed second fiscal quarter), was approximately $80,372,000 based on $9.39
per unit, the closing price of the common units as reported on the American
Stock Exchange and the number of units outstanding on such date. At March 1,
2006, 13,784,441 common units were outstanding.

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GENESIS ENERGY, L.P.
2005 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS

Page
----

PART I

Items 1. Business and Properties................................................................................ 4
and 2
Item 1A. Risk Factors........................................................................................... 18
Item 1B. Unresolved Staff Comments.............................................................................. 29
Item 3. Legal Proceedings...................................................................................... 29
Item 4. Submission of Matters to a Vote of Security Holders.................................................... 30

PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities............................................................................................. 30
Item 6. Selected Financial Data................................................................................ 31
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.................. 33
Item 7A. Quantitative and Qualitative Disclosures about Market Risk............................................. 52
Item 8. Financial Statements and Supplementary Data............................................................ 53
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure................... 53
Item 9A. Controls and Procedures................................................................................ 53
Item 9B. Other Information...................................................................................... 55

PART III

Item 10. Directors and Executive Officers of the Registrant..................................................... 55
Item 11. Executive Compensation................................................................................. 57
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters......... 60
Item 13. Certain Relationships and Related Transactions......................................................... 61
Item 14. Principal Accountant Fees and Services................................................................. 62

PART IV

Item 15. Exhibits and Financial Statement Schedules............................................................. 63

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 forward-looking statements are identified as
any statement that does not relate strictly to historical or current facts. They
use words such as "anticipate," "believe," "continue," "estimate," "expect,"
"forecast," "intend," "may," "plan," "position," "projection," "strategy" or
"will" or the negative of those terms or other variations of them or by
comparable terminology. In particular, statements, expressed or implied,
concerning future actions, conditions or events or future operating results or
the ability to generate sales, income or cash flow are forward-looking
statements. 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 or the ability of our affiliates
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 or "NGLs" 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 liquids transportation systems, natural
gas transportation systems or natural gas gathering and processing
operations;

- shut-downs or cutbacks at refineries, petrochemical plants,
utilities or other businesses for which we transport crude oil,
natural gas or other products or to whom we sell such products;

- 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 financial
covenants;

- loss of key personnel;

- the effects of competition, in particular, by other pipeline
systems;

- hazards and operating risks that may not be covered fully by
insurance;

- the condition of the capital markets in the United States;

- loss of key customers;

- 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 1A. Except as required by applicable
securities laws, we do not intend to update these forward-looking statements and
information.

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

GENERAL

We are a growth-oriented midstream energy partnership that was
formed in 1996 as a master limited partnership, or MLP. We have a diverse
portfolio of customers and assets, including pipeline transportation of
primarily crude oil and, to a lesser extent, natural gas and carbon dioxide
(CO(2)) in the Gulf Coast region of the United Sates. In conjunction with our
crude oil pipeline transportation operations, we operate a crude oil gathering
and marketing business, which (among other things) helps ensure a base supply of
crude oil for our pipelines. We participate in industrial gas activities,
including a CO 2 supply business, which is associated with the CO 2 tertiary
oil recovery process being used in Mississippi by an affiliate of our general
partner. During 2005 we also acquired a 50% interest in a joint venture that
processes natural gas to produce syngas and high-pressure steam. We attempt to
minimize our exposure to changes in the prices of energy commodities by
structuring our compensation arrangements for each service we provide in a
manner that is not directly linked to commodity prices.

We conduct our business through three primary segments:

Pipeline Transportation -- Our core business is the transportation
of crude oil for others for a fee. The rates on substantially all of our
pipelines are regulated by the Federal Energy Regulatory Commission, also known
as FERC, or the Railroad Commission of Texas. Our 230-mile Mississippi System
provides shippers of crude oil in Mississippi indirect access to refineries,
pipelines, storage, terminalling and other crude oil infrastructure located in
the Midwest. Our 90-mile Texas System extends from West Columbia to Webster,
Webster to Texas City and Webster to Houston. Our 100-mile Jay System originates
in eastern Alabama and the panhandle of Florida and extends to a point near
Mobile, Alabama. On a much smaller scale, we also transport CO(2) and natural
gas for a fee.

Crude Oil Gathering and Marketing -- We conduct certain crude oil
aggregating operations, which involve purchasing, gathering and transporting by
trucks and pipelines operated by us and trucks, pipelines and barges operated by
others, and reselling, that (among other things) help ensure a base supply
source for our crude oil pipeline systems. Our profit for those services is
derived from the difference between the price at which we re-sell crude oil less
the price at which we purchase that crude oil, minus the associated costs of
aggregation and any cost of supplying credit. The most substantial component of
our aggregating costs relates to operating our fleet of leased trucks. Our crude
oil gathering and marketing activities provide us with an extensive expertise,
knowledge base and skill set that facilitate our ability to capitalize on
regional opportunities which arise from time to time in our market areas.
Usually, this segment experiences limited commodity price risk because we
generally make back-to-back purchases and sales, matching our sale and purchase
volumes on a monthly basis.

Industrial Gases.

- CO(2) -- We supply CO(2) to industrial customers under seven
long-term contracts, with an average remaining contract life of 10
years. We acquired those contracts, as well as the CO(2) necessary
to satisfy substantially all of the obligations under those
contracts, in three separate transactions with affiliates of our
general partner. Our compensation for supplying CO(2) to our
industrial customers is the effective difference between the price
at which we sell our CO(2) under each contract and the price at
which we acquired our CO(2) pursuant to our volumetric production
payments (also known as VPPs), minus transportation costs. We expect
our CO(2) contracts to provide stable cash flows until they expire,
at which time we will attempt to extend or replace those contracts.

- Syngas -- Through our 50% interest in a joint venture, we receive a
proportionate share of fees under a processing agreement covering a
facility that manufactures syngas and high-pressure steam. Under
that processing agreement, Praxair provides the raw materials to be
processed and receives the syngas and steam produced by the
facility. Praxair has the exclusive right to use the facility
through at least 2016 (term extendable at Praxair's option for two
additional five year terms). Praxair also is our partner in the
joint venture and owns the remaining 50% interest.

We conduct our operations through subsidiaries and joint ventures.
Our general partner is responsible for operating our business, including
providing all necessary personnel and other resources.

OUR GENERAL PARTNER AND OUR RELATIONSHIP WITH DENBURY RESOURCES INC.

We continue to benefit from our affiliation with Denbury Resources
Inc. (NYSE: DNR), which indirectly owns our general partner and a 9.25%
ownership interest in us. Denbury is a publicly traded oil and gas exploration
and production company with operations located primarily in Mississippi,
Louisiana and Texas. As a result of its emphasis on the tertiary recovery of
crude oil using CO(2) flooding, Denbury has become the largest producer (based
on average barrels produced per day) of crude oil in the State of Mississippi,
and owns approximately 4.6 trillion cubic feet of proved CO(2) reserves as of
December 31, 2005.

In addition to its ownership interests in us, we have other
significant commercial arrangements with Denbury. Denbury (including its
subsidiaries) is:

- the only shipper (other than us) on our Mississippi System,
utilizing more than 85% of the current daily throughput;

- the company that sold us seven long-term CO(2) sales contracts with
industrial customers, along with the CO(2) necessary to satisfy
substantially all of our obligations under those contracts (280.0
billion cubic feet (Bcf) of CO(2) under three separate VPPs);

- the operator of the fields in which our CO(2) reserves are located;
and

- the sole shipper on our CO(2) pipeline.

Denbury is a uniquely situated energy company. It is one of only a
handful of producers in the U.S. that possess extensive CO(2) tertiary recovery
expertise, as well as large quantities of low-cost CO(2) reserves. Denbury is
conducting the largest CO(2) tertiary recovery operations in the Eastern Gulf
Coast of the U.S., an area with many mature oil reservoirs that potentially
contain substantial volumes of recoverable crude oil. We believe our
relationship with Denbury, as well as the geographic proximity of our operations
to Denbury's, provides us opportunities to realize additional crude oil
transportation.

OUR OBJECTIVE AND STRATEGY

- Maximizing organic growth opportunities through construction and
expansion opportunities, particularly on our Mississippi System.

- Increasing volumes on our existing assets, particularly on our
Mississippi System.

- Leveraging our CO(2) expertise, along with our relationship with
Denbury, to create new opportunities with Denbury and third parties.

- Pursuing accretive acquisitions.

- Prudently and economically leveraging our asset base, knowledge base
and skill sets to participate in businesses closely related to, or
significantly intertwined with, our existing businesses, including
our industrial gas activities.

- Capitalizing on the regional crude oil supply and demand imbalances
that exist in our market areas through our marketing and
distribution expertise.

- Emphasizing services for which the compensation is not linked to
commodity prices (like gathering and transportation) and managing
commodity risks by using contractual arrangements.

- Maintaining a balanced and diversified portfolio of midstream energy
interests and assets.

- Maintaining a sound capital structure.

- Sharing capital costs and risks through joint ventures and strategic
alliances.

OUR KEY STRENGTHS

Based on the following competitive strengths, we believe we are well
positioned to execute our objective and strategy:

- Quality Asset Base. We have a quality asset base characterized by:

- Strategic Locations. Our Mississippi System is adjacent to
several oil fields operated by Denbury, which is the sole
shipper (other than us) on our Mississippi System. To our
knowledge, our Jay System is the only system serving the
Florida panhandle and southwest Alabama.

- Additional Throughput Capacity. All of our systems have
additional throughput capacity which allows us to transport
additional volumes at minimal additional cost to us.

- Cash Flow Stability. Our relatively low exposure to commodity
price fluctuations, diversified asset base and long-term
contracts associated with our industrial gases operations
provide us with a stable source of cash flows.

- A Unique Platform in Industrial Gases. We believe we have the
potential to expand our CO(2) business and leverage that expertise,
along with our relationship with Denbury, to create a unique growth
platform in industrial gases, an area not currently as competitive
as other midstream industry activities.

- Strong Relationship with Denbury. We have a strong relationship with
Denbury, which is the indirect owner of our general partner and the
largest exploration and production company (based on average barrels
produced per day) currently operating in Mississippi. Denbury is the
sole shipper (other than us) on our Mississippi System, and its
extensive CO(2) reserves and operations provided us the opportunity
to enter the industrial gases business.

- Financial Flexibility and Strong Distribution Coverage. We have the
financial flexibility to pursue growth projects. As of December 31,
2005, we had no long-term debt outstanding and we had up to $65
million of borrowing capacity under our credit facility, subject to
certain limitations.

- Insulation from Commodity Price Risks. Many of our contractual
arrangements help insulate our operating cash flows from changes in
energy commodity prices. Our compensation arrangements include
fee-based arrangements, back-to-back purchases and sales, and
tolling-type arrangements, which in general do not vary with changes
in the price of the underlying commodity. We also use hedges from
time to time to mitigate the impact of fluctuations in energy
commodity prices on our segment margins.

- Balanced and Diversified Operations. We have a balanced portfolio of
customers and assets and a proven track record of cash flow
diversification. Our operations include the pipeline transportation
of crude oil and, to a lesser extent, CO(2) and natural gas in the
Gulf Coast; crude oil gathering and marketing primarily around our
Gulf Coast crude oil pipelines; and industrial gas activities.

RECENT DEVELOPMENTS

Acquisition of CO(2) Assets

On October 11, 2005, we acquired two long-term CO(2) sales
contracts with industrial customers, along with the 80.0 Bcf of CO(2) in the
form of VPPs necessary to satisfy substantially all of our expected obligations
under those contracts, from Denbury for $14.4 million in cash. We funded this
acquisition with borrowings under our credit facility. This acquisition further
diversified our asset base and provides a stable, long-term source of cash flow
to us. Since 2003, we have acquired seven long-term CO(2) sales contracts, along
with three VPPs representing in the aggregate 280.0 Bcf of CO(2), from Denbury
for a total of $43.1 million in cash.

Distribution Increases

On November 14, 2005, we paid a cash distribution of $0.16 per unit
for the quarter ended September 30, 2005. This distribution represented a 6.7%
increase from our distribution of $0.15 per unit for the second quarter of 2005.
We increased our distribution again for the quarter ended December 31, 2005,
with a payment of $0.17 per unit on February 14, 2006.

Acquisition of Syngas Joint Venture

On April 1, 2005, we acquired from TCHI Inc., a wholly-owned
subsidiary of ChevronTexaco Global Energy Inc., a 50% partnership interest in
T&P Syngas Supply Company for $13.4 million in cash, which we funded with
borrowings under our credit facility. T&P Syngas is a partnership which owns a
facility located in Texas City, Texas that manufactures syngas and high-pressure
steam. We receive a proportionate share of fees under a long-term processing
agreement between the joint venture and its sole customer, Praxair Hydrogen
Supply, Inc. Under this processing agreement, the joint venture receives a
processing fee in exchange for manufacturing syngas and steam from raw materials
supplied by Praxair. Praxair has the exclusive right to use the facility through
at least 2016. We expect our investment in T&P Syngas to provide another source
of stable, long-term cash flow and additional balance to our business.

Acquisition of Natural Gas Pipeline

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 in cash, which we funded with
borrowings under our credit facility. These fourteen systems are comprised of 60
miles of pipeline and related assets.

Pipeline Integrity Management Program

We completed our 2005 objectives relating to the Department of
Transportation's Pipeline Integrity Management Program, or IMP, which increased
our operating costs and capital expenditures by $0.3 million and $2.8 million,
respectively, in 2004 and 2005. The IMP regulations required that a baseline
assessment be completed by March 31, 2009, with 50% of the mileage assessed by
September 30, 2005.

DESCRIPTION OF SEGMENTS AND RELATED ASSETS

Pipeline Transportation

Our core business is the transportation of crude oil for others for
a fee. 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
Railroad Commission of Texas. 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, we deduct volumetric pipeline
loss allowances and crude quality deductions. Such allowances and deductions are
offset by measurement gains and losses. When the allowances and deductions
exceed measurement losses, the net pipeline loss allowance volumes are earned
and recognized as income and inventory available for sale valued at the market
price for the crude oil.

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.
Our 230-mile Mississippi System provides shippers of crude oil in Mississippi
indirect access to refineries, pipelines, storage, terminalling and other crude
oil infrastructure located in the Midwest. Our 100-mile Jay System originates in
eastern Alabama and the panhandle of Florida and extends to a point near Mobile,
Alabama. Our 90-mile Texas System extends from West Columbia to Webster, Webster
to Texas City and Webster to Houston. On a much smaller scale, we also transport
CO(2) and natural gas for a fee.

Mississippi System. Our Mississippi System extends from Soso,
Mississippi to Liberty, Mississippi. Our Mississippi System includes tankage at
various locations with an aggregate storage capacity of 200,000 barrels. That
System is adjacent to several oil fields operated by Denbury, which is the sole
shipper (other than us) on our Mississippi System. As a result of its emphasis
on the tertiary recovery of crude oil using CO(2) flooding, Denbury has become
the largest producer (based on average barrels produced per day) of crude oil in
the State of Mississippi. As Denbury continues its tertiary recovery activities
and increases its production, we expect increased demand for our crude oil
transportation services.

We restructured some of our crude oil gathering, marketing and
transportation arrangements with Denbury in 2004 to provide for a fee-based
arrangement with Denbury under which we transport its crude oil on our regulated
pipelines in our Pipeline Transportation Segment. We effected that restructuring
by implementing an "incentive" tariff. Under our incentive tariff, the average
rate per barrel that we charge during any month decreases as our aggregate
throughput for that month increases above specified thresholds. Prior to this
restructuring, we handled most of our Mississippi arrangements with Denbury
using purchases and sales through our Crude Oil Gathering and Marketing Segment,
in which we purchased crude oil from others (including Denbury) and gather,
transport and re-sell that crude in the market. The new tariff arrangement
improved our rate of return and reduced our exposure to commodity prices.

Over the last several years, we have initiated and completed several
projects that increased the capacity of our Mississippi System. We added tankage
and other equipment. During 2004, we constructed a 10-mile, 10-inch CO(2)
pipeline that is connected to Denbury's 183 mile pipeline that transports CO(2)
from their Jackson Dome CO(2) reservoir. Our pipeline will move the CO(2) to the
Brookhaven oil field to be used by Denbury in tertiary recovery. We entered into
a contract granting Denbury the exclusive right to use that CO(2) pipeline
through 2012 in exchange for a monthly demand and commodity charge. We
constructed an 11-mile, 8-inch extension to our Mississippi oil pipeline next to
the CO(2) 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. We
undertook those projects in response to increasing crude oil production in the
area. We expect those production rates to continue to increase primarily as a
result of the broad-based CO(2) tertiary recovery projects that Denbury is
currently undertaking and has announced it will undertake in the future. We
intend to develop other organic growth opportunities related to our Mississippi
System.

Jay System. Our Jay system begins near oil fields in southeastern
Alabama and the panhandle of Florida and extends to a point near Mobile,
Alabama. Our Jay system includes tankage with 230,000 barrels of storage
capacity, primarily at Jay station. New production in the area surrounding our
Jay System has helped to offset the rapidly declining production curves of the
more mature producing wells in the area. We do not know if the production from
new wells will be sufficient to offset declining production from existing wells
in the area.

Should the production surrounding our Jay System decline such that
it becomes uneconomic to continue to operate that pipeline for crude oil
service, we believe that the best use of the Jay System may be to convert it to
natural gas service. We continue to review opportunities to effect such a
conversion. Part of the conversion 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 2006 or 2007.

Texas System. The active segments of the Texas System extend from
West Columbia to Webster, Webster to Texas City and Webster to Houston. These
segments include approximately 90 miles of pipe. The Texas System receives all
of its volume from connections to other pipeline carriers. We charge a tariff
rate for our transportation services, with the tariff rate per barrel of crude
oil varying with the distance from injection point to delivery point. We entered
into a joint tariff with TEPPCO Crude Pipeline, L.P. (TEPPCO) to receive oil
from their system at West Columbia and a joint tariff with TEPPCO and ExxonMobil
Pipeline Company 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 tankage with approximately 110,000 barrels of storage capacity associated
with the Texas System. We lease an additional approximately 165,000 barrels of
storage capacity for our Texas System in Webster. We have a tank rental
reimbursement agreement effective January 1, 2005 with the primary shipper on
our Texas System to reimburse us for the lease of this storage capacity at
Webster.

In 2003, we sold portions of our Texas System to TEPPCO and to
Blackhawk Pipeline, L.P., 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.

Natural Gas Pipeline. In January 2005, we acquired 14 natural gas
pipeline and gathering systems located in Texas, Louisiana and Oklahoma from
Multifuels Energy Asset Group, L.P. These 14 systems are comprised of 60 miles
of pipeline and related assets.

Customers and Credit

Denbury, a large, creditworthy company, is the sole shipper (other
than us) on our Mississippi System. The customers on our Jay and Texas Systems
are primarily large, creditworthy energy companies. Revenues from customers of
this segment did not account for more than ten percent of our consolidated
revenues.

We manage our exposure to credit risk through credit analysis,
credit approval and monitoring procedures.

Competition

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.

Industrial Gases

Our industrial gases segment is a natural outgrowth from our core
business. Because of the substantial CO(2) flooding tertiary recovery operations
being utilized around our Mississippi System, we became familiar with
CO(2)-related activities and, ultimately, began our CO(2) business in 2003. Our
relationships with industrial customers who use CO(2) have expanded, which has
introduced us to potential opportunities associated with other industrial gases,
such as syngas (also known as synthetic gas), which is a combination of carbon
monoxide and hydrogen.

CO(2)

We supply CO(2) to industrial customers under seven long-term CO(2)
sales contracts. We acquired those contracts, as well as the CO(2) necessary to
satisfy substantially all of our expected obligations under those contracts, in
three separate transactions with Denbury. Since 2003, we have purchased those
contracts, along with three VPPs representing 280.0 Bcf of CO(2) (in the
aggregate), from Denbury for a total of $43.1 million in cash. We sell our CO(2)
to customers who treat the CO(2) and sell it to end users for use for beverage
carbonation and food chilling and freezing. Our compensation for supplying CO(2)
to our industrial customers is the effective difference between the price at
which we sell our CO(2) under each contract and the price at which we acquired
our CO(2) pursuant to our VPPs, minus transportation costs. We expect our CO(2)
contracts to provide stable cash flows until they expire, at which time we will
attempt to extend or replace those contracts, including acquiring the necessary
CO(2) supply from wholesalers. At December 31, 2005, we have 237.1 Bcf of CO(2)
remaining under the VPPs.

Currently, all of our CO(2) supply is from naturally occurring
sources - our VPPs. We believe we have an adequate supply to service existing
contracts through their terms. When our VPPs expire, we will have to obtain our
CO(2) supply from Denbury, from other sources, or discontinue the CO(2) supply
business. Denbury will have no obligation to provide us with CO(2), and has the
right to compete with us. See "Risks Related to Our Partnership Structure" for a
discussion of the potential conflicts of interest between Denbury and us.

Syngas

On April 1, 2005, we acquired from TCHI, Inc., a wholly-owned
subsidiary of ChevronTexaco Global Energy, Inc., a 50% partnership interest in
T&P Syngas for $13.4 million in cash, which we funded with proceeds from our
credit facility. T&P Syngas is a partnership which owns a facility located in
Texas City, Texas that manufactures syngas and high-pressure steam. Under a
long-term processing agreement, the joint venture receives fees from its sole
customer, Praxair Hydrogen Supply, Inc. during periods when processing occurs,
and Praxair has the exclusive right to use the facility through at least 2016
(term extendable at Praxair's options for two additional five year terms).
Praxair also is our partner in the joint venture and owns the remaining 50%
interest.

Customers and Credit

Five of the seven contracts for supplying CO(2) are with large
companies with good credit ratings. The remaining contracts are with smaller
companies with long histories in the CO(2) business. We do not expect to
experience any credit related issues with these customers, however we monitor
their credit standings on an ongoing basis. Revenues from this segment did not
account for more than ten percent of our consolidated revenues.

The sole customer of T&P Syngas is Praxair. We believe that Praxair
is a creditworthy customer.

Competition

Currently, all of our CO(2) supply is from naturally occurring
sources - our VPPs. We believe we have an adequate supply to service existing
contracts through their terms. In the future we will likely have to obtain our
CO(2) supply from manufactured processes. Naturally-occurring CO(2), 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. Our
industrial CO(2) customers have facilities that are connected to Denbury's CO(2)
pipeline to make delivery easy and efficient. Once our existing VPPs expire, we
will have to obtain CO(2) from Denbury or other suppliers should we choose to
remain in the CO(2) business, and the competition and pricing issues we will
face at that time are uncertain.

With regard to sales of CO(2), our contracts have take-or-pay
provisions requiring minimum volumes each year for each customer that must be
paid for even if the CO(2) is not taken. We will have to replace these contracts
once they expire should we choose to remain in the CO(2) business, and our
ability to retain or replace these customers at that time is uncertain.

Due to the long-term contract and location of our syngas facility,
as well as the costs involved in establishing a competing facility, we believe
it is unlikely that competing facilities will be established for our syngas
processing services.

Crude Oil Gathering and Marketing

Our crude oil gathering and marketing operations are concentrated in
Texas, Louisiana, Alabama, Florida and Mississippi. These operations, which
involve purchasing, gathering and transporting by trucks and pipelines operated
by us and trucks, pipelines and barges operated by others, and reselling, help
to ensure (among other things) a base supply source for our crude oil pipeline
systems. Our profit for those services is derived from the difference between
the price at which we re-sell the crude oil less the price at which we purchase
that crude oil, minus the associated costs of aggregation and any cost of
supplying credit. The most substantial component of our aggregating costs
relates to operating our fleet of leased trucks. Usually, this segment
experiences limited commodity price risk because we generally make back-to-back
purchases and sales, matching our sale and purchase volumes on a monthly basis.

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.

Usually, fluctuations in the market price of crude oil do not
materially impact us. 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 if we do not
have effective hedges in place.

As of December 31, 2005, we provided crude oil gathering services
through our fleet of 48 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. We also transport purchased crude
oil on trucks, barges and pipelines operated by third parties.

Producer Services

Crude oil purchasers who buy from producers compete on the basis of
competitive prices and quality of services. 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.

Customers and Credit

Due to the nature of our crude oil operations, a disproportionate
percentage of our trade receivables constitute obligations of oil companies.
This industry concentration has the potential to impact our overall exposure to
credit risk, either positively or negatively, in that our customers could be
affected by similar changes in economic, industry or other conditions. However,
we believe that the credit risk posed by this industry concentration is offset
by the creditworthiness of our customer base. Our portfolio of accounts
receivable is comprised in large part of integrated and large independent energy
companies with stable payment experience. The credit risk related to contracts
which are traded on the NYMEX is limited due to the daily cash settlement
procedures and other NYMEX requirements.

When we market crude oil, we must determine the amount, if any, of
the line of credit we will extend to any given customer. We have established
various procedures to manage our credit exposure, including initial credit
approvals, credit limits, collateral requirements and rights of offset. Letters
of credit, prepayments and guarantees are also utilized to limit credit risk to
ensure that our established credit criteria are met.

Our customers are primarily large creditworthy energy companies.
During 2005, more than ten percent of our consolidated revenues were generated
from sales of crude oil to each of two customers, Occidental Energy Marketing,
Inc. (26.5%) and Shell Oil Company (12.5%). 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. Generally sales of crude oil settle within 30
days of the month of the delivery.

Our credit standing is an important consideration for parties with
whom we do business in this segment. In order to assure our ability to perform
our obligations under crude oil purchase agreements, various credit arrangements
are negotiated with suppliers. These arrangements include open lines of credit
directly with us, guarantees or letters of credit.

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 have considerable flexibility
in marketing the volumes of crude oil that we purchase, without dependence on
any single customer or transportation or storage facility.

Our largest competitors in the purchase of leasehold crude oil
production are Plains Marketing, L.P., Shell (US) 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, we
agreed not to compete in a 40 county area for five years from the effective date
of the transaction of October 31, 2003.

EMPLOYEES

To carry out various purchasing, gathering, transporting and
marketing activities, our general partner employed, at December 31, 2005,
approximately 185 employees. None of the employees are represented by labor
unions, and we believe that relationships with our employees are good.

ORGANIZATIONAL STRUCTURE

Genesis Energy, Inc., a Delaware corporation, serves as our sole
general partner and as the general partner of our operating partnership, Genesis
Crude Oil, L.P., and its subsidiary partnerships - Genesis Pipeline Texas, L.P.,
Genesis Pipeline USA, L.P., Genesis CO(2) Pipeline, L.P., Genesis Natural Gas
Pipeline, L.P. and Genesis Syngas Investments, L.P. Our general partner is owned
by Denbury Gathering & Marketing, Inc., a subsidiary of Denbury Resources Inc.
Below is a chart depicting our ownership structure.

<Table>

-----------------------------------------
| |
| |
| Denbury Resources Inc. |
| (and subsidiaries) |
| |
| |
-----------------------------------------
|
|
| 100%
|
|
-----------------------------------------
| |
| |
-----------------| Genesis Energy, Inc. |
| | (our general partner)(1) |
| | |
| | |
| -----------------------------------------
| |
| | 2.0% general partner interest --------
| | 7.25% limited partner interest ( Public )
| | / --------
| | ----
| | /
| ----------------------------------------- ----
| | | / 90.75% limited partner interest
| | | /
| | Genesis Energy, L.P. |---
| | |
| | |
| | |
| -----------------------------------------
| |
| |
| | 99.99% limited partner interest
| |
| |
| -----------------------------------------
| 0.01% | |
| general | |
| partner | Genesis Crude Oil, L.P. |
| interest | Genesis Pipeline Texas, L.P. |
| | Genesis Pipeline USA, L.P. |
-----------------| Genesis CO Pipeline, L.P. |
| 2 |
| Genesis Natural Gas Pipeline, L.P. |
| Genesis Syngas Investments, L.P. |
| |
| |
-----------------------------------------
|
|
SEGMENTS
|
|
----------------------------------------------|----------------------------------------------
| | |
| | |
- ----------------------------------------- ----------------------------------------- -----------------------------------------
| Pipeline Transportation | | Crude Oil Gathering and Marketing | | Industrial Gases |
| | | | | |
| Crude Oil | | Marketing (back-to-back) | | CO |
| Natural Gas | | Trucking/Gathering | | 2 |
| CO | | Blending | | Syngas |
| 2 | | Storing | | |
- ----------------------------------------- ----------------------------------------- -----------------------------------------
</Table>

- ----------
(1) Our general partner owns all of our incentive distribution rights.

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 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 2005 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 were also 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.

In addition to the index methodology, FERC allows for rate changes
under three other methods -- a cost-of-service methodology, competitive market
showings ("Market-Based Rates"), or agreements between shippers and the oil
pipeline company that the rate is acceptable ("Settlement Rates"). The pipeline
tariff rates on our Mississippi and Jay Systems are either rates that were
grandfathered and have been changed under the index methodology, or Settlement
Rates. None of our tariffs have been subjected to a protest or complaint by any
shipper or other interested party.

Our intrastate common carrier pipeline operations in Texas are
subject to regulation by the Railroad Commission of Texas. 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. 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.

Our natural gas gathering pipelines and CO(2) pipeline are subject
to regulation by the state agencies in the states in which they are located.

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 the imposition of injunctive obligations. Changes in
environmental laws and regulations occur

frequently, and any changes that result in more stringent and costly operating
restrictions, emission control, waste handling, disposal, cleanup, and other
environmental 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, including current owners
and operators of a contaminated facility, owners and operators of the facility
at the time of contamination, and those parties arranging for waste disposal at
a contaminated facility. 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.

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. We also may generate, handle
and dispose of regulated materials in the course of our operations. We may
therefore be subject to 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 administrative, civil and criminal
penalties for any unauthorized discharges of pollutants, including oil, and
imposes liabilities for the costs of remediating spills. 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. 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 laws and 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.

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 clean-up activity expected to continue
for an undetermined period of time. The oil spill clean up and related costs
have thus far been covered by insurance and the financial impact to us for the
cost of the clean-up has not been material. We expect our insurance carrier to
continue paying for remedial costs and we do not expect future costs to us to be
material. During 2004, we finalized agreements with the United States
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 not covered by insurance and was recorded to
expense in 2001 and 2002.

The Clean Air Act, as amended, and analogous state and local laws
and regulations restrict the emission of air pollutants including volatile
organic compounds or "VOCs", impose permit requirements and other obligations.
VOC emissions may occur from the handling or storage of crude oil and other
petroleum products. Both federal and state laws impose substantial penalties for
violation of these applicable requirements.

Under the National Environmental Policy Act (NEPA), a federal
agency, commonly in conjunction with a current permittee or applicant, may be
required to prepare an environmental assessment or a detailed environmental
impact statement before taking any major action, including issuing a permit for
a pipeline extension or addition that

would affect the quality of the environment. Should an environmental impact
statement or assessment be required for any proposed pipeline extensions or
additions, the primary effect of NEPA may prevent construction or alter the
proposed location, design or method of construction.

We are currently conducting remediation of subsurface hydrocarbon
contamination at the former Jay Trucking Facility. The estimated remediation and
related costs are $1.3 million, which we expect to share with other responsible
parties. In 2005, we recorded our expected share of these costs in our statement
of operations. See Note 18 to the Consolidated Financial Statements.

Safety and Security Regulations

Our crude oil, natural gas and CO(2) 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 Pipeline and Hazardous Materials Safety Administration 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 2005 mandates the establishment by DOT of pipeline operator
qualification rules requiring minimum training requirements for operators, the
development of standards and criteria to evaluate contractors' 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
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 by March 31, 2009, with 50% of
the mileage assessed by September 30, 2005. 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 us that may not be fully recoverable by tariff
increases. At December 31, 2005, we had completed assessments and repairs on the
major sections of our pipelines.

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 responsible for enforcing the federal regulations and
more stringent state pipeline regulations and inspection with respect to
hazardous liquids pipelines, including crude oil and CO(2) pipelines, and
natural gas pipelines that do not engage in interstate operations. 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 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 our expenditures in the future to comply with
higher industry and regulatory safety standards such as those described above to
increase over historical levels. While the total amount of increased
expenditures cannot be accurately estimated at this time, we anticipate that we
will spend a total of approximately $0.2 million in 2006 and 2007 for testing
and improvements under the IMP. After 2007, we expect our expenditures for IMP
testing and improvements to average from $1.0 to $1.5 million per year.

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 (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.

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.

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 as soon as reasonably practicable after we electronically file the material
with, or furnish it to, the SEC.

ITEM 1A. RISK FACTORS

RISKS RELATED TO OUR BUSINESS

We may not have sufficient cash from operations to pay the current
level of quarterly distribution following the establishment of cash reserves and
payment of fees and expenses, including payments to our general partner.

The amount of cash we distribute on our units principally depends
upon margins we generate from our crude oil gathering and marketing operations,
margins from the pipeline transportation operations and sales of CO(2), which
will fluctuate from quarter to quarter based on, among other things:

- the prices at which we purchase and sell crude oil;

- the volumes of crude oil we transport;

- the volumes of CO(2) we sell;

- the level of our operating costs;

- the level of our general and administrative costs; and

- prevailing economic conditions.

In addition, the actual amount of cash we will have available for
distribution will depend on other factors that include:

- the level of capital expenditures we make, including the cost
of acquisitions (if any);

- our debt service requirements;

- fluctuations in our working capital;

- restrictions on distributions contained in our debt
instruments;

- our ability to borrow under our working capital facility to
pay distributions; and

- the amount of cash reserves established by our general partner
in its sole discretion in the conduct of our business.

You should also be aware that our ability to pay distributions each
quarter depends primarily on our cash flow, including cash flow from financial
reserves and working capital borrowings, and is not solely a function of
profitability, which will be affected by non-cash items. As a result, we may
make cash distributions during periods when we record losses and we may not make
distributions during periods when we record net income.

Our profitability and cash flow is dependent on our ability to
increase or, at a minimum, maintain our current commodity -- oil, natural gas
and CO(2) -- volumes, which often depends on actions and commitments by parties
beyond our control.

Our profitability and cash flow is dependent on our ability to
increase or, at a minimum, maintain our current commodity--oil, natural gas and
CO(2)--volumes. We access commodity volumes through two sources, producers and
service providers (including gatherers, shippers, marketers and other
aggregators). Depending on the needs of each customer and the market in which it
operates, we can either provide a service for a fee (as in the case of our
pipeline transportation operations) or we can purchase the commodity from our
customer and resell it to another party (as in the case of oil marketing and
CO(2) operations).

Our source of volumes depends on successful exploration and
development of additional oil and natural gas reserves by others and other
matters beyond our control.

The oil, natural gas and other products available to us are derived
from reserves produced from existing wells, which reserves naturally decline
over time. In order to offset this natural decline, our energy infrastructure
assets must access additional reserves. Additionally, some of the projects we
have planned or recently completed are dependent on reserves that we expect to
be produced from newly discovered properties that producers are currently
developing.

Finding and developing new reserves is very expensive, requiring
large capital expenditures by producers for exploration and development
drilling, installing production facilities and constructing pipeline extensions
to reach new wells. Many economic and business factors out of our control can
adversely affect the decision by any producer to explore for and develop new
reserves. These factors include the prevailing market price of the commodity,
the capital budgets of producers, the depletion rate of existing reservoirs, the
success of new wells drilled, environmental concerns, regulatory initiatives,
cost and availability of equipment, capital budget limitations or the lack of
available capital, and other matters beyond our control. Additional reserves, if
discovered, may not be developed in the near future or at all. We cannot assure
you that production will rise to sufficient levels to allow us to maintain or
increase the commodity volumes we are experiencing.

We face intense competition to obtain commodity volumes.

Our competitors--gatherers, transporters, marketers, brokers and
other aggregators--include independents and major integrated energy companies,
as well as their marketing affiliates, who vary widely in size, financial
resources and experience. Some of these competitors have capital resources many
times greater than ours and control substantially greater supplies of crude oil.

Even if reserves exist in the areas accessed by our facilities and
are ultimately produced, we may not be chosen by the producers to gather,
transport, store or otherwise handle any of these reserves. We compete with
others for any such volumes on the basis of many factors, including:

- geographic proximity to the production;

- costs of connection;

- available capacity;

- rates; and

- access to markets.

Additionally, third-party shippers do not have long-term contractual
commitments to ship crude oil on our pipelines. A decision by a shipper to
substantially reduce or cease to ship volumes of crude oil on our pipelines
could cause a significant decline in our revenues. In Mississippi, we are
dependent on interconnections with other pipelines to provide shippers with a
market for their crude oil, and in Texas, we are dependent on interconnections
with other pipelines to provide shippers with transportation to our pipeline.
Any reduction of throughput available to our shippers on these interconnecting
pipelines as a result of testing, pipeline repair, reduced operating pressures
or other causes could result in reduced throughput on our pipelines that would
adversely affect our cash flows and results of operations.

Fluctuations in demand for crude oil, such as those caused by
refinery downtime or shutdowns, can negatively affect our operating results.
Reduced demand in areas we service with our pipelines can result in less demand
for our transportation services. In addition, certain of our field and pipeline
operating costs and expenses are fixed and do not vary with the volumes we
gather and transport. These costs and expenses may not decrease ratably or at
all should we experience a reduction in our volumes gathered by truck or
transmitted by our pipelines. As a result, we may experience declines in our
margin and profitability if our volumes decrease.

Fluctuations in commodity prices could adversely affect our
business.

Oil, natural gas, other petroleum product and CO(2) prices are
volatile and could have an adverse effect on a portion of our profits and cash
flow. Our operations are affected by price reductions. Price reductions can
materially reduce the level of exploration, production and development
operations, as well as pipeline and marketing volumes.

Prices for commodities can fluctuate in response to changes in
supply, market uncertainty and a variety of additional factors that are beyond
our control.

Our operations are dependent upon demand for crude oil by refiners
in the Midwest and on the Gulf Coast.

Any decrease in this demand for crude oil by the refineries or
connecting carriers to which we deliver could adversely affect our business.
Those refineries' need for crude oil also is dependent on the competition from
other refineries, the impact of future economic conditions, fuel conservation
measures, alternative fuel requirements, government regulation or technological
advances in fuel economy and energy generation devices, all of which could
reduce demand for our services.

We are exposed to the credit risk of our customers in the ordinary
course of our crude oil gathering and marketing activities.

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. In those cases where we provide division order services for crude oil
purchased at the wellhead, we may be responsible for distribution of proceeds to
all parties. In other cases, we pay all of or a portion of the production
proceeds to an operator who distributes these proceeds to the various interest
owners. These arrangements expose us to operator credit risk. As a result, we
must determine that operators have sufficient financial resources to make such
payments and distributions and to indemnify and defend us in case of a protest,
action or complaint. Even if our credit review and analysis mechanisms work
properly, there can be no assurance that we will not experience losses in
dealings with other parties.

Our indebtedness could adversely restrict our ability to operate,
affect our financial condition and prevent us from fulfilling our obligations
under our debt instruments and making distributions.

We have outstanding indebtedness and the ability to incur more
indebtedness. As of December 31, 2005, we had no outstanding senior secured
indebtedness, however, we had approximately $85.3 million outstanding of
accounts payable.

We and all of our subsidiaries must comply with various affirmative
and negative covenants contained in our credit facilities. Among other things,
these covenants limit the ability of us and our subsidiaries to:

- incur additional indebtedness or liens;

- make payments in respect of or redeem or acquire any debt or
equity issued by us;

- sell assets;

- make loans or investments;

- extend credit;

- acquire or be acquired by other companies; and

- amend some of our contracts.

The restrictions under our indebtedness may prevent us from engaging
in certain transactions which might otherwise be considered beneficial to us and
could have other important consequences to you. For example, they could:

- increase our vulnerability to general adverse economic and
industry conditions;

- limit our ability to make distributions to unitholders; to
fund future working capital, capital expenditures and other
general partnership requirements; to engage in future
acquisitions, construction or development activities; or to
otherwise fully realize the value of our assets and
opportunities because of the need to dedicate a substantial
portion of our cash flow from operations to payments on our
indebtedness or to comply with any restrictive terms of our
indebtedness;

- limit our flexibility in planning for, or reacting to, changes
in our businesses and the industries in which we operate; and

- place us at a competitive disadvantage as compared to our
competitors that have less debt.

We may incur additional indebtedness (public or private) in the
future, either under our existing credit facilities, by issuing debt
instruments, under new credit agreements, under joint venture credit agreements,
under capital leases or synthetic leases, on a project finance or other basis,
or a combination of any of these. If we incur additional indebtedness in the
future, it likely would be under our existing credit facility or under
arrangements which may have terms and conditions at least as restrictive as
those contained in our existing credit facilities. Failure to comply with the
terms and conditions of any existing or future indebtedness would constitute an
event of default. If an event of default occurs, the lenders will have the right
to accelerate the maturity of such indebtedness and foreclose upon the
collateral, if any, securing that indebtedness. If an event of default occurs
under our joint ventures' credit facilities, we may be required to repay amounts
previously distributed to us and our subsidiaries. In addition, if there is a
change of control as described in our credit facility that would be an event of
default, unless our creditors agreed otherwise, under our credit facility, any
such event could limit our ability to fulfill our obligations under our debt
instruments and to make cash distributions to unitholders which could adversely
affect the market price of our securities.

Our operations are subject to federal and state environmental
protection and safety laws and regulations.

Our operations are subject to the risk of incurring substantial
environmental and safety related costs and liabilities. In particular, the
transportation and storage of crude oil involves a risk that crude oil and
related hydrocarbons may be released into the environment, which may result in
substantial expenditures for a response action, significant government
penalties, liability to government agencies for natural resources damages,
liability to private parties for personal injury or property damages, and
significant business interruption. These costs and liabilities could rise under
increasingly strict environmental and safety laws, including regulations and
enforcement policies, or claims for damages to property or persons resulting
from our operations. If we are unable to recover such resulting costs through
increased rates or insurance reimbursements, our cash flows and distributions to
our unitholders could be materially affected

Our CO(2) operations primarily relate to our volumetric production
payment interests, which are a finite resource and projected to deplete around
2016.

The cash flow from our CO(2) operations primarily relates to our
volumetric production payments, which are projected to terminate around 2016.
Unless we are able to obtain a replacement supply of CO(2) and enter into sales
arrangements that generate substantially similar economics, our cash flow could
decline significantly around 2016.

Our CO(2) operations are exposed to risks related to Denbury's
operation of their CO(2) fields, equipment and pipeline.

Because Denbury Resources produces the CO(2) and transports the
CO(2) to our customers, any major failure of its operations could have an impact
on our ability to meet our obligations to our CO(2) customers. We have no other
supply of CO(2) or method to transport it to our customers.

The CO(2) supplied by Denbury Resources to us for our sale to our
customers could fail to meet the quality standards in the contracts due to
impurities or water vapor content. If the CO(2) were below specifications, we
could

be contractually obligated to provide compensation to our customers for the
costs incurred in raising the CO(2) quality to serviceable levels required by
our contracts.

Fluctuations in demand for CO(2) by our industrial customers could
materially impact our profitability.

Our customers are not obligated to purchase volumes in excess of
specified minimum amounts in our contracts. As a result, fluctuations in our
customers' demand due to market forces or operational problems could result in a
reduction in our revenues from our sales of CO(2).

Our wholesale CO(2) industrial operations are dependent on five
customers.

If one or more of those customers experience financial difficulties
such that they fail to purchase their required minimum take-or-pay volumes, our
cash flows could be adversely affected. We believe these five customers are
credit worthy, but we cannot assure you that an unanticipated deterioration in
their ability to meet their obligations to us might not occur.

We may not be able to fully execute our growth strategy if we
encounter tight capital markets or increased competition for qualified assets.

Our strategy contemplates substantial growth through the development
and acquisition of a wide range of midstream and other energy infrastructure
assets while maintaining a strong balance sheet. This strategy includes
constructing and acquiring additional assets and businesses to enhance our
ability to compete effectively, diversify our asset portfolio and, thereby,
provide more stable cash flow. We regularly consider and enter into discussions
regarding, and are currently contemplating, additional potential joint ventures,
stand-alone projects and other transactions that we believe will present
opportunities to realize synergies, expand our role in the energy infrastructure
business, and increase our market position and, ultimately, increase
distributions to unitholders.

We will need new capital to finance the future development and
acquisition of assets and businesses. Limitations on our access to capital will
impair our ability to execute this strategy. Expensive capital will limit our
ability to develop or acquire accretive assets. Although we intend to continue
to expand our business, this strategy may require substantial capital, and we
may not be able to raise the necessary funds on satisfactory terms, if at all.

In addition, we are experiencing increased competition for the
assets we purchase or contemplate purchasing. Increased competition for a
limited pool of assets could result in our not being the successful bidder more
often or our acquiring assets at a higher relative price than that which we have
paid historically. Either occurrence would limit our ability to fully execute
our growth strategy. Our ability to execute our growth strategy may impact the
market price of our securities.

Our growth strategy may adversely affect our results of operations
if we do not successfully integrate the businesses that we acquire or if we
substantially increase our indebtedness and contingent liabilities to make
acquisitions.

We may be unable to integrate successfully businesses we acquire. We
may incur substantial expenses, delays or other problems in connection with our
growth strategy that could negatively impact our results of operations.
Moreover, acquisitions and business expansions involve numerous risks,
including:

- difficulties in the assimilation of the operations,
technologies, services and products of the acquired companies
or business segments;

- inefficiencies and complexities that can arise because of
unfamiliarity with new assets and the businesses associated
with them, including unfamiliarity with their markets; and

- diversion of the attention of management and other personnel
from day-to-day business to the development or acquisition of
new businesses and other business opportunities.

If consummated, any acquisition or investment also likely would
result in the incurrence of indebtedness and contingent liabilities and an
increase in interest expense and depreciation, depletion and amortization
expenses. A substantial increase in our indebtedness and contingent liabilities
could have a material adverse effect on our business, as discussed above.

Our actual construction, development and acquisition costs could
exceed our forecast, and our cash flow from construction and development
projects may not be immediate.

Our forecast contemplates significant expenditures for the
development, construction or other acquisition of energy infrastructure assets,
including some construction and development projects with technological
challenges. We may not be able to complete our projects at the costs currently
estimated. If we experience material cost overruns, we will have to finance
these overruns using one or more of the following methods:

- using cash from operations;

- delaying other planned projects;

- incurring additional indebtedness; or

- issuing additional debt or equity.

Any or all of these methods may not be available when needed or may
adversely affect our future results of operations.

Fluctuations in interest rates could adversely affect our business.

In addition to our exposure to commodity prices, we also have
exposure to movements in interest rates. The interest rates on our credit
facility are variable. Our results of operations and our cash flow, as well as
our access to future capital and our ability to fund our growth strategy, could
be adversely affected by significant increases or decreases in interest rates.

Our use of derivative financial instruments could result in
financial losses.

We use financial derivative instruments and other hedging mechanisms
from time to time to limit a portion of the adverse effects resulting from
changes in commodity prices, although there are times when we do not have any
hedging mechanisms in place. To the extent we hedge our commodity price
exposure, we forego the benefits we would otherwise experience if commodity
prices were to increase. In addition, we could experience losses resulting from
our hedging and other derivative positions. Such losses could occur under
various circumstances, including if our counterparty does not perform its
obligations under the hedge arrangement, our hedge is imperfect, or our hedging
policies and procedures are not followed.

A natural disaster, catastrophe or other interruption event
involving us could result in severe personal injury, property damage and
environmental damage, which could curtail our operations and otherwise adversely
affect our assets and cash flow.

Some of our operations involve risks of severe personal injury,
property damage and environmental damage, any of which could curtail our
operations and otherwise expose us to liability and adversely affect our cash
flow. Virtually all of our operations are exposed to the elements, including
hurricanes, tornadoes, storms, floods and earthquakes.

If one or more facilities that are owned by us or that connect to us
is damaged or otherwise affected by severe weather or any other disaster,
accident, catastrophe or event, our operations could be significantly
interrupted. Similar interruptions could result from damage to production or
other facilities that supply our facilities or other stoppages arising from
factors beyond our control. These interruptions might involve significant damage
to people, property or the environment, and repairs might take from a week or
less for a minor incident to six months or more for a major interruption. Any
event that interrupts the fees generated by our energy infrastructure assets, or
which causes us to make significant expenditures not covered by insurance, could
reduce our cash available for paying our interest obligations as well as
unitholder distributions and, accordingly, adversely impact the market price of
our securities. Additionally, the proceeds of any property insurance maintained
by us may not be paid in a timely manner or be in an amount sufficient to meet
our needs if such an event were to occur, and we may not be able to renew it or
obtain other desirable insurance on commercially reasonable terms, if at all.

FERC regulation and a changing regulatory environment could affect
our cash flow.

The FERC extensively regulates certain of our energy infrastructure
assets engaged in interstate operations. Our intrastate pipeline operations are
regulated by state agencies. This regulation extends to such matters as:

- rate structures;

- rates of return on equity;

- recovery of costs;

- the services that our regulated assets are permitted to
perform;

- the acquisition, construction and disposition of assets; and

- to an extent, the level of competition in that regulated
industry.

Given the extent of this regulation, the extensive changes in FERC
policy over the last several years, the evolving nature of federal and state
regulation and the possibility for additional changes, the current regulatory
regime may change and affect our financial position, results of operations or
cash flows.

Terrorist attacks aimed at the partnership's facilities could
adversely affect the business.

On September 11, 2001, the United States was the target of terrorist
attacks of unprecedented scale. Since the September 11 attacks, the U.S.
government has issued warnings that energy assets, specifically the nation's
pipeline infrastructure, may be the future targets of terrorist organizations.
These developments have subjected our operations to increased risks. Any future
terrorist attack at our facilities, those of our customers and, in some cases,
those of other pipelines, could have a material adverse effect on our business.

Denbury is the only shipper (other than us) on our Mississippi
System.

Denbury Resources is our only customer on the Mississippi System.
This relationship may subject our operations to increased risks. Any adverse
developments concerning Denbury Resources could have a material adverse effect
on our Mississippi System business. Neither our partnership agreement nor any
other agreement requires Denbury Resources to pursue a business strategy that
favors us or utilizes our Mississippi System. Denbury Resources may compete with
us and may manage their assets in a manner that could adversely affect our
Mississippi System business.

We cannot cause our joint venture to take or not to take certain
actions unless some or all of the joint venture participants agree.

Due to the nature of joint ventures, each participant (including us)
in our joint venture, T & P Syngas Supply Company, has made substantial
investments (including contributions and other commitments) in that joint
venture and, accordingly, has required that the relevant charter documents
contain certain features designed to provide each participant with the
opportunity to participate in the management of the joint venture and to protect
its investment in that joint venture, as well as any other assets which may be
substantially dependent on or otherwise affected by the activities of that joint
venture. These participation and protective features include a corporate
governance structure that consists of a management committee composed of four
members, only two of which are appointed by us. In addition, Praxair, the other
50% owner, operates the joint venture facilities. Thus, without the concurrence
of the other joint venture participant, we cannot cause our joint venture to
take or not to take certain actions, even though those actions may be in the
best interest of the joint venture or us. As of December 31, 2005, our aggregate
investment in T & P Syngas Supply Company totaled $13.0 million.

Our syngas operations are dependent on one customer.

Our syngas joint venture has dedicated 100% of its syngas processing
capacity to one customer pursuant to a processing contract. The contract term
expires in 2016, unless our customer elects to extend the contract for two
additional five year terms. If our customer reduces or discontinues its business
with us, or if we are not able to successfully negotiate a replacement contract
with our sole customer after the expiration of such contract, or if the
replacement contract is on less favorable terms, the effect on us will be
adverse. In addition, if our sole customer for syngas processing were to
experience financial difficulties such that it failed to provide volumes to
process, our cash flow from the syngas joint venture could be adversely
affected. We believe this customer is creditworthy, but we cannot assure you
that unanticipated deterioration of their abilities to meet their obligations to
the syngas joint venture might not occur.

RISKS RELATED TO OUR PARTNERSHIP STRUCTURE

Denbury and its affiliates have conflicts of interest with us and
limited fiduciary responsibilities, which may permit them to favor their own
interests to your detriment.

Denbury Resources indirectly owns and controls our general partner.
Conflicts of interest may arise between Denbury Resources and its affiliates,
including our general partner, on the one hand, and us and our unitholders, on
the other hand. As a result of these conflicts, our general partner may favor
its own interest and the interest of its affiliates or others over the interest
of our unitholders. These conflicts include, among others, the following
situations:

- neither our partnership agreement nor any other agreement
requires Denbury Resources to pursue a business strategy that
favors us or utilizes our assets. Denbury Resources' directors
and officers have a fiduciary duty to make these decisions in
the best interest of the stockholders of Denbury Resources;

- Denbury Resources may compete with us. Denbury Resources owns
the largest reserves of CO(2) used for tertiary oil recovery
east of the Mississippi River and may manage these reserves in
a manner that could adversely affect our CO(2) business;

- our general partner is allowed to take into account the
interest of parties other than us, such as Denbury Resources,
in resolving conflicts of interest;

- our general partner may limit its liability and reduce its
fiduciary duties, while also restricting the remedies
available to our unitholders for actions that, without the
limitations, might constitute breaches of fiduciary duty;

- our general partner determines the amount and timing of asset
purchases and sales, capital expenditures, borrowings,
including for incentive distributions, issuance of additional
partnership securities, reimbursements and enforcement of
obligations to the general partner and its affiliates,
retention of counsel, accountants and service providers, and
cash reserves, each of which can also affect the amount of
cash that is distributed to our unitholders;

- our general partner determines which costs incurred by it and
its affiliates are reimbursable by us and the reimbursement of
these costs and of any services provided by our general
partner could adversely affect our ability to pay cash
distributions to our unitholders;

- our general partner controls the enforcement of obligations
owed to us by our general partner and its affiliates;

- our general partner decides whether to retain separate
counsel, accountants or others to perform services for us; and

- in some instances, our general partner may cause us to borrow
funds in order to permit the payment of distributions even if
the purpose or effect of the borrowing is to make incentive
distributions.

We expect to continue to enter into substantial transactions and
other activities with Denbury Resources and its subsidiaries because of the
businesses and areas in which we and Denbury Resources currently operate, as
well as those in which we plan to operate in the future. Some more recent
transactions in which we, on the one hand, and Denbury Resources and its
subsidiaries, on the other hand, had a conflict of interest include:

- transportation services

- pipeline monitoring services; and

- CO(2) volumetric production payment.

In addition, Denbury Resources' beneficial ownership interest in our
outstanding partnership interests could have a substantial effect on the outcome
of some actions requiring partner approval. Accordingly, subject to legal
requirements, Denbury Resources makes the final determination regarding how any
particular conflict of interest is resolved.

Even if unitholders are dissatisfied, they cannot easily remove our
general partner.

Unlike the holders of common stock in a corporation, unitholders
have only limited voting rights on matters affecting our business and,
therefore, limited ability to influence management's decisions regarding our
business.

Unitholders did not elect our general partner or its board of
directors and will have no right to elect our general partner or its board of
directors on an annual or other continuing basis. The board of directors of our
general partner is chosen by the stockholders of our general partner. In
addition, if the unitholders are dissatisfied with the performance of our
general partner, they will have little ability to remove our general partners.
As a result of these limitations, the price at which the common units trade
could be diminished because of the absence or reduction of a takeover premium in
the trading price.

The vote of the holders of at least a majority of all outstanding
units (excluding any units held by our general partner and its affiliates) is
required to remove the general partner without cause, as defined in the
partnership agreement. If our general partner is removed without cause, (i)
Denbury Resources will have the option to acquire a substantial portion of our
Mississippi pipeline system at 110% of its then fair market value, and (ii) our
general partner will have the option to convert its interest in us (other than
its common units) into common units or to require our replacement general
partner to purchase such interest for cash at its then fair market value. In
addition, unitholders' voting rights are further restricted by our partnership
agreement provision providing that any units held by a person that owns 20% or
more of any class of units then outstanding, other than the general partner, its
affiliates, their transferees, and persons who acquired such units with the
prior approval of the board of directors of the general partner, cannot vote on
any matter. Our partnership agreement also contains provisions limiting the
ability of unitholders to call meetings or to acquire information about our
operations, as well as other provisions limiting the unitholders' ability to
influence the manner of direction of management.

As a result of these provisions, the price at which our common units
trade may be lower because of the absence or reduction of a takeover premium.

The control of our general partner may be transferred to a third
party without unitholder consent, which could affect our strategic direction and
liquidity.

Our general partner may transfer its general partner interest to a
third party in a merger or in a sale of all or substantially all of its assets
without the consent of the unitholders. Furthermore, there is no restriction in
our partnership agreement on the ability of the owner of our general partner
from transferring its ownership interest in the general partner to a third
party. The new owner of the general partner would then be in a position to
replace the board of directors and officers of the general partner with its own
choices and to control the decisions taken by the board of directors and
officers.

In addition, unless our creditors agreed otherwise, we would be
required to repay the amounts outstanding under our credit facilities upon the
occurrence of any change of control described therein. We may not have
sufficient funds available or be permitted by our other debt instruments to
fulfill these obligations upon such occurrence. A change of control could have
other consequences to us depending on the agreements and other arrangements we
have in place from time to time, including employment compensation arrangements.

Our general partner and its affiliates may sell units or other
limited partner interests in the trading market, which could reduce the market
price of common units.

As of December 31, 2005, our general partner and its affiliates own
1,019,441 (approximately 7%) of our common units. In the future, they may
acquire additional interest or dispose of some or all of their interest. If they
dispose of a substantial portion of their interest in the trading markets, the
sale could reduce the market price of common units. Our partnership agreement,
and other agreements to which we are party, allow our general partner and
certain of its subsidiaries to cause us to register for sale the partnership
interests held by such persons, including common units. These registration
rights allow our general partner and its subsidiaries to request registration of
those partnership interests and to include any of those securities in a
registration of other capital securities by us.

Our general partner has anti-dilution rights.

Whenever we issue equity securities to any person other than our
general partner and its affiliates, our general partner and its affiliates have
the right to purchase an additional amount of those equity securities on the
same terms as they are issued to the other purchasers. This allows our general
partner and its affiliates to maintain

their percentage partnership interest in us. No other unitholder has a similar
right. Therefore, only our general partner may protect itself against dilution
caused by the issuance of additional equity securities.

Due to our significant relationships with Denbury, adverse
developments concerning Denbury could adversely affect us, even if we have not
suffered any similar developments.

Through its subsidiaries, Denbury Resources owns 100 percent of our
general partner and has historically, with its affiliates, employed the
personnel who operate our businesses. Denbury Resources is a significant
stakeholder in our limited partner interests, and as with many other energy
companies, is a significant customer of ours.

We may issue additional common units without unitholders' approval,
which would dilute their ownership interests.

We may issue an unlimited number of limited partner interests of any
type without the approval of our unitholders.

The issuance of additional common units or other equity securities
of equal or senior rank will have the following effects:

- our unitholders' proportionate ownership interest in us will
decrease;

- the amount of cash available for distribution on each unit may
decrease;

- the relative voting strength of each previously outstanding
unit may be diminished; and

- the market price of our common units may decline.

Our general partner has a limited call right that may require you to
sell your common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than
80% of the common units, our general partner will have the right, but not the
obligation, which it may assign to any of its affiliates or to us, to acquire
all, but not less than all, of the common units held by unaffiliated persons at
a price not less than their then-current market price. As a result, you may be
required to sell your common units at an undesirable time or price and may not
receive any return on your investment. You may also incur a tax liability upon a
sale of your units.

The interruption of distributions to us from our subsidiaries and
joint ventures may affect our ability to make payments on indebtedness or cash
distributions to our unitholders.

We are a holding company. As such, our primary assets are the equity
interests in our subsidiaries and joint ventures. Consequently, our ability to
fund our commitments (including payments on our indebtedness) and to make cash
distributions depends upon the earnings and cash flow of our subsidiaries and
joint ventures and the distribution of that cash to us. Distributions from our
joint ventures are subject to the discretion of their respective management
committees. Further, each joint venture's charter documents typically vest in
its management committee sole discretion regarding distributions. Accordingly,
our joint ventures may not continue to make distributions to us at current
levels or at all.

We do not have the same flexibility as other types of organizations
to accumulate cash and equity to protect against illiquidity in the future.

Unlike a corporation, our partnership agreement requires us to make
quarterly distributions to our unitholders of all available cash reduced by any
amounts reserved for commitments and contingencies, including capital and
operating costs and debt service requirements. The value of our units and other
limited partner interests will decrease in direct correlation with decreases in
the amount we distribute per unit. Accordingly, if we experience a liquidity
problem in the future, we may not be able to issue more equity to recapitalize.

TAX RISKS TO COMMON UNITHOLDERS

The IRS could treat us as a corporation for tax purposes, which
would substantially reduce the cash available for distribution to our
unitholders.

The after-tax economic benefit of an investment in the common units
depends largely on our being treated as a partnership for federal income tax
purposes. We have not requested, and do not plan to request, a ruling from the
IRS on this or any other tax matter affecting us.

If we were treated as a corporation for federal income tax purposes,
we would pay federal income tax on our income at the corporate tax rate, which
is currently a maximum of 35%. Distributions to you may be taxed again as
corporate dividends, and no income, gains, losses or deductions would flow
through to you. Because a tax would be imposed upon us as a corporation, our
cash available for distribution to you would be substantially reduced. If we
were treated as a corporation, there would be a material reduction in the
after-tax return to the unitholders, likely causing a substantial reduction in
the value of our common units.

Current law may change so as to cause us to be treated as a
corporation for federal income tax purposes or otherwise subject us to
entity-level taxation. In addition, because of widespread state budget deficits,
several states are evaluating ways to subject partnerships to entity-level
taxation through the imposition of state income, franchise or other forms of
taxation. If any state were to impose a tax upon us as an entity, the cash
available for distribution to you would be reduced. The partnership agreement
provides that if a law is enacted or existing law is modified or interpreted in
a manner that subjects us to taxation as a corporation or otherwise subjects us
to entity-level taxation for federal, state or local income tax purposes, the
minimum quarterly distribution amount and the target distribution amounts will
be adjusted to reflect the impact of that law on us.

A successful IRS contest of the federal income tax positions we take
may adversely affect the market for our common units, and the cost of any IRS
contest will be borne by our unitholders and our general partner.

We have not requested a ruling from the IRS with respect to our
treatment as a partnership for federal income tax purposes or any other matter
affecting us. The IRS may adopt positions that differ from the conclusions of
our counsel or from the positions we take. It may be necessary to resort to
administrative or court proceedings to sustain some or all of our counsel's
conclusions or the positions we take. A court may not agree with some or all of
our counsel's conclusions or positions we take. Any contest with the IRS may
materially and adversely impact the market for our common units and the price at
which they trade. In addition, our costs of any contest with the IRS will be
borne indirectly by our unitholders and our general partner, and these costs
will reduce our cash available for distribution.

Our unitholders may be required to pay taxes on income from us even
if they do not receive any cash distributions from us.

You will be required to pay any federal income taxes and, in some
cases, state and local income taxes on your share of our taxable income even if
you receive no cash distributions from us. You may not receive cash
distributions from us equal to your share of our taxable income or even the tax
liability that results from that income.

Tax gain or loss on disposition of common units could be different
than expected.

If you sell your common units, you will recognize a gain or loss
equal to the difference between the amount realized and your tax basis in those
common units. Prior distributions to you in excess of the total net taxable
income you were allocated for a common unit, which decreased your tax basis in
that common unit, will, in effect, become taxable income to you if the common
unit is sold at a price greater than your tax basis in that common unit, even if
the price is less than your original cost. A substantial portion of the amount
realized, whether or not representing gain, may be ordinary income. In addition,
if you sell your units, you may incur a tax liability in excess of the amount of
cash you receive from the sale.

Tax-exempt entities, regulated investment companies and foreign
persons face unique tax issues from owning common units that may result in
adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as
individual retirement accounts (known as IRAs), regulated investment companies
(known as mutual funds) and non U.S. persons raises issues unique to them. For
example, a significant amount of our income allocated to organizations exempt
from federal income tax,

including individual retirement accounts and other retirement plans, may be
unrelated business taxable income and will be 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 prior to the date of enactment, very little of our income will be
qualifying income to a regulated investment company. Distributions to non-U.S.
persons will be reduced by withholding tax at the highest effective tax rate
applicable to individuals, and non U.S. unitholders will be required to file
federal income tax returns and pay tax on their share of our taxable income.

We are registered as a tax shelter. This may increase the risk of an
IRS audit of us or our unitholders.

We are registered with the IRS as a "tax shelter." Our tax shelter
registration number is 97043000153. The federal income tax laws require that
some types of entities, including some partnerships, register as tax shelters in
response to the perception that they claim tax benefits that may be unwarranted.
As a result, we may be audited by the IRS and tax adjustments may be made. Any
unitholder owning less than a 1% profit interest in us has very limited rights
to participate in the income tax audit process. Further, any adjustments in our
tax returns will lead to adjustments in your tax returns and may lead to audits
of your tax returns and adjustments of items unrelated to us. You would bear the
cost of any expense incurred in connection with an examination of your tax
return.

We will treat each purchaser of common units as having the same tax
benefits without regard to the units purchased. The IRS may challenge this
treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units,
we adopt depreciation and amortization positions that may not conform with all
aspects of applicable Treasury regulations. A successful IRS challenge to those
positions could adversely affect the amount of tax benefits available to a
common unitholder. It also could affect the timing of these tax benefits or the
amount of gain from a sale of common units and could have a negative impact on
the value of the common units or result in audit adjustments to the common
unitholder's tax returns.

Our unitholders will likely be subject to state and local taxes in
states where they do not live as a result of an investment in units.

In addition to federal income taxes, you will likely be subject to
other taxes, including foreign, state and local taxes, unincorporated business
taxes and estate inheritance or intangible taxes that are imposed by the various
jurisdictions in which we do business or own property, even if you do not live
in any of those jurisdictions. You will likely be required to file foreign,
state and local income tax returns and pay state and local income taxes in some
or all of these jurisdictions. Further, you may be subject to penalties for
failure to comply with those requirements. We own assets and do business in
Texas, Louisiana, Mississippi, Alabama, Florida, and Oklahoma. Louisiana,
Mississippi, Alabama, Florida, and Oklahoma currently impose a personal income
tax. It is your responsibility to file all United States federal, foreign, state
and local tax returns. Our counsel has not rendered an opinion on the state or
local tax consequences of an investment in the common units.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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 our financial condition, results of operations or cash flows.
(See Note 18. Commitments and Contingencies.)

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

Our 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)
---------- ----------- -------------

2006
First Quarter (through March 1, 2006)...... $ 12.85 $ 11.25 $ 0.17

2005
First Quarter.............................. $ 12.60 $ 8.50 $ 0.15
Second Quarter............................. $ 10.00 $ 8.25 $ 0.15
Third Quarter.............................. $ 12.15 $ 9.22 $ 0.15
Fourth Quarter............................. $ 12.00 $ 9.61 $ 0.16
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, 2005, there were 13,784,441 common units outstanding,
including 1,019,441 common units held by our general partner. As of December 31,
2005, there were approximately 6,100 record holders of our common units, which
include holders who own units through their brokers "in street name."

We distribute all of our available cash, as defined in our partnership
agreement, within 45 days after the end of each quarter to Unitholders of record
and to our 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 our
partnership agreement and amendments thereto, which is filed as an exhibit to
this Form 10-K.

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.

Recent Sales of Unregistered Securities. On December 13, 2005, we sold
330,630 common units to our general partner for $3.3 million in a private
transaction that was exempt from the registration requirements of the Securities
Act of 1933, pursuant to Section 4(2) thereof. This sale, made concurrently with
a public offering, was made pursuant to our general partner's preemptive rights
under Section 5.6 of our partnership agreement.

ITEM 6. SELECTED FINANCIAL DATA

The table below includes selected financial data for the Partnership for
the years ended December 31, 2005, 2004, 2003, 2002, and 2001 (in thousands,
except per unit and volume data).

Year Ended December 31,
-----------------------------------------------------------------
2005 2004 2003 2002 2001
----------- ----------- ----------- ----------- -----------

INCOME STATEMENT DATA:
Revenues:
Crude oil gathering & marketing ........................ $ 1,038,549 $ 901,902 $ 641,684 $ 639,143(1)$ 3,001,632
Pipeline transportation, including natural gas sales ... 28,888 16,680 15,134 13,485 9,948
CO(2) marketing ........................................ 11,302 8,561 1,079 - -
----------- ----------- ----------- ----------- -----------
Total revenues ....................................... 1,078,739 927,143 657,897 652,628 3,011,580
Costs and expenses:
Crude oil and field operating .......................... 1,034,888 897,868 633,776 629,245(1) 2,990,223
Pipeline transportation, including natural gas
purchases ............................................ 19,084 8,137 10,026 8,076 7,038
CO(2) marketing transportation costs ................... 3,649 2,799 355 - -
General and administrative expenses .................... 9,656 11,031 8,768 7,864 11,307
Depreciation and amortization .......................... 6,721 7,298(2) 4,641 4,603 14,929(2)
Loss (gain) from sales of surplus assets ............... (479) 33 (236) (705) (167)
Other operating charges ................................ - - - 1,500 1,500
----------- ----------- ----------- ----------- -----------
Total costs and expenses ............................. 1,073,519 927,166 657,330 650,583 3,024,830
----------- ----------- ----------- ----------- -----------
Operating income (loss) from continuing operations ......... 5,220 (23) 567 2,045 (13,250)
Earnings from equity in joint venture ...................... 501 - - - -
Interest expense, net ...................................... (2,032) (926) (986) (1,035) (527)
Minority interests effects ................................. - - - - 1
----------- ----------- ----------- ----------- -----------
Income (loss) in continuing operations before cumulative
effect of change in accounting principle ............. 3,689 (949) (419) 1,010 (13,776)
Income (loss) from discontinued operations ................. 312 (463) 13,741 4,082 (30,303)(2)
Cumulative effect of change in accounting principle ........ (586) - - - 467
----------- ----------- ----------- ----------- -----------
Net income (loss) .......................................... $ 3,415 $ (1,412) $ 13,322 $ 5,092 $ (43,612)
=========== =========== =========== =========== ===========
Net income (loss) per common unit-basic and diluted:
Continuing operations .................................. $ 0.38 $ (0.10) $ (0.05) $ 0.12 $ (1.57)
Discontinued operations ................................ 0.03 (0.05) 1.55 0.46 (3.44)
Cumulative effect of change in accounting
principle ............................................ (0.06) - - - 0.05
----------- ----------- ----------- ----------- -----------
Net income (loss) ...................................... $ 0.35 $ (0.15) $ 1.50 $ 0,58 $ (4.96)
=========== =========== =========== =========== ===========

Cash distributions per common unit: ........................ $ 0.61 $ 0.60 $ 0.15 $ 0.20 $ 0.80

BALANCE SHEET DATA (AT END OF PERIOD):
Current assets ............................................. $ 90,449 $ 77,396 $ 88,211 $ 92,830 $ 182,100
Total assets ............................................... 181,777 143,154 147,115 137,537 230,113
Long-term liabilities ...................................... 955 15,460 7,000 5,500 13,900
Minority interests ......................................... 522 517 517 515 515
Partners' capital .......................................... 87,689 45,239 52,354 35,302 32,009

Year Ended December 31,
-----------------------------------------------------
2005 2004 2003 2002 2001
-------- -------- -------- -------- --------

OTHER DATA:
Maintenance capital expenditures(3) ..... $ 1,543 $ 939 $ 4,178 $ 4,211 $ 1,882
Volumes-continuing operations:
Crude oil pipeline (bpd) ............ 61,296 63,441 66,959 71,870 80,408
CO(2) sales (Mcf per day) ........... 56,823 45,312 36,332(4) - -
Crude oil gathering and marketing:
Wellhead (bpd) .................... 39,194 45,919 45,015 47,819 67,373
Total (bpd) ....................... 52,943 60,419 56,805 73,429(1) 320,532

- ----------
(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 unaudited quarterly financial data for 2005
and 2004 (in thousands, except per unit data).

2005 Quarters
---------------------------------------------
First Second Third Fourth
--------- --------- --------- ---------

Revenues - continuing operations ...................... $ 256,600 $ 257,144 $ 300,577 $ 264,418
Operating income (loss) - continuing operations ....... $ 2,843 $ 1,006 $ (109) $ 1,480
Income (loss) from continuing operations .............. 2,488 752 (641) 1,090
Income (loss) from discontinued operations ............ 282 (9) 45 (6)
Cumulative effect adjustment .......................... - - - (586)
Net income (loss) ..................................... $ 2,770 $ 743 $ (596) $ 498
Net income (loss) per common unit-basic and diluted ... $ 0.29 $ 0.08 $ (0.06) $ 0.05

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)

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 2005

- - Acquisitions in 2005

- - Critical Accounting Policies

- - Results of Operations

- - Liquidity and Capital Resources

- - Commitments and Off-Balance Sheet Arrangements

- - Other Matters

- - New Accounting Pronouncements

In the discussions that follow, we will focus on two measures that we use
to manage the business and to review the results of our operations. Those two
measures are segment margin and Available Cash before Reserves. 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. Segment
margin also includes our equity in the operating income of joint ventures. A
reconciliation of segment margin to income from continuing operations is
included in our segment disclosures in Note 10 to the consolidated financial
statements. Available Cash before Reserves 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,
the replacement with the amount recognized as our equity in the income of joint
ventures with the available cash generated from those ventures, 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 before Reserves and a reconciliation of
this measure to cash flows from operations, see "Liquidity and Capital Resources
- - Non-GAAP Financial Measure" below.

OVERVIEW OF 2005

We conduct our business through three segments - pipeline
transportation (primarily of crude oil), crude oil gathering and marketing, and
industrial gases. We have a diverse portfolio of customers and assets, including
pipeline transportation of primarily crude oil and, to a lesser extent, natural
gas and carbon dioxide (CO(2)) in the Gulf Coast region of the United Sates. In
conjunction with our crude oil pipeline transportation operations, we operate a
crude oil gathering and marketing business, which (among other things) helps
ensure a base supply of crude oil for our pipelines. We participate in
industrial gas activities, including a CO(2) supply business, which is
associated with the CO(2) tertiary oil recovery process being used in
Mississippi by an affiliate of our general partner. We generate revenues by
selling crude oil and industrial gases and by charging fees for the
transportation of crude oil, natural gas and CO(2) on our pipelines, and through
our joint venture in T&P Syngas Supply Company, fees for services to produce
syngas for our customer from the customer's raw materials. 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 CO(2)
to the customer, and the costs of operating our assets. We also report our share
of the earnings of our joint venture, T&P Syngas in which we acquired a 50%
interest on April 1, 2005.

Our objective is to operate as a growth-oriented midstream MLP with
a focus on increasing cash flow, earnings and return to our unitholders by
becoming one of the leading providers of pipeline transportation, crude oil
gathering and marketing and industrial gas services in the regions in which we
operate. Increases in cash flow generally result in increases in Available Cash
before Reserves, which we distribute quarterly to our unitholders. During 2005,
we generated $11.1 million of Available Cash before Reserves, and distributed
$5.8 million to our unitholders. During 2005, cash provided by operations was
$9.5 million.

In 2005, we generated net income and earnings per limited partner of
$3.4 million and $0.35 per unit. The results for 2005 include increased segment
margin from our pipeline transportation and significant contributions from asset
acquisitions in the industrial gases segment. We also disposed of idle assets.
Fluctuations in our unit

price decreased our general and administrative expenses as we recognized a
credit related to our stock appreciation rights plan.

In December 2005, we raised equity capital in connection with a
public offering of newly issued limited partner units. The public acquired
4,140,000 of units and our general partner acquired 330,630 units to maintain
its proportionate ownership interest in us. This offering of limited partner
units provided us with net proceeds of $44.8 million, with $1.0 million being
contributed by our general partner to maintain its 2% general partner interest.
The proceeds of this offering were used to temporarily reduce our outstanding
debt under our revolving credit facility at December 31, 2005.

We increased our cash distribution by $0.01 to $0.16 per unit for
the third quarter of 2005 (which was paid in November 2005) and increased our
cash distribution again to $0.17 per unit for the fourth quarter of 2005. This
distribution was paid in February 2006. This distribution represented a 13.3%
increase from our distribution of $0.15 per unit for the fourth quarter of 2004.

ACQUISITIONS IN 2005

Acquisition of Syngas Joint Venture

On April 1, 2005, we acquired a 50% interest in T&P Syngas Supply
Company (T&P Syngas) for $13.4 million. We acquired our interest from TCHI Inc.,
a wholly owned subsidiary of ChevronTexaco Global Energy Inc. Praxair Hydrogen
Supply, Inc. (Praxair) owns the other 50% interest in the partnership. We
financed our T&P Syngas interest acquisition with proceeds from our credit
facility.

T&P Syngas is a partnership that owns a syngas manufacturing
facility located in Texas City, Texas. That facility processes natural gas to
produce syngas (a combination of carbon monoxide and hydrogen) and high pressure
steam. Praxair provides the raw materials to be processed and receives the
syngas and steam produced by the facility under a long-term processing
agreement. T&P Syngas receives a processing fee for its services. Praxair
operates the facility.

T&P Syngas is managed by a management committee consisting of two
representatives each from Praxair and us. The T&P Syngas management committee
has an approved resolution that provides that cash distributions will be paid
quarterly to the partners. In 2005, we received distributions totaling $0.8
million and we received a distribution in February 2006 of $0.2 million. We
expect our investment in T&P Syngas to provide another source of stable,
long-term cash flow and additional balance to our business.

Acquisition of CO(2) Assets

On October 11, 2005, we acquired two long-term CO(2) sales contracts
with industrial customers, along with the 80.0 Bcf of CO(2) in the form of VPPs
necessary to satisfy substantially all of our expected obligations under those
contracts, from Denbury for $14.4 million in cash. We funded this acquisition
with borrowings under our credit facility. This acquisition further diversified
our asset base and provides a stable, long-term source of cash flow to us. Since
2003, we have acquired seven long-term CO(2) sales contracts, along with three
VPPs representing in the aggregate 280.0 Bcf of CO(2) from Denbury for a total
of $43.1 million in cash.

In accordance with our procedures for evaluating and valuing
material acquisitions with Denbury, our Special Conflicts Committee of our Board
of Directors engaged independent financial and legal advisors and obtained a
fairness opinion from the independent financial advisor regarding the
acquisition of the third volumetric production payment. The opinion we received
stated the transaction was fair to our unitholders. See "Certain Relationships
and related Transactions" for a description of our affiliate transaction
procedures.

Gas Pipeline Transportation 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 are comprised
of 60 miles of pipeline and related assets. This acquisition was financed with
proceeds from our credit facility. The results of this acquisition are included
in our pipeline transportation segment.

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.

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.

Asset Retirement Obligations

Some of our assets, primarily related to our pipeline operations
segment, have obligations regarding removal and restoration activities when the
asset is abandoned. Additionally, we generally have obligations to remove crude
oil injection stations located on leased sites. We estimate the fair values of
these obligations based on current costs, inflation estimates and other factors
in order to record the liabilities. We also must estimate the ultimate timing of
the performance of these liabilities in determining the fair value of the
obligations. We revise these estimates as information becomes available that
affects the assumptions we made.

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.

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 of $0.4
million 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 expected to be covered by insurance, we recorded a receivable from the
insurers for a similar amount.

We are currently conducting remediation of subsurface soil and
groundwater hydrocarbon contamination at the former Jay Trucking Facility. The
estimated remediation and related costs are $1.3 million, which we expect to
share with other responsible parties. In 2005, we recorded a liability of $0.5
million as our estimated share of this liability. We currently have no reason to
believe that this remediation will have a material financial effect on our
financial position, results of operation, or cash flows.

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

PIPELINE TRANSPORTATION SEGMENT

We operate three common carrier crude oil pipeline systems in a four
state area. We refer to these pipelines as our Mississippi System, Jay System
and Texas System. Volumes shipped on these systems for the last three years are
as follows (barrels per day):

Pipeline System 2005 2004 2003
- --------------- ------ ------ ------

Mississippi 16,021 12,589 8,443
Jay 13,725 14,440 15,128
Texas 31,550 36,413 43,388

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.

Denbury is the largest producer (based on average barrels produced
per day) of crude oil in the State of Mississippi. Our Mississippi System is
adjacent to several of Denbury's existing and prospective oil fields. Our
Mississippi System is adjacent to several of Denbury's existing and prospective
oil fields. As Denbury continues to acquire and develop old oil fields using
CO(2)based tertiary recovery operations, Denbury expects to add crude oil
gathering and CO(2) supply infrastructure to these fields..

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.

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 began
operations in the first quarter of 2005. Denbury pays 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. Throughput has declined
from an annual average of 15,128 barrels per day in 2003, to 14,440 barrels per
day in 2004, and to 13,725 barrels per day in 2005, although part of the decline
in 2004 and 2005 can be attributed to hurricanes that passed near the panhandle
of Florida. While our facilities experienced minimal damage from the storms,
power outages in the area shut down our crude oil pipeline transportation
operations for several days.

New production in the area surrounding the Jay System has offset
some of the declining production curves of the older producing fields in the
area, however we do not know if this new production will be sufficient to
continue to offset declining production from existing wells in the area. One of
the larger older fields has been unable to return to its production levels
before the hurricanes of 2005. We do not know if they will be successful in
returning to those levels.

Should the production surrounding the Jay System decline such that
it becomes uneconomical to continue to operate the pipeline in crude oil
service, we believe that the best use of the Jay System may be to convert it to
natural gas service. We continue to review opportunities to effect such a
conversion. 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 2006 or 2007.

Volumes on our Texas System averaged 31,550 barrels per day during
2005. 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. This tariff declined to $0.20 per barrel in November 2004.
Substantially all of the volume being shipped on our Texas System goes to two
refineries on the Texas Gulf Coast.

Our Texas System is dependent on the connecting carriers for supply,
and on the two refineries for demand for our services. Volumes on the Texas
System have declined since the sale to TEPPCO as a result of changes in the

supply available for the two refineries to acquire and ship on our pipeline and
changes TEPPCO made to the operations of the pipeline segments it acquired from
us. We lease tankage in Webster on the Texas System of approximately 165,000
barrels. We have a tank rental reimbursement agreement effective January 1, 2005
with the primary shipper on our Texas System to reimburse us for the expense of
leasing of that storage capacity. Volumes on the Texas System may continue to
fluctuate as refiners on the Texas Gulf Coast compete for crude oil with other
markets connected to TEPPCO's pipeline systems.

We operate a CO(2) pipeline in Mississippi to transport CO(2) from
Denbury's main CO(2) pipeline to Brookhaven oil field. Denbury has the exclusive
right to use this CO(2) pipeline. This arrangement has been accounted for as a
direct financing lease.

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.

Operating results from continuing operations for our pipeline
transportation segment were as follows.

Years Ended December 31,
--------------------------------
2005 2004 2003
-------- -------- --------
(in thousands)

Crude oil tariffs and revenues from direct financing leases of
crude oil pipelines ......................................... $ 13,490 $ 13,048 $ 12,868
Sales of crude oil pipeline loss allowance volumes ............... 4,672 3,475 2,266
Revenues from direct financing leases of CO(2) pipelines ......... 359 25 -
Tank rental reimbursements and other miscellaneous revenues ...... 566 132 -
-------- -------- --------
Total revenues from crude oil and CO(2) tariffs, including
revenues from direct financing leases ....................... 19,087 16,680 15,134
Revenues from natural gas tariffs and sales ...................... 9,801 - -
Natural gas purchases ............................................ (9,343) - -
Pipeline operating costs ......................................... (9,741) (8,137) (10,026)
-------- -------- --------
Segment margin ............................................. $ 9,804 $ 8,543 $ 5,108
======== ======== ========

Volumes per day from continuing operations:
Crude oil pipeline - barrels ............................... 61,296 63,441 66,959

Year Ended December 31, 2005 Compared with Year Ended December 31,
2004

Pipeline segment margin increased $1.3 million, or 15%, for 2005, as
compared to 2004. Revenues from crude oil and CO(2) tariffs and related sources
added $2.4 million of the increase for the period and $0.5 million of the
increase resulted from net profit from natural gas transportation and sales.
Pipeline operating cost increases offset $1.6 million of the revenue increases.

Crude oil and CO(2) tariff revenues increased $0.8 million in 2005
compared to the prior year period due to the combination of higher tariffs and
higher volumes on the systems with higher per barrel tariffs. Volumes on our
pipelines were affected briefly by hurricanes in both periods. The effects of
lower tariffs and volumes on the Texas System were generally offset by increased
volumes and tariffs on the Mississippi System.

Higher market prices for crude oil added $1.2 million to pipeline
loss allowance revenues. The CO(2) pipeline did not exist until December 2004,
and the natural gas gathering pipelines were acquired in the first quarter of
2005.

Operating costs increased $1.6 million. In 2004, as well as in 2005,
we incurred costs for regulatory testing and repairs resulting from that
testing. Those costs were approximately $0.6 million greater in 2005.
Operational

costs for personnel, contract services, liability insurance and equipment
maintenance accounted for most of the remaining increase.

Year Ended December 31, 2004 Compared with Year Ended December 31,
2003

In 2004, pipeline segment margin increased $3.4 million, or 67%, as
compared to 2003. A decrease in operating costs was a large part of this
improvement. Total revenues from crude oil and CO(2) tariffs and related sources
also increased, contributing $1.5 million of the total increase.

Crude oil and CO(2) tariff revenues increased $0.2 million, with
higher tariff rates offsetting decreases in volumes. Pipeline loss allowance
revenues benefited from higher market sales prices for crude oil.

Operating costs declined $1.9 million from the 2003 level. 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.

INDUSTRIAL GASES SEGMENT

Our industrial gases segment includes the results of our CO(2) sales
to industrial customers and our share of the operating income of our 50%
partnership interest in T&P Syngas.

CO(2)

The terms of our contracts with the industrial CO(2) customers
include minimum take-or-pay and maximum delivery volumes. The maximum daily
contract quantity per year in the contracts totals 88,875 Mcf. Under the minimum
take-or-pay volumes, the customers must purchase a total of 46,673 Mcf per day
whether received or not. Any volume purchased under the take-or-pay provision in
any year can then be recovered in a future year as long as the minimum
requirement is met in that year. In the three years ended December 31, 2005, all
of our customers purchased more than their minimum take-or-pay quantities.

Our seven industrial contracts expire at various dates beginning in
2010 and extending through 2023. The sales contracts contain provisions for
adjustments for inflation to sales prices based on the Producer Price Index,
with a minimum price.

The industrial customers treat the CO(2) and transport it to their
own customers. The primary industrial applications of CO(2) by these customers
include beverage carbonation and food chilling and freezing. Based on historical
data for 2003 through 2005, we can expect some seasonality in our sales of
CO(2). The dominant months for beverage carbonation and freezing food are from
April to October, when warm weather increases demand for beverages and the
approaching holidays increase demand for frozen foods. The table below depicts
these seasonal fluctuations. The average daily sales (in Mcfs) of CO(2) for each
quarter in 2005 and 2004 under these contracts (including volumes sold by
Denbury on the contracts we acquired in the third quarter of 2004 and fourth
quarter of 2005) were as follows:

Quarter 2005 2004
- ---------------- ------ ------

First 67,434 63,953
Second 73,307 73,734
Third 77,264 78,097
Fourth 77,089 70,696

Syngas

On April 1, 2005, we acquired from TCHI Inc., a wholly owned
subsidiary of ChevronTexaco Global Energy Inc., a 50% partnership interest in
T&P Syngas for $13.4 million in cash, which we funded with proceeds from our
credit facility. T&P Syngas is a partnership which owns a facility located in
Texas City, Texas that manufactures syngas and high-pressure steam. Under that
processing agreement, Praxair provides the raw materials to be processed and
receives the syngas and steam produced by the facility. T&P Syngas receives a
processing fee for its services. Praxair has the exclusive right to use the
facility through at least 2016 (term extendable at Praxair's option for two
additional five year terms). Praxair also is our partner in the joint venture
and owns the remaining 50% interest. We recognize our share of the earnings of
T&P Syngas in each period. We are amortizing the excess of the price we paid for
our interest in T&P Syngas over our share of the equity of T&P Syngas over the
remaining useful life of the assets of T&P Syngas. This excess of $4.0 million
is being amortized over eleven years. We receive cash distributions from T&P
Syngas quarterly.

Operating Results

Operating results for our industrial gases segment were as follows.

Years Ended December 31,
--------------------------------
2005 2004 2003
-------- -------- --------
(in thousands)

Revenues from CO(2) sales ............. $ 11,302 $ 8,561 $ 1,079
CO(2) transportation and other costs .. (3,649) (2,799) (355)
Equity in earnings of T&P Syngas ...... 501 - -
-------- -------- --------
Segment margin .................. $ 8,154 $ 5,762 $ 724
======== ======== ========

Volumes per day:
CO(2) sales - Mcf ............... 56,823 45,312 36,332

The increasing margins from the industrial gases segment between
2003 and 2004 and from 2004 to 2005 are primarily attributable to the
acquisitions we have made each year in this segment. The average revenue per Mcf
sold increased almost 6% in each year, due to inflation adjustments in the
contracts and variations in the volumes sold under each contract.

Transportation costs for the CO(2) on Denbury's pipeline have
increased due to the increased volume and the effect of the annual inflation
factor in the rate paid to Denbury. The rate per Mcf in 2005 increased 4% over
the 2004 rate. The rate in 2004 increased 2% over the 2003 rate.

Our share of the operating income of T&P Syngas for the nine month
period we owned it in 2005 was $765,000. We reduced the amount we recorded as
our equity in T&P Syngas by $264,000 as amortization of the excess purchase
price of T&P Syngas. During 2005, T&P Syngas paid us distributions totaling $0.8
million, and we received a distribution of $0.2 million in 2006 attributable to
the fourth quarter of 2005.

CRUDE OIL GATHERING AND MARKETING OPERATIONS

We conduct certain crude oil aggregating operations, which involve
purchasing, gathering, transporting by trucks and pipelines owned by us and
trucks, pipelines and barges operated by others, and reselling, that (among
other things) help ensure a base supply source for our crude oil pipeline
systems. Our profit for those services is derived from the difference between
the price at which we re-sell crude oil less the price at which we purchase that
crude oil, minus the associated costs of aggregation and any cost of supplying
credit. The most substantial component of our aggregating costs relates to
operation our fleet of leased trucks. Our crude oil gathering and marketing
activities provide us with an extensive expertise, knowledge base and skill set
that facilitates our ability to

capitalize on regional opportunities which arise from time to time in our market
areas. Usually this segment experiences limited commodity price risk because we
generally make back-to-back purchases and sales, matching our sale and purchase
volumes on a monthly basis.

The commodity price (for purchases and sales) of crude oil do not
necessarily bear a relationship to segment margin as those prices normally
impact revenues and costs of sales by approximately 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 our gathering and
marketing operations, these changes are not addressed in the following
discussion.

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.

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
Contracts will sometimes also contain a grade differential which considers the
chemical composition of the crude oil and its appeal to different customers.
Typically the pricing in a contract to sell crude oil will consist of the market
price components and the grade differentials. The margin on individual
transactions is then dependent on our ability to manage our transportation costs
and to capitalize on grade differentials.

Field operating costs consist of the costs to operate our fleet of
48 leased trucks used to transport crude oil, and the costs to maintain the
trucks and assets used in the crude oil gathering operation. Approximately 59%
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,
------------------------------------
2005 2004 2003
---------- ---------- ----------
(in thousands)

Revenues ............................................ $1,038,549 $ 901,902 $ 641,684
Crude oil costs ..................................... 1,018,896 883,988 622,279
Field operating costs ............................... 15,992 13,880 11,497
---------- ---------- ----------
Segment margin ................................ $ 3,661 $ 4,034 $ 7,908
========== ========== ==========

Volumes per day from continuing operations:

Crude oil wellhead - barrels .................. 39,194 45,919 45,015
Crude oil total - barrels (includes wellhead
barrels) ................................... 52,943 60,419 56,805
Crude oil truck transported only - barrels .... 3,084 1,742 662

Year Ended December 31, 2005 as Compared to Year Ended December 31,
2004

Crude oil gathering and marketing segment margins from continuing
operations decreased $0.4 million in 2005 from the prior year period. An
increase in field costs of $2.1 million was offset by $1.7 million of increased
segment margin from four other factors.

The majority of the increase in field costs over 2004 related to
higher fuel costs, higher employee costs and the costs related to additional
tractor/trailers we leased beginning in the third quarter of 2004. We also
recorded a

reserve of $0.5 million for 40% of the expected costs to remediate Jay Trucking
Station. (See additional discussion at Note 18 to the Consolidated Financial
Statements.)

Partially offsetting the higher field costs were increases in four
factors. These factors were:

- A $0.4 million increase in revenues from volumes that we
transported for a fee but did not purchase. Approximately 63%
of the total transportation fee revenue related to volumes
transported for Denbury. Through August 31, 2004, we purchased
Denbury's crude oil at the wellhead. Beginning in September
2004, Denbury started selling its production to the end-market
directly, and we provide transportation services for fees in
our trucks and in our pipeline.

- An increase in the average difference between the sales price
and the purchase price of crude oil increased segment margin
by $0.7 million, despite a 7,786 barrel per day decrease in
purchased volumes.

- A $0.4 million realized gain from a fair value hedge of
inventory. Due to market conditions in the second quarter, we
elected to hold inventory and hedge it in the market. We sold
this inventory in the fourth quarter realizing the gain.

- A $0.2 million decrease in credit costs related to crude oil
transactions.

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 market factors and
grade differentials in the first half of 2003 that we
benefited from significantly.

- 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.

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.

OTHER COSTS AND INTEREST

General and administrative expenses were as follows.

Years Ended December 31,
----------------------------
2005 2004 2003
------- ------- -------
(in thousands)

Expenses excluding effect of stock appreciation rights plan
and bonus plan ............................................. $ 8,903 $ 9,662 $ 8,411

Bonus plan expense ........................................... 1,235 218 129
Stock appreciation rights plan (credit) expense .............. (482) 1,151 228
------- ------- -------
Total general and administrative expenses .............. $ 9,656 $11,031 $ 8,768
======= ======= =======

Year Ended December 31, 2005 Compared with Year Ended December 31, 2004

General and administrative expenses, excluding the effects of our
bonus plan and stock appreciation rights (SAR) plan, decreased $0.8 million in
2005 from the 2004 level. In 2004, we incurred expenses of $1.3 million for
professional services to assist us in the internal control documentation and
assessment provisions of the Sarbanes-Oxley Act including additional audit fees
related to this process. In 2005 we formed an internal audit department to

assist in the testing and evaluation of our internal controls. The total costs
related to internal control documentation, testing and assessment declined $0.7
million between the two periods. Other administrative costs decreased $0.1
million.

The bonus plan for employees is described in Item 11, "Executive
Compensation" below. The plan provides for a bonus pool based on the amount of
Available Cash generated. In 2005, we generated more available cash than in
2004, resulting in a larger bonus expense.

The SAR plan for employees and directors is a long-term incentive
plan whereby rights are granted for the grantee to receive cash equal to the
difference between the grant price and common unit price at date of exercise.
The rights vest over several years. Our unit price was $12.60 at December 31,
2004. At December 31, 2005, the unit price was $11.65, resulting in a non-cash
credit of $0.5 million for 2005. (See Note 14 to the consolidated financial
statements.)

Year Ended December 31, 2004 Compared with Year Ended December 31, 2003

General and administrative expenses, excluding the effects of our
stock appreciation rights (SAR) plan, increased $1.3 million in 2004 from the
2003 level. The costs related to compliance with the internal control
documentation and assessment provisions of the Sarbanes-Oxley Act contributed to
this increase. Legal fees were $0.2 million less in the 2004 period, primarily
due to a charge that we took in the 2003 period for unamortized legal and
consultant costs related to a credit facility that was replaced. Other
administrative costs increased $0.2 million.

Our unit price rose 29% from $9.80 at December 31, 2003 to $12.60 at
December 31, 2004 resulting in a $1.2 million non-cash increase to the SAR plan
accrual in 2004.

Depreciation, amortization and impairment expense decreased $0.6
million between 2004 and 2005. 2004 included a charge of $0.9 million to
write-down the value of the segment of our Mississippi System from Baton Rouge
to its estimated salvage value. Although amortization related to the CO(2)
assets increased in 2005, this increase was offset by the cessation of
depreciation on assets that were fully-depreciated during 2003 and 2004.
Depreciation, amortization and impairment increased by $2.7 million in 2004 from
the 2003 level of $4.6 million, due to two main factors. The first is the
write-down related to the Mississippi System segment. We also had a full-year of
amortization of the CO(2) contracts in 2004 acquired late in 2003.

Interest expense, net was as follows:

Years Ended December 31,
-----------------------------
2005 2004 2003
------- ------- -------
(in thousands)

Interest expense, including commitment fees... $ 1,831 $ 743 $ 341
Capitalized interest ......................... (35) (76) -
Amortization and write-off of facility fees... 307 303 679
Interest income .............................. (71) (44) (34)
------- ------- -------
Net interest expense ................... $ 2,032 $ 926 $ 986
======= ======= =======

In 2005, our net interest expense increased by $1.1 million.
Variances in debt outstanding (primarily due to the acquisition of assets
throughout 2005), increases in market interest rates and an increase on June 1,
2004 to the size of our credit facility to $100 million resulted in greater
interest expense and commitment fees.

In 2004, our net interest expense decreased by $0.1 million.
Interest expense and commitment fees increased for reasons similar to the 2005
period. This increase was offset by a reduction in facility fees amortization
and write-off. In 2003, we wrote-off the unamortized facility fees related to a
credit facility that was replaced in March 2003.

At December 31, 2005, we had no outstanding debt. During 2006, we
will continue to amortize facility fees and will pay commitment fees on the
unutilized portion of our credit facility. Additionally market interest rates
may also increase in 2006. Debt obligations under our credit facility bear
interest at variable rates based on market interest rates.

Net gain/loss on disposal of surplus assets. In 2005, 2004 and 2003
we sold surplus assets no longer in use in our operations, recognizing gains in
2005 and 2003 of $0.5 million and $0.2 million, respectively and a loss in 2004
of $33,000.

DISCONTINUED OPERATIONS

In the fourth quarter of 2003, we sold a significant portion of our
Texas Pipeline System and the related crude oil gathering and marketing
operations to TEPPCO Crude Oil, L.P. Additionally we sold other segments of our
Texas Pipeline System that had been idled in 2002 to Blackhawk Pipeline, L.P.,
an affiliate of Multifuels, Inc. We abandoned in place other remaining segments
not sold to these parties in 2003.

We received net proceeds from the transaction with TEPPCO of $21.2
million. We agreed not to compete with TEPPCO in a 40-county area in Texas
surrounding the pipeline for a five-year period. We retained responsibility for
environmental matters related to the operations sold to TEPPCO for the period
prior to the sale date, subject to certain conditions. Our responsibility to
indemnify TEPPCO for environmental matters in connection with this transaction
will cease in ten years. We do not expect the effects of this indemnification to
have a material effect on our results of operations in the future.

Operating results from the discontinued operations for the years
ended December 31, 2005, 2004 and 2003 were as follows:

Year Ended December 31,
-------------------------------
2005 2004 2003
-------- -------- -------
(in thousands)

Gathering and marketing and pipeline revenues ..................... $ $ - $270,410
Costs and expenses, excluding depreciation and amortization ..... - 463 267,832
Depreciation and amortization ................................... - - 1,864
-------- -------- --------
Total costs and expenses .................................... - 463 269,696
-------- -------- --------
Operating (loss) income from discontinued operations ............ - (463) 714
Gain on disposal of assets ........................................ 312 - 13,028
-------- -------- --------
Income (loss) from operations from discontinued Texas System before
minority interests .............................................. $ 312 $ (463) $ 13,742
======== ======== ========

During 2005, we sold assets that had been idled as a result of the
sale to TEPPCO, receiving $0.3 million and recognizing a gain of $0.3 million.
During 2004, we incurred costs totaling $0.5 million related to the
dismantlement of assets that we abandoned in 2003. During 2003 we operated the
assets for ten months, recognizing income from these operations of $0.7 million.
When we sold the assets in 2003, we recognized a gain of $13.0 million.

CUMULATIVE EFFECT ADJUSTMENT

On December 31, 2005, we adopted FASB Interpretation No. 47,
"Accounting for Conditional Asset Retirement Obligations, an interpretation of
FASB Statement No. 143" (FIN 47). FIN 47 clarified that the term "conditional
asset retirement obligation", as used in SFAS No. 143, "Accounting for Asset
Retirement Obligations", refers to a legal obligation to perform an asset
retirement activity in which the timing and/or method of settlement are
conditional upon a future event that may or may not be within our control.
Although uncertainty about the timing and/or method of settlement may exist and
may be conditional upon a future event, the obligation to perform the asset
retirement activity is unconditional. Accordingly, we are required to recognize
a liability for the fair value of a conditional asset retirement obligation if
the fair value of the liability can be reasonably estimated.

Some of our assets, primarily related to our pipeline operations
segment, have obligations regarding removal activities when the asset is
abandoned. Additionally, we generally have obligations to remove crude oil
injection stations located on leased sites. These assets are actively in use in
our operations and the timing of the abandonment of these assets cannot be
determined. Accordingly, under the provisions of FIN 47, we have made an
estimate of the fair value of our obligations.

over the life of the related assets. The accretion of the discount on the
liability and the depreciation through December 31, 2005 were recorded in the
statement of operations as a cumulative effect adjustment totaling $0.5 million.
Additionally, we reflected our share of the asset retirement obligation recorded
in accordance with FIN 47 of our equity method joint venture as a cumulative
affect adjustment of $0.1 million.

See Note 4 to the Consolidated Financial Statements for the pro
forma impact for the periods ended December 31, 2005, 2004 and 2003 of the
adoption of FIN 47 if it had been adopted at the beginning of each of those
periods.

LIQUIDITY AND CAPITAL RESOURCES

CAPITAL RESOURCES

We have a $100 million credit facility comprised of a $50 million
revolving line of credit for acquisitions and a $50 million working capital
revolving facility. The working capital portion of the credit facility is
composed of two components - up to $15 million for loans and up to $35 million
for letters of credit. In total we may borrow up to $65 million in loans under
our credit facility. At December 31, 2005, we had $10.1 million in letters of
credit outstanding under the working capital portion. We had no debt outstanding
under the working capital or acquisition portions of our credit facility, as we
paid off the balances with the proceeds of our limited partner unit offering
completed in December 2005. Due to the revolving nature of loans under our
credit facility, additional borrowings and periodic repayments and re-borrowings
may be made until the maturity date of June 1, 2008.

Interest on amounts borrowed under the credit facility is equal to
(x) either the applicable Eurodollar settlement rate or the higher of the
Federal funds rate plus 1/2 of 1% or Bank of America's prime rate for the
relevant period, at our option, plus (y) the applicable margin rate. We are
required to pay our credit facility lenders a fee based upon amounts available
but not borrowed under each of the acquisition and working capital facilities,
as well as certain other fees.

The aggregate amount that we may have outstanding at any time in
loans and letters of credit under the working capital portion of our credit
facility is subject to a borrowing base calculation. The borrowing base is
limited to $50 million and is calculated monthly. At December 31, 2005, the
borrowing base was $33.0 million. The total amount available for borrowings at
December 31, 2005 was $15.0 million under the working capital portion and $50.0
million under the acquisition portion of our credit facility.

We must comply with various affirmative and negative covenants
contained in our credit facility. Among other things, those covenants limit our
ability to:

- incur additional indebtedness or liens;

- make payments in respect of or redeem or acquire any debt or equity
issued by us;

- sell assets;

- make loans or investments;

- extend credit;

- acquire or be acquired by other companies;

- enter into or amend certain existing agreements to the detriment of
the lenders under the credit facility; and

- to maintain physical petroleum inventory for which there is not an
off-setting sale or hedging agreement, subject to specified
exceptions.

Our credit facility covenants also require us to achieve specified
minimum financial metrics. For example, before we may make distributions to our
partners, we must maintain a cash flow coverage ratio of at least 1.1 to 1.0. In
general, this calculation compares operating cash inflows, as adjusted in
accordance with the credit facility, less maintenance capital expenditures, to
the sum of interest expense and distributions. At December 31, 2005, the
calculation resulted in a ratio of 1.3 to 1.0. The credit facility also requires
that the level of operating cash inflows during the prior twelve months, as
adjusted in accordance with the credit facility, be at least $8.5 million. At
December 31, 2005, the result of this calculation was $13.2 million. Our credit
facility also requires that we meet or exceed certain other financial ratios,
such as a current ratio, leverage ratio and funded indebtedness to
capitalization

ratio. If we meet these covenants and are not otherwise in default under our
credit facility, we are otherwise not limited by our credit facility in making
distributions to our partners.

The covenants described above could prevent us from engaging in
certain transactions which might otherwise be considered beneficial to us. For
example, they could:

- increase our vulnerability to general adverse economic and industry
conditions;

- limit our ability to make distributions to unitholders; to fund
future working capital, capital expenditures and other general
partnership requirements; to engage in future acquisitions,
construction or development activities; or to otherwise fully
realize the value of our assets and opportunities because of the
need to dedicate a substantial portion of our cash flow from
operations to payments on our indebtedness or to comply with any
restrictive terms of our indebtedness; and

- limit our flexibility in planning for, or reacting to, changes in
our businesses and the industries in which we operate.

Our credit facility contains customary events of default, including
for non-payment of principal and interest, failure to comply with any covenant
and failure to pay certain other of our indebtedness.

Our average daily outstanding balance under our credit facility
during 2005 was $19.2 million. The average interest rate we paid during this
same period was 7.29%.

Our credit facility is secured by liens on substantially all of our
assets.

CAPITAL EXPENDITURES

A summary of our capital expenditures in the three years ended
December 31, 2005, 2004, and 2003 is as follows:

Year Ended December 31,
---------------------------
2005 2004 2003
------- ------- -------
(in thousands)

Maintenance capital expenditures:
Mississippi pipeline system ................................. $ 1,147 $ 505 $ 1,684
Jay pipeline system ......................................... 7 28 213
Texas pipeline system ....................................... 102 122 1,588
Crude oil gathering assets .................................. 34 159 307
Administrative assets ....................................... 253 125 384
------- ------- -------
Total maintenance capital expenditures .................. 1,543 939 4,176

Growth capital expenditures (including construction in progress):
Mississippi pipeline system ................................. 1,059 7,371 76
Natural gas gathering assets ................................ 3,110 - -
T&P Syngas investment ....................................... 13,418 - -
CO(2) contracts ............................................. 14,446 4,723 24,401
Crude oil gathering assets .................................. 260 161 658
------- ------- -------
Total growth capital expenditures ....................... 32,292 12,255 25,135
------- ------- -------
Total capital expenditures .......................... $33,836 $13,194 $29,311
======= ======= =======

We have no commitments to make capital expenditures; however, we
anticipate that our maintenance capital expenditures for 2006 will be
approximately $1.5 million. These expenditures are expected to relate primarily
to the replacement of a tank on the Texas System and improvements on our
Mississippi System. Based on the information available to us at this time, we do
not anticipate that future capital expenditures for compliance with regulatory
requirements will be material.

Expenditures for capital assets to grow the partnership distribution
will depend on our access to debt and capital discussed below in "Sources of
Future Capital." We will look for opportunities to acquire assets from other

parties that meet our criteria for stable cash flows such as the three
acquisitions discussed in "Acquisitions in 2005" above.

SOURCES OF FUTURE CAPITAL

Our credit facility provides us with $50 million of capacity for
acquisitions and $15 million for borrowings under the working capital portion.
Both portions of the facility are revolving facilities. At December 31, 2005, we
had no debt outstanding under either facility.

We expect to use cash flows from operating activities to fund cash
distributions and maintenance capital expenditures needed to sustain existing
operations. Future acquisitions or capital projects for our expansion will
require funding through borrowings under our credit facility or from proceeds
from equity offerings, or a combination of the two sources of funds.

CASH FLOWS

Our primary sources of cash flows have been operations, credit
facilities, the issuance of equity, and in 2003, proceeds from the sale of a
portion of our operations. Our primary uses of cash flows are capital
expenditures and distributions. A summary of our cash flows is as follows:

Year Ended December 31,
--------------------------------
2005 2004 2003
-------- -------- --------
(in thousands)

Cash provided by (used in):
Operating activities ... $ 9,490 $ 9,702 $ 4,693
Investing activities ... $(31,809) $(12,805) $ (6,994)
Financing activities ... $ 23,340 $ 2,312 $ 4,099

Operating. Our operating cash flows are affected significantly by
changes in items of working capital. We have had situations where other parties
have prepaid for purchases or paid more than was due, resulting in fluctuations
in one period as compared to the next until the party recovers the excess
payment. Additionally, in 2004, we paid the $3.0 million in fines assessed in
connection with the Mississippi oil release in 1999, which utilized our cash
flows. The accrual for this payment was made in 2001 and 2002. The timing of
capital expenditures and the related effect on our recorded liabilities also
affects operating cash flows.

Our accounts receivable settle monthly and collection delays
generally relate only to discrepancies or disputes as to the appropriate price,
volume or quality of crude oil delivered. Of the $82.6 million aggregate
receivables on our consolidated balance sheet at December 31, 2005,
approximately $81.1 million, or 98.1%, were less than 30 days past the invoice
date.

Investing. We utilized cash flows in investing activities in 2005 by
making a $13.4 million investment in T&P Syngas, acquiring another CO(2)
contract for $14.4 million and making investments in property and equipment of
$6.1 million, including $3.1 million for the natural gas gathering assets
acquired from Multifuels. Offsetting these expenditures was the receipt of $1.6
million for the sale of idle assets. We also received returns of our investment
in T&P Syngas in the form of distributions totaling $0.4 million.

Cash flows used in investing activities in 2004 were $12.8 million
as compared to $7.0 million in 2003. Capital expenditures for construction of
pipeline assets and the acquisition of a second volumetric payment from Denbury
were the primary uses of cash for investing.

Cash flows used in investing activities in 2003 were $7.0 million.
In 2003 we sold portions of our Texas pipeline system as well as other assets
for $22.3 million net, and we expended $24.4 million to acquire the CO(2)
assets. Additionally we expended $4.9 million for other capital improvements.
These expenditures included improvements on our Mississippi pipeline system and
improvements totaling approximately $1.5 million on the Texas assets sold to
TEPPCO in October 2003 and other equipment improvements.

Financing. In 2005, financing activities provided net cash of $23.3
million. We issued 4,140,000 new limited partner units to the public and 330,630
new limited partner units to our general partner. Additionally, our general
partner contributed funds to maintain its 2% general partner interest. In total
these activities provided $44.8

million to us. A portion of these funds were utilized to eliminate our bank
debt, and we also paid distributions totaling $5.8 million to our limited
partners and our general partner during the year.

In 2004, financing activities provided net cash of $2.3 million.
Borrowings provided $8.8 million of cash flow. We utilized $0.8 million of these
funds to pay fees related to the Credit Agreement we obtained in June 2004.
Distributions to our partners utilized $5.7 million.

In 2003, financing activities provided net cash of $4.1 million. In
November 2003, our general partner acquired from us 688,811 newly-issued Common
Units for $4.9 million. We also increased our outstanding debt by $1.5 million.
We utilized $1.1 million of these funds to pay credit facility issuance fees.
Distributions to our partners utilized $1.3 million.

DISTRIBUTIONS

We are required by our partnership agreement to distribute 100% of
our available cash (as defined therein) within 45 days after the end of each
quarter to unitholders of record and to our general partner. Available cash
consists generally of all of our cash receipts less cash disbursements adjusted
for net changes to reserves. We increased our distribution for the fourth
quarter of 2004 and then again for the third and fourth quarters of 2005 as
shown in the table below.

Date Per Unit Total
Distribution For Paid Amount Amount (000's)
- -------------------- ------------- --------- -------------

Fourth quarter 2003 February 2004 $ 0.05 $ 475
First quarter 2004 May 2004 $ 0.05 $ 475
Second quarter 2004 August 2004 $ 0.05 $ 475
Third quarter 2004 November 2004 $ 0.05 $ 475
Fourth quarter 2004 February 2005 $ 0.15 $ 1,426
First quarter 2005 May 2005 $ 0.15 $ 1,426
Second quarter 2005 August 2005 $ 0.15 $ 1,426
Third quarter 2005 November 2005 $ 0.16 $ 1,521
Fourth quarter 2005 February 2006 $ 0.17 $ 2,391

Our general partner is entitled to receive incentive distributions
if the amount we distribute with respect to any quarter exceeds levels specified
in our partnership agreement. Under the quarterly incentive distribution
provisions, our general partner is entitled to receive 13.3% of any
distributions in excess of $0.25 per unit, 23.5% of any distributions in excess
of $0.28 per unit, and 49% of any distributions in excess of $0.33 per unit,
without duplication. The likelihood and timing of the payment of any incentive
distributions will depend on our ability to increase the cash flow from our
existing operations and to make cash flow accretive acquisitions. In addition,
our partnership agreement authorizes us to issue additional equity interests in
our partnership with such rights, powers and preferences (which may be senior to
our common units) as our general partner may determine in its sole discretion,
including with respect to the right to share in distributions and profits and
losses of the partnership. We have not paid any incentive distributions and do
not expect to make incentive distributions during 2006.

Available Cash before Reserves for the year ended December 31, 2005
is as follows (in thousands):

Net income.............................................................. $ 3,415
Depreciation and amortization........................................... 6,721
Cash received from direct financing leases not included in income....... 495
Cash effects from sales of certain asset sales.......................... 794
Effects of available cash generated by investment in T&P Syngas not
included in net income.............................................. 836
Non-cash charges........................................................ 418
Maintenance capital expenditures........................................ (1,543)
---------------
Available Cash before Reserves.......................................... $ 11,136
===============

We have reconciled Available Cash (a non-GAAP liquidity measure) to
cash flow from operating activities (the GAAP measure) for the year ended
December 31, 2005 below. For the year ended December 31, 2005, cash flows
provided by operating activities were $9.5 million.

NON-GAAP FINANCIAL MEASURE

This annual report includes the financial measures of Available
Cash, which measures often are referred to as "non-GAAP" measures because they
are not contemplated by or referenced in accounting principles generally
accepted in the U.S., also referred to as GAAP. The accompanying schedules
provide reconciliations of those non-GAAP financial measures to their most
directly comparable GAAP financial. Our non-GAAP financial measures should not
be considered as alternatives to GAAP measures such as net income, operating
income, cash flow from operating activities or any other GAAP measure of
liquidity or financial performance. We believe that investors benefit from
having access to the same financial measures being utilized by management,
lenders, analysts and other market participants.

Available Cash, also referred to as discretionary cash flow, is
commonly used as a supplemental financial measure by management and by external
users of financial statements, such as investors, commercial banks, research
analysts and rating agencies, to assess: (1) the financial performance of our
assets without regard to financing methods, capital structures or historical
cost basis; (2) the ability of our assets to generate cash sufficient to pay
interest cost and support our indebtedness; (3) our operating performance and
return on capital as compared to those of other companies in the midstream
energy industry, without regard to financing and capital structure; and (4) the
viability of projects and the overall rates of return on alternative investment
opportunities. Because Available Cash excludes some, but not all, items that
affect net income or loss and because these measures may vary among other
companies, the Available Cash data presented in this Annual Report on Form 10-K
may not be comparable to similarly titled measures of other companies. The GAAP
measure most directly comparable to Available Cash is net cash provided by
operating activities.

Available Cash is a liquidity measure used by our management to
compare cash flows generated by us to the cash distribution paid to our limited
partners and general partner. This is an important financial measure to our
public unitholders since it is an indicator of our ability to provide a cash
return on their investment. Specifically, this financial measure aids investors
in determining whether or not we are generating cash flows at a level that can
support a quarterly cash distribution to the partners. Lastly, Available Cash
before Reserves (also referred to as distributable cash flow) is the
quantitative standard used throughout the investment community with respect to
publicly-traded partnerships.

The reconciliation of Available Cash (a non-GAAP liquidity measure)
to cash flow from operating activities (the GAAP measure) for the year ended
December 31, 2005, is as follows (in thousands):

Year
Ended
December 31,
2005
------------

Cash flows from operating activities ........................................ $ 9,490
Adjustments to reconcile operating cash flows to Available Cash:
Maintenance capital expenditures ...................................... (1,543)
Proceeds from sales of certain assets ................................. 1,585
Amortization of credit facility issuance fees ......................... (373)
Effects of available cash generated by investment in T&P Syngas not
included in cash flows from operating activities .................. 848
Cash effects of exercises under SAR Plan .............................. (61)
Net effect of changes in operating accounts not included in calculation
of Available Cash ................................................. 1,190
------------
Available Cash before Reserves .............................................. $ 11,136
============

COMMITMENTS AND OFF-BALANCE SHEET ARRANGEMENTS

CONTRACTUAL OBLIGATION AND COMMERCIAL COMMITMENTS

In addition to our credit facility discussed above, we have
contractual obligations under operating leases as well as commitments to
purchase crude oil. The table below summarizes our obligations and commitments
at December 31, 2005.

Payments Due by Period
---------------------------------------------------
2007 and 2009 and After
Contractual Cash Obligations 2006 2008 2010 2010 Total
- ---------------------------- -------- -------- -------- -------- -------
(in thousands)

Long-term Debt(1) ................... $ - $ - $ - $ - $ -
Operating Leases .................... 2,816 4,886 2,696 364 10,762
Unconditional Purchase
Obligations (2) ............... 127,338 65,446 - - 192,784
-------- -------- -------- -------- --------
Total Contractual Cash Obligations... $130,154 $ 70,332 $ 2,696 $ 364 $203,546
======== ======== ======== ======== ========

(1) We had no balance outstanding under our credit facility at December 31,
2005. The credit facility allows us to repay and re-borrow funds at any
time through the maturity of the facility at June 1, 2008.

(2) The unconditional purchase obligations included above are contracts to
purchase crude oil, generally at market-based prices. For purposes of this
table, market prices at December 31, 2005, were used to value the
obligations. Actual obligations may differ from the amounts included
above.

OFF-BALANCE SHEET ARRANGEMENTS

We have no off-balance sheet arrangements, special purpose entities,
or financing partnerships, other than as disclosed under Contractual Obligation
and Commercial Commitments above, nor do we have any debt or equity triggers
based upon our unit or commodity prices.

OTHER MATTERS

CRUDE OIL CONTAMINATION LITIGATION

We were named one of the defendants in a petition filed on January
11, 2001, in the 125th District Court of Harris County, Texas, Cause No.
2001-01176. Pennzoil-Quaker State Company ("PQS") was seeking property damages,
loss of use and business interruption suffered as a result of a fire and
explosion that occurred at the Pennzoil Quaker State refinery in Shreveport,
Louisiana, on January 18, 2000. PQS claimed the fire and explosion were caused,
in part, by Genesis selling to PQS crude oil that was contaminated with organic
chlorides. In December 2003, our insurers settled this litigation for $12.8
million. The settlement of this litigation had no effect on our results of
operations.

PQS is also a defendant in five consolidated class action/mass tort
actions brought by neighbors living in the vicinity of the PQS Shreveport,
Louisiana refinery in the First Judicial District Court, Caddo Parish,
Louisiana, Cause Nos. 455,647-A. 455,658-B, 455,655-A, 456,574-A, and 458,379-C.
PQS has brought third party claims against Genesis and others for indemnity with
respect to the fire and explosion of January 18, 2000. We believe that the
claims against Genesis are without merit and intend to vigorously defend
ourselves in this matter.

ENVIRONMENTAL

In 1992, Howell Crude Oil Company entered into a sublease with Koch
Industries, Inc., covering a one acre tract of land located in Santa Rosa
County, Florida to operate a crude oil trucking station, known as Jay Station.
The sublease provided that Howell would indemnify Koch for environmental
contamination on the property under certain circumstances. Howell operated the
Jay Station from 1992 until December of 1996 when this operation was sold to us
by Howell. We operated the Jay Station as a crude oil trucking station until
2003. Koch has indicated that it has incurred certain investigative and/or other
costs, for which Koch alleges some or all should be reimbursed by us, under the
indemnification provisions of the sublease for environmental contamination on
the site and surrounding areas. Koch has also alleged that we are responsible
for future environmental obligations relating to the Jay Station.

Howell was acquired by Anadarko Petroleum Corporation (Anadarko) in 2002.
During the second quarter of 2005, we entered into a joint defense and cost
allocation agreement with Anadarko. Under the terms of the joint allocation
agreement, we agreed to reasonably cooperate with each other to address any
liabilities or defense costs with respect to the Jay Station. Additionally under
the Joint Allocation Agreement, Anadarko will be responsible for sixty percent
of the costs related to any liabilities or defense costs incurred with respect
to contamination at the Jay Station.

We were formed in 1996 by the sale and contribution of assets from Howell
and Basis Petroleum, Inc. Anadarko's liability with respect to the Jay Station
is derived largely from contractual obligations entered into upon our formation.
We believe that Basis has contractual obligations under the same formation
agreements. We intend to seek recovery for Basis' share of potential liabilities
and defense costs with respect to the Jay Station.

We have contacted the appropriate state regulatory agencies regarding
developing a plan of remediation for certain affected soils at the Jay Station.
It is possible that we will also need to develop a plan for other affected soils
and/or affected groundwater. We have accrued an estimate of our share of future
liability for this matter in the amount of $0.5 million. The time period over
which our liability would be paid is uncertain and could be several years. This
liability may decrease if indemnification and/or cost reimbursement is obtained
by us for Basis' potential liabilities with respect to this matter. At this
time, our estimate of potential obligations does not assume any specific amount
contributed on behalf of the Basis obligations, although we believe that Basis
is responsible for a significant part of these potential obligations.

INSURANCE

We maintain insurance of various types that we consider adequate to cover
our operations and properties. The insurance policies are subject to deductibles
that we consider reasonable. The policies do not cover every potential risk
associated with operating our assets, including the potential for a loss of
significant revenues. Consistent with the coverage available in the industry,
our policies provide limited pollution coverage, with broader coverage for
sudden and accidental pollution events. Additionally, as a result of the events
of September 11, 2001, the cost of insurance available to the industry has risen
significantly, and insurers have excluded or reduced coverage for losses due to
acts of terrorism and sabotage.

Since September 11, 2001, warnings have been issued by various agencies of
the United States Government to advise owners and operators of energy assets
that those assets may be a future target of terrorist organizations. Any future
terrorist attacks on our assets, or assets of our customers or competitors could
have a material adverse effect on our business.

We believe that we are adequately insured for public liability and
property damage to others as a result of our operations. However, we cannot
assure you that an event not fully insured or indemnified against will not
materially and adversely affect our operations and financial condition.
Additionally, we cannot assure you that we will be able to maintain insurance in
the future at rates that we consider reasonable.

NEW AND PROPOSED ACCOUNTING PRONOUNCEMENTS

EITF NO. 04-13

In September 2005, the Emerging Issues Task Force (EITF) of the Financial
Accounting Standards Board (FASB) reached consensus in the issue of accounting
for buy/sell arrangements as part of its EITF Issue No. 04-13, "Accounting for
Purchases and Sales of Inventory with the Same Counterparty" (Issue 04-13). As
part of Issue 04-13, the EITF is requiring that all buy/sell arrangements be
reflected on a net basis, such that the purchase and sale are netted and shown
as either a net purchase or a net sale in the income statement. This requirement
is effective for new arrangements entered into after March 31, 2006. If this
requirement had been effective for the three years ended December 31, 2005, 2004
and 2003, our reported crude oil gathering and marketing revenues from unrelated
parties and our reported crude oil costs from unrelated parties would be reduced
by the amounts shown in parenthetical notations on the consolidated statements
of operations. We do not expect that the adoption of Issue 04-13 will have a
material effect on our financial position, results of operations or cash flows.

SFAS 123(R)

In December 2004, the FASB issued SFAS No. 123 (revised December 2004),
"Share-Based Payment". This statement replaces SFAS No. 123 and requires that
compensation costs related to share-based payment

transactions be recognized in the financial statements. This statement is
effective for us in the first quarter of 2006. The adoption of this statement
will require that the compensation cost associated with our stock appreciation
rights plans be re-measured each reporting period based on the fair value of the
rights. Before the adoption of SFAS 123 (R), we accounted for the stock
appreciation rights in accordance with FASB Interpretation No. 28, "Accounting
for Stock Appreciation Rights and Other Variable Stock Option or Award Plans"
which required that the liability under the plan be measured at each balance
sheet date based on the market price of our common units on that date. Under
SFAS 123 (R), the liability will be calculated using a fair value method that
will take into consideration the expected future value of the rights at their
expected exercise dates.

At December 31, 2005, we had a recorded liability of $0.8 million,
computed under the provisions of FASB Interpretation No. 28. Two significant
factors in determining the fair value of this liability under FAS 123(R) are the
expected volatility of the market price for our common units, which we expect to
increase the recorded liability, and the expected rate of employee forfeitures
of rights granted due to termination of employment, which is expected to
decrease the liability. Another factor impacting the fair value is the expected
life of the rights, which is the period of time we would expect between the date
when the rights vest and when the employee exercises the rights. We have not
completed the calculation of the impact of the adoption of FAS 123(R) on our
financial position or results of operations and such impact cannot be estimated;
however we do not expect it to have any effect on our cash flows.

SFAS 154

In May 2005, the FASB issued Statement of Financial Standards No. 154,
"Accounting Changes and Error Corrections" (SFAS 154). This statement
establishes new standards on the accounting for and reporting of changes in
accounting principles and error corrections. SFAS 154 requires retrospective
application to the financial statements of prior periods for all such changes,
unless it is impracticable to do so. SFAS 154 is effective for us in the first
quarter of 2006.

ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risks primarily related to volatility in crude oil
prices and interest rates.

Our primary price risk relates to the effect of crude oil price fluctuations
on our inventories and the fluctuations each month in grade and location
differentials and their effect on future contractual commitments. We utilize
NYMEX commodity based futures contracts and forward contracts to hedge our
exposure to these market price fluctuations as needed. At December 31, 2005, we
had entered into forward contracts and NYMEX future contracts that will settle
during February 2006. These contracts either do not qualify for hedge accounting
or are fair value hedges, therefore the fair value of these derivatives have
received mark-to-market treatment in current earnings. This accounting treatment
is discussed further under Note 2 to our Consolidated Financial Statements.

Sell (Short) Buy (Long)
Contracts Contracts
----------- ---------------

Futures Contracts
Contract volumes (1,000 bbls)......................... 30
Weighted average price per bbl........................ $ 57.90

Contract value (in thousands)......................... $ 1,737
Mark-to-market change (in thousands).................. 94
-----------
Market settlement value (in thousands)................ $ 1,831
===========

Forward Contracts
Contract volumes (1,000 bbls)......................... 30 60
Weighted average price per bbl........................ $ 58.17 57.58

Contract value (in thousands)......................... $ 1,745 3,455
Mark-to-market change (in thousands).................. 86 192
----------- -----
Market settlement value (in thousands)................ $ 1,831 3,647
=========== =====

The table above presents notional amounts in barrels, the weighted average
contract price, total contract amount and total fair value amount in U.S.
dollars. Fair values were determined by using the notional amount in barrels
multiplied by the December 31, 2005 quoted market prices on the NYMEX.

We are also exposed to market risks due to the floating interest rates on our
credit facility. Our debt bears interest at the LIBOR or prime rate plus the
applicable margin. We do not hedge our interest rates. At December 31, 2005, we
had no debt outstanding under our credit facility.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required hereunder is included in this report as set forth in
the "Index to Consolidated Financial Statements" on page 67.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures and internal controls designed
to ensure that information required to be disclosed in our filings under the
Securities Exchange Act of 1934 is recorded, processed, summarized and reported
within the time periods specified in the Securities and Exchange Commission's
rules and forms. Our chief executive officer and chief financial officer, with
the participation of our management, have evaluated our disclosure controls and
procedures as of the end of the period covered by this Annual Report on Form
10-K and have determined that such disclosure controls and procedures are
adequate and effective in all material respects in providing to them on a timely
basis material information relating to us (including our consolidated
subsidiaries) required to be disclosed in this annual report.

There were no changes during our last fiscal quarter that materially
affected, or are reasonably likely to materially affect, our internal control
over financial reporting.

Management's Report on Internal Control over Financial Reporting

Management of the Partnership is responsible for establishing and maintaining
effective internal control over financial reporting as defined in Rules
13a-15(f) under the Securities and Exchange Act of 1934. The Partnership's
internal control over financial reporting is designed to provide reasonable
assurance to the Partnership's management and board of directors regarding the
preparation and fair presentation of published financial statements.

Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect to
financial statement preparation and presentation.

Management assessed the effectiveness of the Partnership's internal control
over financial reporting as of December 31, 2005. In making this assessment,
management used the criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. Based on our assessment, we believe that, as of December 31, 2005,
the Partnership's internal control over financial reporting is effective based
on those criteria.

Management's assessment of the effectiveness of internal control over
financial reporting as of December 31, 2005, has been audited by Deloitte &
Touche LLP, the independent registered public accounting firm who also audited
the Partnership's consolidated financial statements. Deloitte & Touche's
attestation report on management's assessment of the Partnership's internal
control over financial reporting appears below.

Report of Independent Registered Public Accounting Firm on Internal Control
over Financial Reporting

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Genesis Energy, Inc. and Unitholders of
Genesis Energy, L.P.
Houston, Texas

We have audited management's assessment, included in the accompanying
Management's Report on Internal Control over Financial Reporting, that Genesis
Energy, L.P. and subsidiaries (the "Partnership") maintained effective internal
control over financial reporting as of December 31, 2005, based on criteria
established in Internal Control -- Integrated Framework issued by the Committee
of Sponsoring Organizations of the Treadway Commission. The Partnership's
management is responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal
control over financial reporting. Our responsibility is to express an opinion on
management's assessment and an opinion on the effectiveness of the Partnership's
internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, evaluating management's assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by,
or under the supervision of, the company's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
company's board of directors, management, and other personnel to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial
reporting, including the possibility of collusion or improper management
override of controls, material misstatements due to error or fraud may not be
prevented or detected on a timely basis. Also, projections of any evaluation of
the effectiveness of the internal control over financial reporting to future
periods are subject to the risk that the controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.

In our opinion, management's assessment that the Partnership maintained
effective internal control over financial reporting as of December 31, 2005, is
fairly stated, in all material respects, based on the criteria established in
Internal Control -- Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Also in our opinion, the Partnership
maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2005, based on the criteria established in Internal
Control -- Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the consolidated financial
statements as of and for the year ended December 31, 2005 of the Partnership and
our report dated March 7, 2006, expressed an unqualified opinion on those
financial statements, and included an explanatory paragraph relating to the
required adoption of a new accounting principle for accounting for conditional
asset retirement obligations.

/s/ DELOITTE & TOUCHE LLP
Houston, Texas

March 7, 2006

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

We do not directly employ any persons responsible for managing or operating
the Partnership or for providing services relating to day-to-day business
affairs. The general partner provides such services and is reimbursed for its
direct and indirect costs and expenses, including all compensation and benefit
costs.

The Board of Directors of the general partner (the "Board") consists of eight
persons. Four of the directors, including the Chairman of the Board, are
executives of Denbury. Our Chief Executive Officer serves on the Board. The
three remaining directors are independent of Genesis and Denbury or any of its
affiliates.

Directors and Executive Officers of the General Partner

Set forth below is certain information concerning the directors and
executive officers of the general partner. All executive officers serve at the
discretion of the general partner.

Name Age Position
- ----------------------------- --- ------------------------------------------------------

Gareth Roberts................ 53 Director and Chairman of the Board
Mark J. Gorman................ 51 Director, Chief Executive Officer and President
Ronald T. Evans............... 43 Director
Herbert I. Goodman............ 83 Director
Susan O. Rheney............... 46 Director
Phil Rykhoek.................. 49 Director
J. Conley Stone............... 74 Director
Mark A. Worthey............... 48 Director
Ross A. Benavides............. 52 Chief Financial Officer, General Counsel and Secretary
Kerry W. Mazoch............... 59 Vice President, Crude Oil Acquisitions
Karen N. Pape................. 47 Vice President and Controller

Gareth Roberts has served as a Director and Chairman of the Board of our
general partner since May 2002. Mr. Roberts is President, Chief Executive
Officer and a director of Denbury Resources Inc. and has been employed by
Denbury since 1992.

Mark J. Gorman has served as a Director of our general partner since
December 1996 and as President and Chief Executive Officer since October 1999.
From December 1996 to October 1999 he served as Executive Vice President and as
Chief Operating Officer from October 1997 to October 1999. He was President of
Howell Crude Oil Company, a wholly-owned subsidiary of Howell Corporation, from
September 1992 to December 1996.

Ronald T. Evans has served as a director of our general partner since May
2002. Mr. Evans is Senior Vice President of Reservoir Engineering of Denbury and
has been employed by Denbury since September 1999. Before

joining Denbury, Mr. Evans was employed as Engineering Manager with Matador
Petroleum Corporation for three years and employed by Enserch Exploration, Inc.
for twelve years in various positions.

Herbert I. Goodman has served as a director of our general partner since
January 1997. During 2001, he served as the Chief Executive Officer of
PEPEX.NET, LLC, which provides electronic trading solutions to the international
oil industry. From 2002 to 2005, he served as Chairman of PEPEX.NET, LLC. He was
Chairman of IQ Holdings, Inc., a manufacturer and marketer of
petrochemical-based consumer products until 2004. From 1988 until 1996 he was
Chairman and Chief Executive Officer of Applied Trading Systems, Inc., a trading
and consulting business.

Susan O. Rheney has served as a Director of our general partner since
March 2002. Ms. Rheney is a private investor and formerly was a principal of The
Sterling Group, L.P., a private financial and investment organization, from 1992
to 2000.

Phil Rykhoek has served as a director of our general partner since May
2002. Mr. Rykhoek is Chief Financial Officer, Senior Vice President, Secretary
and Treasurer of Denbury, and has been employed by Denbury since 1995.

J. Conley Stone has served as a director of our general partner since
January 1997. From 1987 to his retirement in 1995, he served as President, Chief
Executive Officer, Chief Operating Officer and Director of Plantation Pipe Line
Company, a common carrier liquid petroleum products pipeline transporter.

Mark A. Worthey has served as a director of our general partner since May
2002. Mr. Worthey is Senior Vice President, Operations for Denbury and has been
employed by Denbury since September 1992.

Ross A. Benavides has served as Chief Financial Officer of our general
partner since October 1998. He has served as General Counsel and Secretary since
December 1999.

Kerry W. Mazoch has served as Vice President, Crude Oil Acquisitions, of
our general partner since August 1997. From 1991 to 1997 he held the position of
Vice President and General Manager of Crude Oil Acquisitions at Northridge
Energy Marketing Corp., a wholly-owned subsidiary of TransCanada Pipelines
Limited.

Karen N. Pape has served as Vice President and Controller of our general
partner since March 2002. Ms. Pape served as Controller and as Director of
Finance and Administration of our general partner since December 1996. From 1990
to 1996, she was Vice President and Controller of Howell Corporation.

Board Committees

The Audit Committee consists of Susan O. Rheney, Herbert I. Goodman and J.
Conley Stone. The Audit Committee has been established in accordance with SEC
rules and regulations, and all members are independent directors as defined
under the rules of the American Stock Exchange. The Board of Directors believes
that Susan O. Rheney qualifies as an audit committee financial expert as such
term is used in the rules and regulations of the SEC. The committee engages our
independent auditors and oversees our independence from the auditors,
pre-approves any services provided by our independent auditors, oversees the
quality and integrity of our financial reports and our systems of internal
controls with respect to finance, accounting, legal compliance and ethics, and
oversees our anonymous complaint procedure established for our employees. The
Audit Committee adopted a written Audit Committee charter on August 7, 2003. The
full text of the Audit Committee charter is available on our website.

Additionally, our general partner is authorized to seek special approval from
the Audit Committee of any resolution of a potential conflict of interest
between our general partner or of any of its affiliates and the Partnership or
any of its affiliates.

The Board has established a compensation committee to oversee compensation
decisions for the employees of the general partner, as well as the compensation
plans of our general partner. The members of the Compensation Committee are
Gareth Roberts, Susan O. Rheney and Herbert I. Goodman, all of whom are
non-employee directors of our general partner.

Code of Ethics

We have adopted a code of ethics that is applicable to, among others, the
principal financial officer and the principal accounting officer. The Genesis
Energy Financial Employee Code of Professional Conduct is posted at our website,
where we intend to report any changes or waivers.

Section 16(a) Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires the officers
and directors of our general partner and persons who own more than ten percent
of a registered class of the equity securities of the Partnership to file
reports of ownership and changes in ownership with the SEC and the American
Stock Exchange. Based solely on its review of the copies of such reports
received by it, or written representations from certain reporting persons that
no Forms 5 was required for those persons, we believe that during 2005 its
officers and directors complied with all applicable filing requirements in a
timely manner.

ITEM 11. EXECUTIVE COMPENSATION

EXECUTIVE OFFICER COMPENSATION

Under the terms of our partnership agreement, we are required to reimburse
our general partner for expenses relating to the operation of the Partnership,
including salaries and bonuses of employees employed on behalf of the
Partnership, as well as the costs of providing benefits to such persons under
employee benefit plans and for the costs of health and life insurance. See
"Certain Relationships and Related Transactions."

Summary Compensation Table

The following table summarizes certain information regarding the compensation
paid or accrued by Genesis during 2005, 2004, and 2003 to the Chief Executive
Officer and each of our three other executive officers (the "Named Officers").

Annual Compensation Long-Term
------------------------------ Compensation
Awards
----------
Securities
Other Annual underlying All Other
Salary Bonus Compensation SARs Granted (2) Compensation
Name and Principal Position Year $ $ $ (1) # $
- --------------------------- ------ -------- ------ ------------ ---------------- -------------

Mark J. Gorman 2005 275,000 66,000 2,865 5,968 15,900 (3)
Chief Executive Officer 2004 275,000 6,793 66,810 5,615 15,150 (4)
and President 2003 275,000 4,070 12,755 23,620 15,174 (5)

Ross A. Benavides 2005 185,000 44,400 1,927 4,015 14,368 (6)
Chief Financial Officer, 2004 185,000 4,570 44,942 3,777 14,230 (7)
General Counsel and
Secretary 2003 185,000 2,738 8,580 15,889 13,977 (8)

Kerry W. Mazoch 2005 175,000 42,000 1,823 3,798 13,474 (9)
Vice President, Crude 2004 175,000 4,323 42,513 3,573 13,392 (10)
Oil Acquisitions 2003 175,000 2,590 8,116 15,030 13,197 (11)

Karen N. Pape 2005 141,500 33,960 1,474 3,071 11,025 (12)
Vice President and 2004 141,500 3,495 34,375 2,889 10,920 (13)
Controller 2003 141,500 2,094 6,563 12,153 10,707 (14)

(1) Represents the value deemed to have been "earned" during the year under
the Stock Appreciation Rights Plan discussed below. No Named Officer had
other "Perquisites and Other Personal Benefits" with a value greater than
the lesser of $50,000 or 10% of reported salary and bonus.

(2) SARs are Stock Appreciation Rights. See additional information in the
table below.

(3) Includes $9,450 of Company-matching contributions to a defined
contribution plan, $6,300 of profit-sharing contributions to a defined
contribution plan and $150 for annual term life insurance premiums.

(4) Includes $9,000 of Company-matching contributions to a defined
contribution plan, $6,000 of profit-sharing contributions to a defined
contribution plan and $150 for annual term life insurance premiums.

(5) Includes $9,000 of Company-matching contributions to a defined
contribution plan, $6,000 of profit-sharing contributions to a defined
contribution plan and $174 for annual term life insurance premiums.

(6) Includes $8,531 of Company-matching contributions to a defined
contribution plan, $5,687 of profit-sharing contributions to a defined
contribution plan and $150 for annual term life insurance premiums.

(7) Includes $8,448 of Company-matching contributions to a defined
contribution plan, $5,632 of profit-sharing contributions to a defined
contribution plan and $150 for annual term life insurance premiums.

(8) Includes $8,282 of Company-matching contributions to a defined
contribution plan, $5,521 of profit-sharing contributions to a defined
contribution plan and $174 for annual term life insurance premiums.

(9) Includes $7,944 of Company-matching contributions to a defined
contribution plan, $5,380 of profit-sharing contributions to a defined
contribution plan and $150 for annual term life insurance premiums.

(10) Includes $7,914 of Company-matching contributions to a defined
contribution plan, $5,328 of profit-sharing contributions to a defined
contribution plan and $150 for annual term life insurance premiums.

(11) Includes $7,802 of Company-matching contributions to a defined
contribution plan, $5,221 of profit-sharing contributions to a defined
contribution plan and $174 for annual term life insurance premiums.

(12) Includes $6,525 of Company-matching contributions to a defined
contribution plan, $4,350 of profit-sharing contributions to a defined
contribution plan and $150 for annual term life insurance premiums.

(13) Includes $6,462 of Company-matching contributions to a defined
contribution plan, $4,308 of profit-sharing contributions to a defined
contribution plan and $150 for annual term life insurance premiums.

(14) Includes $6,320 of Company matching contributions to a defined
contribution plan, $4,213 of profit-sharing contributions to a defined
contribution plan and $174 for annual term life insurance premiums.

Stock Appreciation Rights Plan

In December 2003, the Board approved a Stock Appreciation Rights plan
(SAR) for all employees. Under the terms of this plan, all regular, full-time
active employees and the members of the Board are eligible to participate in the
plan. The plan is administered by the Compensation Committee of the Board, who
shall determine, in its full discretion, the number of rights to award, the
grant date of the units and the formula for allocating rights to the
participants and the strike price of the rights awarded. Each right is
equivalent to one common unit. The rights have a term of 10 years from the date
of grant. The initial award to a participant will vest one-fourth each year
beginning with the first anniversary of the grant date of the award. Subsequent
awards to participants will vest on the fourth anniversary of the grant date. If
the right has not been exercised at the end of the ten year term and the
participant has not terminated employment with us, the right will be deemed
exercised as of the date of the right's expiration and a cash payment will be
made as described below.

Upon vesting, the participant may exercise his rights to receive a cash
payment equal to the difference between the average of the closing market price
of our common units for the ten days preceding the date of exercise over the
strike price of the right being exercised. The cash payment to the participant
will be net of any applicable withholding taxes required by law. If the
Committee determines, in its full discretion, that it would cause significant
financial harm to the Partnership to make cash payments to participants who have
exercised rights under the plan, then the Committee may authorize deferral of
the cash payments until a later date.

Termination for any reason other than death, disability or normal
retirement (as these terms are defined in the plan) will result in the
forfeiture of any non-vested rights. Upon death, disability or normal
retirement, all rights will become fully vested. If a participant is terminated
for any reason within one year after the effective date of a change in control
(as defined in the plan) all rights will become fully vested.

The following tables show the stock appreciation rights granted to the
Executive Officers and the values of the stock appreciation rights at December
31, 2005. Information on rights granted to non-employee directors is included in
the section entitled Director Compensation.

SAR Grants During the Year Ended December 31, 2005

Individual Grants
- -------------------------------------------------------------------------------
Number of Percent Grant Potential realizable value at
Securities of total date assumed annual rates of
underlying SARs granted Exercise closing stock price appreciation
SARs to employees price price Expiration for SAR term
-----------------------------
Name granted (#) in fiscal year $/Unit $/Unit date 5% ($) 10% ($)
- ----------------- ----------- -------------- --------- ------- ----------- ------------ ------------

Mark J. Gorman 5,968 5.9 % 11.17 11.65 12/31/2015 41,924 106,243
Ross A. Benavides 4,015 4.0 % 11.17 11.65 12/31/2015 28,204 71,475
Kerry W. Mazoch 3,798 3.8 % 11.17 11.65 12/31/2015 26,680 67,612
Karen N. Pape 3,071 3.0 % 11.17 11.65 12/31/2015 21,573 54,670

December 31, 2005 SAR Values (1)

Number of Common Units Value of
underlying unexercised unexercised in-the-money
SARs at December 31, 2005 (#) SARs at December 31, 2005 ($)
------------------------------- -------------------------------
Name Exercisable Unexercisable Exercisable Unexercisable
- ----------------- ------------ ------------- ------------ --------------

Mark J. Gorman 11,810 23,393 28,226 31,091
Ross A. Benavides 7,945 15,737 18,987 20,915
Kerry W. Mazoch 7,515 14,886 17,961 19,784
Karen N. Pape 6,077 12,037 14,523 15,997

(1) None of the executive officers exercised any SARs during 2005.

Bonus Plan

In May 2003, the Compensation Committee of the Board of our general
partner approved a Bonus Plan (the "Bonus Plan") for all employees of our
general partner. The Bonus Plan is designed to enhance the financial performance
of the Partnership by rewarding employees for achieving financial performance
objectives. The Bonus Plan is administered by the Compensation Committee. Under
this plan, amounts will be allocated for the payment of bonuses to employees
each time our operating partnership earns $1.6 million of Available Cash before
bonus expense. The amount allocated to the bonus pool increases for each $1.6
million earned, such that a maximum bonus pool of $2.3 million will exist if the
Partnership earns $14.6 million of Available Cash. Beginning in 2006, the amount
our operating partnership must earn will be increased to $2.0 million of
Available Cash before bonus expense.

Bonuses will be paid to employees after the end of the year. The amount in
the bonus pool will be allocated to employees based on the group to which they
are assigned. Employees in the first group can receive bonuses that range from
zero to ten percent of base compensation. The next group includes employees who
could earn a total bonus ranging from zero to twenty percent. Certain members
are eligible to earn a total bonus ranging from zero to thirty percent. Lastly,
our officers and other senior management are eligible for a total bonus ranging
from zero to forty percent. The Bonus Plan will be at the discretion of the
Compensation Committee, and our general partner can amend or change the Bonus
Plan at any time.

Severance Protection Plan

In June 2005, the Compensation Committee of the Board of Directors of our
general partner approved the Genesis Energy Severance Protection Plan (the
"Severance Plan") for employees of our general partner. The Severance Plan
provides that a participant in the Plan is entitled to receive a severance
benefit if his employment is terminated during the period beginning six months
prior to a change in control and ending two years after a change in control, for
any reason other than (x) termination by our general partner for cause or (y)
termination by the participant for other than good reason. Termination by the
participant for other than good reason would be triggered by a change in job
status, a reduction in pay, or a requirement to relocate more than 25 miles.

A change in control is defined in the Severance Plan. Generally, a
change in control is a change in the control of Denbury, a disposition by
Denbury of more than 50% of our general partner, or a transaction involving the
disposition of substantially all of the assets of Genesis.

The amount of severance is determined separately for three classes of
participants. The first class, which includes the Chief Executive Officer and
two other Executive Officers of Genesis, would receive a severance benefit equal
to three times that participant's annual salary and bonus amounts. The second
class, which includes the other Executive Officer of Genesis as well as certain
other members of management, would receive a severance benefit equal to two
times that participant's salary and bonus amounts. The third class of
participant would receive a severance benefit based on the participant's salary
and bonus amounts and length of service. Participants would also receive certain
medical and dental benefits.

DIRECTOR COMPENSATION

Information regarding the compensation received from the general partner
by Mr. Gorman, President, Chief Executive Officer and a director of the general
partner, is disclosed under the heading "Executive Officer Compensation".

Directors Fees

The three independent directors receive an annual fee of $30,000. The
Audit Committee Chairman receives an additional annual fee of $4,000 and all
members of the Audit Committee receive $1,500 for attendance at each committee
meeting. Denbury receives $120,000 from the Partnership for providing four of
its executives as directors. Mr. Gorman does not receive a fee for serving as a
director.

Stock Appreciation Rights

The non-employee directors received stock appreciation rights under the
same terms as the Executive Officers. Grants issued to directors during 2005
were:

Number of
Securities
underlying Exercise
SARs price Expiration
Name granted (#) $/Unit date
- ------------------ ----------- ---------- -----------

Gareth Roberts 651 11.17 12/31/2015
Ronald T. Evans 651 11.17 12/31/2015
Herbert I. Goodman 781 11.17 12/31/2015
Susan O. Rheney 868 11.17 12/31/2015
Phil Rykhoek 651 11.17 12/31/2015
J. Conley Stone 781 11.17 12/31/2015
Mark A. Worthey 651 11.17 12/31/2015

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS

Beneficial Ownership of Partnership Units

The following table sets forth certain information as of February 28,
2005, regarding the beneficial ownership of our units by beneficial owners of 5%
or more of the units, by directors and the executive officers of our general
partner and by all directors and executive officers as a group. This information
is based on data furnished by the persons named.

Beneficial Ownership of Common Units
------------------------------------
Percent
Title of Class Name Number of Units of Class
- -------------------- ------------------- --------------- ----------------

Genesis Energy, L.P. Genesis Energy, Inc. 1,019,441 7.4
Common Unit Gareth Roberts 10,000 *
Mark J. Gorman 25,525 *
Ronald T. Evans 1,000 *
Herbert I. Goodman 2,000 *
Susan O. Rheney 700 *
Phil Rykhoek 2,500 *
J. Conley Stone 2,000 *
Mark A. Worthey 1,600 *
Ross A. Benavides 9,283 *
Kerry W. Mazoch 8,669 *
Karen N. Pape 3,386 *

All directors and
executive officers
as a group (11 in
number)
66,663 *

- -----
* Less than 1%

Each unitholder in the above table is believed to have sole voting and
investment power with respect to the shares beneficially held. Included in the
units held by Mark A. Worthey are 500 units held by his child. Included in the
units held by Kerry W. Mazoch are 584 units held with his children.

Beneficial Ownership of General Partner Interest

Genesis Energy, Inc. owns all of our 2% general partner interest and all
of our incentive distribution rights, in addition to 7.4% of our units. Genesis
Energy, Inc. is a wholly-owned subsidiary of Denbury Resources, Inc.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Our General Partner

Our operations are managed by, and our employees are employed by, Genesis
Energy, Inc., our general partner. Our general partner does not receive any
management fee or other compensation in connection with the management of our
business, but is reimbursed for all direct and indirect expenses incurred on our
behalf. During 2005, these reimbursements totaled $15.1 million. At December 31,
2005, we owed our general partner $1.1 million related to these services.

Our general partner owns the 2% general partner interest and all incentive
distribution rights. Our general partner is entitled to receive incentive
distributions if the amount we distribute with respect to any quarter exceeds
levels specified in our partnership agreement. Under the quarterly incentive
distribution provisions, generally our general partner is entitled to 13.3% of
amounts we distribute in excess of $0.25 per unit, 23.5% of the amounts we
distribute in excess of $0.28 per unit, and 49% of the amounts we distribute in
excess of $0.33 per unit.

Our general partner also owns 1,019,441 limited partner units and has the
same rights and is entitled to receive distributions as the other limited
partners with respect to those units.

During 2005, our general partner received a total of $0.5 million from us
as distributions on its limited partner units and for its general partner
interest.

Relationship with Denbury Resources, Inc.

Historically, we have entered into transactions with Denbury and its
subsidiaries to acquire assets. We have instituted specific procedures for
evaluating and valuing our material transactions with Denbury and its
subsidiaries. Before we consider entering into a transaction with Denbury or any
of its subsidiaries, we determine whether the proposed transaction (1) would
comply with the requirements under our credit facility, (2) would comply with

substantive law, and (3) would be fair to us and our limited partners. In
addition, our general partner's board of directors utilizes a Special Conflicts
Committee comprised solely of independent directors. That committee:

- evaluates and, where appropriate, negotiates the proposed
transaction;

- engages an independent financial advisor and independent legal
counsel to assist with its evaluation of the proposed transaction;
and

- determines whether to reject or approve and recommend the proposed
transaction.

We will only consummate any proposed material acquisition or disposition with
Denbury if, following our evaluation of the transaction, the Special Conflicts
Committee approves and recommends the proposed transaction and our general
partner's full board approves the transaction.

During 2005, 2004 and 2003, we acquired CO(2) volumetric production payments
and related wholesale marketing contracts from Denbury for $14.4 million, $4.7
million and $24.4 million, respectively. Additionally we enter into transactions
with Denbury in the ordinary course of our operations. During 2005, these
transactions included:

- Purchases of crude oil from Denbury totaling $4.6 million.

- Sales of crude oil to Denbury totaling $0.2 million.

- Provision of transportation services for crude oil by truck totaling
$0.8 million.

- Provision of crude oil pipeline transportation services totaling
$3.9 million.

- Provision of crude oil from and CO(2) transportation to the
Brookhaven field and crude oil from the Olive field for $1.2
million.

- Provision of CO(2) transportation services to our wholesale
industrial customers by Denbury's pipeline. The fees for this
service totaled $3.5 million in 2005.

- Provision of pipeline monitoring services to Denbury for its CO(2)
pipelines totaling $30,000 in 2005.

- Provision of services by Denbury officers as directors of our
general partner. We paid Denbury $120,000 for these services in
2005.

At December 31, 2005, we owed Denbury $1.9 million for purchases of crude oil
and provision of CO(2) transportation services. Denbury owed us $0.5 million for
crude oil trucking and pipeline transportation services.

In 2002, we amended our partnership agreement to broaden the right of the
common unitholders to remove our general partner. Prior to this amendment, the
general partner could only be removed for cause and with approval by holders of
two-thirds or more of the outstanding limited partner interests in GELP. As
amended, the partnership agreement provides that, with the approval of at least
a majority of the limited partners in GELP, the general partner also may be
removed without cause. Any limited partner interests held by the general partner
and its affiliates would be excluded from such a vote.

The amendment further provides that if it is proposed that the removal is
without cause and an affiliate of Denbury is the general partner to be removed
and not proposed as a successor, then any action for removal must also provide
for Denbury to be granted an option effective upon its removal to purchase our
Mississippi pipeline system at a price that is 110 percent of its fair market
value at that time. Denbury also has the right to purchase the Mississippi CO(2)
pipeline to Brookhaven field at its fair market value at that time. Fair value
is to be determined by agreement of two independent appraisers, one chosen by
the successor general partner and the other by Denbury or if they are unable to
agree, the mid-point of the values determined by them.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table summarizes the aggregate fees billed to us by Deloitte &
Touche LLP.

2005 2004
---------------------------
(in thousands)

Audit Fees (a)....................................... $ 733 $ 665
Audit-Related Fees (b)............................... 41 36
Tax-Related Fees..................................... 66 -
--------- ---------
Total................................................ $ 840 $ 701
========= =========

(a) Fees for audit services in 2005 consisted of:
Audit of our annual financial statements
Sarbanes-Oxley Section 404 audit work
Audit of our general partner financial statements
Reviews of our quarterly financial statements
Audit of an equity joint venture

Fees for audit services in 2004 consisted of:
Audit of our annual financial statements
Sarbanes-Oxley Section 404 audit work
Audit of our general partner financial statements
Reviews of our quarterly financial statements

(b) Fees for audit-related services in 2005 consisted of:
Financial accounting and reporting consultations
Employee benefit plan audit.

Fees for audit-related services in 2004 consisted of:
Financial accounting and reporting consultations
Sarbanes-Oxley Act, Section 404 advisory services
Employee benefit plan audit.

Deloitte provided no tax services or other services to us in 2004. In 2005
Deloitte provided tax services, consisting of tax compliance and tax advice. In
considering the nature of the services provided by Deloitte, the Audit Committee
determined that such services are compatible with the provision of independent
audit services. The Audit Committee discussed these services with Deloitte and
management of our general partner to determine that they are permitted under the
rules and regulations concerning auditor independence promulgated by the SEC to
implement the Sarbanes-Oxley Act of 2002, as well as the American Institute of
Certified Public Accountants.

Pre-Approval Policy

The services by Deloitte in 2005 and 2004 were pre-approved in accordance
with the pre-approval policy and procedures adopted by the Audit Committee. This
policy describes the permitted audit, audit-related, tax and other services
(collectively, the "Disclosure Categories") that the independent auditor may
perform. The policy requires that prior to the beginning of each fiscal year, a
description of the services (the "Service List") expected to be performed by the
independent auditor in each of the Disclosure Categories in the following fiscal
year be presented to the Audit Committee for approval.

Any requests for audit, audit-related, tax and other services not
contemplated on the Service List must be submitted to the Audit Committee for
specific pre-approval and cannot commence until such approval has been granted.
Normally, pre-approval is provided at regularly scheduled meetings.

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) and (2) Financial Statements and Financial Statement Schedules

See "Index to Consolidated Financial Statements" set forth on page 67.

(a)(3) Exhibits

3.1 Certificate of Limited Partnership of Genesis Energy, L.P.
("Genesis") (incorporated by reference to Exhibit 3.1 to
Registration Statement, File No. 333-11545)

3.2 Fourth Amended and Restated Agreement of Limited Partnership
of Genesis (incorporated by reference to Exhibit 4.1 of Form
8-K dated June 15, 2005)

3.3 Certificate of Limited Partnership of Genesis Crude Oil, L.P.
(the "Operating Partnership") (incorporated by reference to
Exhibit 3.3 to Form 10-K for the year ended December 31, 1996)

3.4 Fourth Amended and Restated Agreement of Limited Partnership
of the Operating Partnership (incorporated by reference to
Exhibit 4.2 to Form 8-K dated June 15, 2005)

10.1 Purchase & Sale and Contribution & Conveyance Agreement dated
as of December 3, 1996 among Basis Petroleum, Inc. ("Basis"),
Howell Corporation ("Howell"), certain subsidiaries of Howell,
Genesis, the Operating Partnership and Genesis Energy, L.L.C.
(incorporated by reference to Exhibit 10.1 to Form 10-K for
the year ended December 31, 1996)

10.2 First Amendment to Purchase & Sale and Contribution &
Conveyance Agreement (incorporated by reference to Exhibit
10.2 to Form 10-K for the year ended December 31, 1996)

10.3 Credit Agreement dated as of June 1, 2004, between Genesis
Crude Oil, L.P., Genesis Energy, Inc. Genesis Energy, L.P.,
Fleet National Bank and Certain Financial Institutions
(incorporated by reference to Exhibit 10.1 to Form 8-K dated
June 1, 2004)

10.4 Consent and Amendment effective as of April 15, 2005, to the
Credit Agreement dated as of June 1, 2004 among Genesis Crude
Oil, L.P., Genesis Energy, Inc., Genesis Energy, L.P., Fleet
National Bank and certain financial institutions (incorporated
by reference to Exhibit 10.1 to Form 8-K dated December 7,
2005)

10.5 Pipeline Sale and Purchase Agreement between TEPPCO Crude
Pipeline, L.P. and Genesis Crude Oil, L.P. and Genesis
Pipeline, L.P. (incorporated by reference to Exhibit 10.1 to
Form 8-K dated October 31, 2003)

10.6 Purchase and Sale Agreement between TEPPCO Crude Pipeline,
L.P. and Genesis Crude Oil, L.P. (incorporated by reference to
Exhibit 10.2 to Form 8-K dated October 31, 2003)

10.7 Production Payment Purchase and Sale Agreement between Denbury
Resources, Inc. and Genesis Crude Oil, L.P. executed November
14, 2003 (incorporated by reference to Exhibit 10.7 to Form
10-K for the year ended December 31, 2003)

10.8 Carbon Dioxide Transportation Agreement between Denbury
Resources, Inc. and Genesis Crude Oil, L.P. (incorporated by
reference to Exhibit 10.8 to Form 10-K for the year ended
December 31, 2003)

10.9+ Genesis Energy, Inc. Stock Appreciation Rights Plan
(incorporated by reference to Exhibit 10.9 to Form 10-K for
the year ended December 31, 2004)

10.10+ Form of Stock Appreciation Rights Plan Grant Notice
(incorporated by reference to Exhibit 10.10 to Form 10-K for
the year ended December 31, 2004)

10.11+ Summary of Director Compensation (incorporated by reference to
Exhibit 10.11 to Form 10-K for the year ended December 31,
2004)

* 10.12+ Summary of Genesis Energy, Inc. Bonus Plan

10.13+ Genesis Energy Severance Protection Plan (incorporated by
reference to Exhibit 10.1 to Form 8-K dated June 2, 2005)

10.14 Second Production Payment Purchase and Sale Agreement between
Denbury Onshore, LLC. and Genesis Crude Oil, L.P. executed
August 26, 2004 (incorporated by reference to Exhibit 99.1 to
Form 8-K dated August 26, 2004)

10.15 Second Carbon Dioxide Transportation Agreement between Denbury
Onshore, LLC. and Genesis Crude Oil, L.P. (incorporated by
reference to Exhibit 99.1 to Form 8-K dated August 26, 2004)

10.16 Third Production Payment Purchase and Sale Agreement between
Denbury Onshore, LLC. and Genesis Crude Oil, L.P. executed
October 11, 2005 (incorporated by reference to Exhibit 99.2 to
Form 8-K dated October 11, 2005)

10.17 Third Carbon Dioxide Transportation Agreement between Denbury
Onshore, LLC. and Genesis Crude Oil, L.P. (incorporated by
reference to Exhibit 99.3 to Form 8-K dated October 11,2005)

11.1 Statement Regarding Computation of Per Share Earnings (See
Notes 2 and 9 to the Consolidated Financial Statements)

* 21.1 Subsidiaries of the Registrant

* 23.1 Consent of Deloitte & Touche LLP

* 31.1 Certification by Chief Executive Officer Pursuant to Rule
13a-14(a) under the Securities Exchange Act of 1934.

* 31.2 Certification by Chief Financial Officer Pursuant to Rule
13a-14(a) under the Securities Exchange Act of 1934.

* 32.1 Certification by Chief Executive Officer Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.

* 32.2 Certification by Chief Financial Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.

- ------
* Filed herewith

+ A management contract or compensation plan or arrangement.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized on the 7th day of March,
2006.

GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)

By: GENESIS ENERGY, INC., as
General Partner

By: /s/ Mark J. Gorman
-------------------------------------
Mark J. Gorman
Chief Executive Officer and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons in the capacities and on
the dates indicated.

/s/ MARK J. GORMAN Director, Chief Executive Officer March 7, 2006
- -------------------------------------- and President
Mark J. Gorman (Principal Executive Officer)

/s/ ROSS A. BENAVIDES Chief Financial Officer, March 7, 2006
- -------------------------------------- General Counsel and Secretary
Ross A. Benavides (Principal Financial Officer)

/s/ KAREN N. PAPE Vice President and Controller March 7, 2006
- -------------------------------------- (Principal Accounting Officer)
Karen N. Pape

/s/ GARETH ROBERTS Chairman of the Board and March 7, 2006
- -------------------------------------- Director
Gareth Roberts

/s/ RONALD T. EVANS Director March 7, 2006
- --------------------------------------
Ronald T. Evans

/s/ HERBERT I GOODMAN Director March 7, 2006
- --------------------------------------
Herbert I. Goodman

/s/ SUSAN O. RHENEY Director March 7, 2006
- --------------------------------------
Susan O. Rheney

/s/ PHIL RYKHOEK Director March 7, 2006
- --------------------------------------
Phil Rykhoek

/s/ J. CONLEY STONE Director March 7, 2006
- --------------------------------------
J. Conley Stone

/s/ MARK A. WORTHEY Director March 7 2006
- --------------------------------------
Mark A. Worthey

GENESIS ENERGY, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Page
----

Report of Independent Registered Public Accounting Firm............................................ 68

Consolidated Balance Sheets, December 31, 2005 and 2004............................................ 69

Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004 and 2003......... 70

Consolidated Statements of Comprehensive (Loss) Income for the Years Ended December 31, 2005,
2004 and 2003..................................................................................... 71

Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003......... 72

Consolidated Statements of Partners' Capital for the Years Ended December 31, 2005, 2004 and 2003.. 73

Notes to Consolidated Financial Statements......................................................... 74

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Genesis Energy, Inc. and Unitholders of
Genesis Energy, L.P.
Houston, Texas

We have audited the accompanying consolidated balance sheets of Genesis Energy,
L.P. and subsidiaries (the "Partnership") as of December 31, 2005 and 2004, and
the related consolidated statements of operations, comprehensive income (loss),
partners' capital, and cash flows for each of the three years in the period
ended December 31, 2005. These financial statements are the responsibility of
the Partnership's management. Our responsibility is to express an opinion on the
financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Genesis Energy, L.P. and
subsidiaries at December 31, 2005 and 2004, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2005, in conformity with accounting principles generally accepted in the
United States of America.

As discussed in Note 4 to the consolidated financial statements, in connection
with the required adoption of a new accounting principle in 2005, the
Partnership changed its method of accounting for conditional asset retirement
obligations.

We have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the effectiveness of the
Partnership's internal control over financial reporting as of December 31, 2005,
based on the criteria established in Internal Control -- Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission
and our report dated March 7, 2006 expressed an unqualified opinion on
management's assessment of the effectiveness of the Partnership's internal
control over financial reporting and an unqualified opinion on the effectiveness
of the Partnership's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP
Houston, Texas

March 7, 2006

GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)

December 31, December 31,
2005 2004
---------------- ------------

ASSETS

CURRENT ASSETS
Cash and cash equivalents....................................................... $ 3,099 $ 2,078
Accounts receivable:
Trade........................................................................ 82,119 68,737
Related party................................................................ 515 584
Inventories..................................................................... 498 1,866
Net investment in direct financing leases, net of unearned income - current
portion...................................................................... 531 318
Insurance receivable............................................................ 2,042 2,125
Other........................................................................... 1,645 1,688
---------------- ------------
Total current assets......................................................... 90,449 77,396

FIXED ASSETS, at cost.............................................................. 69,708 73,023
Less: Accumulated depreciation................................................. (35,939) (39,237)
---------------- ------------
Net fixed assets............................................................. 33,769 33,786

NET INVESTMENT IN DIRECT FINANCING
LEASES, net of unearned income.................................................. 5,941 4,247
CO(2) ASSETS, net of amortization.................................................. 37,648 26,344
INVESTMENT IN T&P SYNGAS SUPPLY COMPANY............................................ 13,042 -
OTHER ASSETS, net of amortization.................................................. 928 1,381
---------------- ------------

TOTAL ASSETS....................................................................... $ 181,777 $ 143,154
================ ============

LIABILITIES AND PARTNERS' CAPITAL

CURRENT LIABILITIES
Accounts payable -
Trade........................................................................ $ 82,369 $ 74,176
Related party................................................................ 2,917 1,239
Accrued liabilities............................................................. 7,325 6,523
---------------- ------------
Total current liabilities.................................................... 92,611 81,938

LONG-TERM DEBT..................................................................... - 15,300
OTHER LONG-TERM LIABILITIES........................................................ 955 160
COMMITMENTS AND CONTINGENCIES (Note 18)
MINORITY INTERESTS................................................................. 522 517

PARTNERS' CAPITAL
Common unitholders, 13,784 and 9,314 units issued and outstanding at 2005 and
2004, respectively........................................................... 85,870 44,326
General partner................................................................. 1,819 913
---------------- ------------
Total partners' capital...................................................... 87,689 45,239
---------------- ------------

TOTAL LIABILITIES AND PARTNERS' CAPITAL............................................ $ 181,777 $ 143,154
================ ============

The accompanying notes are an integral part of these consolidated financial
statements.

GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)

Year Ended December 31,
--------------------------------------------------------
2005 2004 2003
------------- ---------- -----------

REVENUES:
Crude oil gathering and marketing:
Unrelated parties (including revenues from buy/sell arrangements
of $365,067,$296,329, and $177,244 in 2005, 2004 and 2003,
respectively).................................................. $ 1,037,577 $ 901,689 $ 641,684
Related parties.................................................. 972 213 -
Pipeline transportation, including natural gas sales:
Unrelated parties................................................ 24,297 15,506 15,134
Related parties.................................................. 4,591 1,174 -
CO(2) marketing revenues............................................ 11,302 8,561 1,079
------------- ---------- -----------
Total revenues................................................. 1,078,739 927,143 657,897
COSTS AND EXPENSES:
Crude oil costs:
Unrelated parties (including crude oil costs from buy/sell
arrangements of $363,208, $295,380, and $176,953 in 2005,
2004 and 2003, respectively)................................... 1,014,249 805,990 562,626
Related parties.................................................. 4,647 77,998 59,653
Field operating.................................................. 15,992 13,880 11,497
Pipeline transportation costs:
Pipeline operating costs......................................... 9,741 8,137 10,026
Natural gas purchases............................................ 9,343 - -
CO(2) marketing costs:
Transportation costs - related party............................. 3,501 2,694 355
Other costs...................................................... 148 105
General and administrative.......................................... 9,656 11,031 8,768
Depreciation and amortization....................................... 6,721 7,298 4,641
Net (gain) loss on disposal of surplus assets....................... (479) 33 (236)
------------- ---------- -----------
Total costs and expenses....................................... 1,073,519 927,166 657,330
------------- ---------- -----------
OPERATING INCOME (LOSS)................................................ 5,220 (23) 567
OTHER INCOME (EXPENSE):
Equity in earnings of investment in T&P Syngas...................... 501 - -
Interest income..................................................... 71 44 34
Interest expense.................................................... (2,103) (970) (1,020)
------------- ---------- -----------
INCOME (LOSS) FROM CONTINUING OPERATIONS............................... 3,689 (949) (419)
Discontinued operations:
Income (loss) from operations from discontinued Texas System
(including gain on disposal of $13,028 in 2003) before minority
interests........................................................... 312 (463) 13,742
Minority interests in discontinued operations.......................... - - 1
------------- ---------- -----------
INCOME (LOSS) FROM DISCONTINUED OPERATIONS............................. 312 (463) 13,741
CUMULATIVE EFFECT ADJUSTMENT........................................... (586) - -
------------- ---------- -----------
NET INCOME (LOSS)...................................................... $ 3,415 $ (1,412) $ 13,322
============= ========== ===========

GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS-CONTINUED
(In thousands, except per unit amounts)

Year Ended December 31,
--------------------------------------------------------
2005 2004 2003
------------- ---------- -----------

NET INCOME (LOSS) PER COMMON UNIT-BASIC AND DILUTED:
Income (loss) from continuing operations........................ $ 0.38 $ (0.10) $ (0.05)
Income (loss) from discontinued operations...................... 0.03 (0.05) 1.55
Cumulative effect adjustment.................................... (0.06) - -
------------- ---------- -----------
NET INCOME (LOSS)............................................. $ 0.35 $ (0.15) $ 1.50
============= ========== ===========

Weighted average number of common units outstanding................... 9,547 9,314 8,715
============= ========== ===========

The accompanying notes are an integral part of these consolidated financial
statements.

GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)

Year Ended December 31,
--------------------------------------------------------
2005 2004 2003
------------- ---------- -----------

NET INCOME (LOSS)................................................... $ 3,415 $ (1,412) $ 13,322
OTHER COMPREHENSIVE INCOME:
Change in fair value of derivatives used for hedging purposes.... - - 39
------------- ---------- -----------
COMPREHENSIVE INCOME (LOSS)......................................... $ 3,415 $ (1,412) $ 13,361
============= ========== ===========

The accompanying notes are an integral part of these consolidated financial
statements.

GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

Year Ended December 31,
--------------------------------------------------------
2005 2004 2003
------------- -------------- -----------

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)................................................... $ 3,415 $ (1,412) $ 13,322
Adjustments to reconcile net income to net cash
provided by operating activities -
Depreciation................................................... 3,579 4,846 5,970
Amortization of CO(2) contracts and covenant not-to-compete.... 3,142 2,452 534
Amortization and write-off of credit facility issuance costs... 373 373 1,031
Amortization of unearned income on direct financing leases..... (689) (36) -
Payments received under direct financing leases................ 1,185 75 -
Equity in earnings of investment in T&P Syngas................. (501) - -
Distributions from T&P Syngas - return on investment........... 435 - -
(Gain) loss on disposal of assets.............................. (791) 33 (13,264)
Minority interests equity in earnings.......................... - - 1
Cumulative effect adjustment................................... 586 - -
Other non-cash (credits) charges............................... (54) 1,151 267
Changes in components of working capital -
Accounts receivable.......................................... (13,313) (2,589) 13,932
Inventories.................................................. 790 (1,170) 3,758
Other current assets......................................... 132 13,251 (11,654)
Accounts payable............................................. 10,431 7,525 (20,211)
Accrued liabilities.......................................... 770 (14,797) 11,007
------------- ---------- -----------
Net cash provided by operating activities.............................. 9,490 9,702 4,693

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment................................. (6,106) (8,322) (4,910)
CO(2) contracts acquisition......................................... (14,446) (4,723) (24,401)
Investment in T&P Syngas Supply Company............................. (13,418) - -
Distributions from T&P Syngas - return of investment................ 388 - -
Proceeds from disposal of assets.................................... 1,585 112 22,341
Other, net ........................................................ 188 128 (24)
------------- ---------- -----------
Net cash used in investing activities.................................. (31,809) (12,805) (6,994)

CASH FLOWS FROM FINANCING ACTIVITIES:
Bank (repayments) borrowings, net................................... (15,300) 8,300 1,500
Other, net ........................................................ (400) 541 -
Credit facility issuance fees....................................... - (826) (1,093)
Issuance of limited and general partner interests, net.............. 44,833 - 5,012
Minority interests contributions.................................... 5 - 1
Distributions to common unitholders................................. (5,682) (5,589) (1,294)
Distributions to general partner.................................... (116) (114) (27)
------------- ---------- -----------
Net cash provided by financing activities........................... 23,340 2,312 4,099

Net increase (decrease) in cash and cash equivalents................... 1,021 (791) 1,798
Cash and cash equivalents at beginning of period....................... 2,078 2,869 1,071
------------- ---------- -----------

Cash and cash equivalents at end of period............................. $ 3,099 $ 2,078 $ 2,869
============= ========== ===========

The accompanying notes are an integral part of these consolidated financial
statements.

GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(In thousands)

Partners' Capital
---------------------------------------------------------------------------------------
Accumulated
Number of Other
Common Common General Comprehensive
Units Unitholders Partner Income Total
------------ -------------- ------------ ------------- ------------

Partners' capital, January 1, 2003..... 8,625 $ 34,626 $ 715 $ (39) $ 35,302
Net income ............................ - 13,055 267 - 13,322
Cash distributions .................... - (1,294) (27) - (1,321)
Issuance of units ..................... 689 4,912 100 - 5,012
Change in fair value of derivatives
used for hedging purposes ........... - - - 39 39
------------ -------------- ------------ ------------- ------------
Partners' capital, December 31, 2003... 9,314 51,299 1,055 - 52,354
Net income ............................ - (1,384) (28) - (1,412)
Cash distributions .................... - (5,589) (114) - (5,703)
------------ -------------- ------------ ------------- ------------
Partners' capital, December 31, 2004... 9,314 44,326 913 - 45,239
Net income ............................ - 3,347 68 - 3,415
Cash distributions .................... - (5,682) (116) - (5,798)
Issuance of units ..................... 4,470 43,879 954 - 44,833
------------ -------------- ------------ ------------- ------------
Partners' capital, December 31, 2005... 13,784 $ 85,870 $ 1,819 $ - $ 87,689
============ ============== ============ ============= ============

The accompanying notes are an integral part of these consolidated financial
statements.

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION

We are a publicly traded Delaware limited partnership formed in December
1996. Our operations are conducted through our operating subsidiary, Genesis
Crude Oil, L.P., and its subsidiary partnerships. We are engaged in pipeline
transportation of crude oil, and, to a lesser degree, natural gas and carbon
dioxide (CO(2)), crude oil gathering and marketing, and we engage in industrial
gas activities, including wholesale marketing of CO(2) and processing of syngas
through a joint venture. Our assets are located in the United States Gulf Coast
area.

Our 2% general partner interest is held by Genesis Energy, Inc., a
Delaware corporation and indirect wholly-owned subsidiary of Denbury Resources
Inc. Denbury and its subsidiaries are hereafter referred to as Denbury. Our
general partner also owns a 7.25% interest in us through limited partner
interests.

Our general partner manages our operations and activities and employs our
officers and personnel, who devote 100% of their efforts to our management.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Consolidation and Presentation

The accompanying financial statements and related notes present our
consolidated financial position as of December 31, 2005 and 2004 and our results
of operations, cash flows and changes in partners' capital for the years ended
December 31, 2005, 2004 and 2003, and changes in comprehensive income for the
years ended December 31, 2005, 2004 and 2003. All significant intercompany
transactions have been eliminated. The accompanying consolidated financial
statements include Genesis Energy, L.P., its operating subsidiary and its
subsidiary partnerships. Our general partner owns a 0.01% general partner
interest in Genesis Crude Oil, L.P., which is reflected in our financial
statements as a minority interest.

In 2005, we acquired a 50% interest in T&P Syngas Supply Company. This
investment is accounted for by the equity method, as we exercise significant
influence over its operating and financial policies. See Note 7.

No provision for income taxes related to our operations is included in the
accompanying consolidated financial statements; as such income will be taxable
directly to the partners holding partnership interests.

Use of Estimates

The preparation of consolidated financial statements in conformity with
accounting principles generally accepted in the United States of America
requires us to make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and liabilities,
if any, at the date of the consolidated financial statements and the reported
amounts of revenues and expenses during the reporting period. Significant
estimates that we make include: (1) estimated useful lives of assets, which
impacts depreciation and amortization, (2) accruals related to revenues and
expenses, (3) liability and contingency accruals, (4) estimated fair value of
assets and liabilities acquired, and (5) estimates of future net cash flows from
assets for purposes of determining whether impairment of those assets has
occurred. While we believe these estimates are reasonable, actual results could
differ from these estimates.

Cash and Cash Equivalents

Cash and cash equivalents consist of all demand deposits and funds
invested in highly liquid instruments with original maturities of three months
or less. The Partnership has no requirement for compensating balances or
restrictions on cash.

Inventories

Crude oil inventories held for sale are valued at the lower of average
cost or market. Fuel inventories are carried at the lower of cost or market.

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fixed Assets

Property and equipment are carried at cost. Depreciation of property
and equipment is provided using the straight-line method over the respective
estimated useful lives of the assets. Asset lives are 5 to 15 years for
pipelines and related assets, 3 to 7 years for vehicles and transportation
equipment, and 3 to 10 years for buildings, office equipment, furniture and
fixtures and other equipment.

Interest is capitalized in connection with the construction of major
facilities. The capitalized interest is recorded as part of the asset to which
it relates and is amortized over the asset's estimated useful life.

Long-lived assets are reviewed for impairment. An asset is tested for
impairment when events or circumstances indicate that its carrying value may not
be recoverable. The carrying value of a long-lived asset is not recoverable if
it exceeds the sum of the undiscounted cash flows expected to be generated from
the use and ultimate disposal of the asset. If the carrying value is determined
to not be recoverable under this method, an impairment charge equal to the
amount the carrying value exceeds the fair value is recognized. Fair value is
generally determined from estimated discounted future net cash flows.

Maintenance and repair costs are charged to expense as incurred. Costs
incurred for major replacements and upgrades are capitalized and depreciated
over the remaining useful life of the asset.

Certain volumes of crude oil are classified in fixed assets, as they
are necessary to ensure efficient and uninterrupted operations of the gathering
businesses. These crude oil volumes are carried at their weighted average cost.

We account for asset retirement obligations by capitalizing the present
value of the estimated future obligations as part of the cost of the related
long-lived asset and subsequently allocating the capitalized value to expense
systematically as with depreciation. Accretion of the discount increases the
liability and is recorded to expense. See Note 4 regarding asset retirement
obligations.

Direct Financing Leasing Arrangements

We lease three pipelines to Denbury under direct financing leases.
These leases to Denbury of pipeline segments will expire in eight to ten years.

When a direct financing lease is consummated, we record the gross
finance receivable, unearned income and the estimated residual value of the
leased pipelines. Unearned income represents the excess of the gross receivable
plus the estimated residual value over the costs of the pipelines. Unearned
income is recognized as financing income using the interest method over the term
of the transaction and is included in pipeline revenue in the Consolidated
Statements of Operations. The pipeline cost is not included in fixed assets. See
Note 5.

CO(2) and Other Assets

Other assets consist primarily of CO(2) assets, deferred credit
facility fees and intangibles. The CO(2) assets include three volumetric
production payments and long-term contracts to sell the CO(2) volume. The
contract values are being amortized on a units-of-production method. See Note 6.

We are amortizing the deferred credit facility fees over the period the
facility is in effect. Intangibles included a covenant not to compete, which was
amortized over five years ending during 2003.

Environmental Liabilities

We provide for the estimated costs of environmental contingencies when
liabilities are probable to occur and reasonable estimates can be made. Ongoing
environmental compliance costs, including maintenance and monitoring costs, are
charged to expense as incurred.

Stock Appreciation Rights Plan

Upon exercise, a participant in our stock appreciation rights plan
receives a cash payment calculated as the difference between the average of the
closing market price of our common units for the ten days preceding the date of
exercise over the strike price of the right being exercised. We accrue a
liability for the difference between the market price at the balance sheet date
and the strike price of each outstanding stock appreciation right, to the extent
that the difference is positive. See Note 14.

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Beginning in 2006, we will account for our stock appreciation rights
plan in accordance with SFAS No. 123 (revised December 2004), "Share-Based
Payment". The adoption of this statement will require that the compensation cost
associated with our stock appreciation rights plans be re-measured each
reporting period based on the fair value of the rights. See "Recent and Proposed
Accounting Pronouncements" below.

Revenue Recognition

Revenues from gathering and marketing of crude oil and natural gas are
recognized when title to the crude oil or natural gas is transferred to the
customer. Revenues from transportation of crude oil or natural gas by our
pipelines are recognized upon delivery of the barrels to the location designated
by the shipper. Pipeline loss allowance revenues are recognized to the extent
that pipeline loss allowances charged to shippers exceed pipeline measurement
losses for the period based upon the fair market value of the crude oil upon
which the allowance is based.

Income from direct financing leases is being recognized ratably over
the term of the leases and is included in pipeline revenues.

Revenues from CO(2) marketing activities are recorded when title
transfers to the customer at the inlet meter of the customer's facility.

Cost of Sales

Crude oil cost of sales consists of the cost of crude oil and field
operating expenses. Pipeline transportation costs consist of pipeline operating
expenses and the cost of natural gas. Field and pipeline operating expenses
consist primarily of labor costs for drivers and pipeline field personnel, truck
rental costs, fuel and maintenance, utilities, insurance and property taxes.

We enter into buy/sell arrangements that are accounted for on a gross
basis in our statements of operations as revenues and costs of crude. These
transactions are contractual arrangements that establish the terms of the
purchase of a particular grade of crude oil at a specified location and the sale
of a particular grade of crude oil at a different location at the same or at
another specified date. These arrangements are detailed either jointly, in a
single contract, or separately, in individual contracts that are entered into
concurrently or in contemplation of one another with a single counterparty. Both
transactions require physical delivery of the crude oil and the risk and reward
of ownership are evidenced by title transfer, assumption of environmental risk,
transportation scheduling, credit risk and counterparty nonperformance risk. In
accordance with the provision of Emerging Issues Task Force (EITF) Issue No.
04-13, "Accounting for Purchases and Sales of Inventory with the Same
Counterparty," we will reflect these amounts of revenues and purchases as a net
amount in our consolidated statements of operations beginning in 2006.
Additionally, our reported crude oil gathering and marketing revenues from
unrelated parties for the year ended December 31, 2005 would be reduced by $365
million to $673 million. Our reported crude oil costs from unrelated parties for
the year ended December 31, 2005, would be reduced by $363 million to $651
million. We do not believe this change will have any affect on operating income,
net income or cash flows.

Cost of sales for the CO(2) marketing activities consists of a
transportation fee charged by Denbury ($0.16 per Mcf, adjusted annually for
inflation) to transport the CO(2) to the customer through Denbury's pipeline and
insurance costs.

Derivative Instruments and Hedging Activities

We minimize our exposure to price risk by limiting our inventory
positions, therefore we rarely use derivative instruments. In 2003 and 2004, we
used derivative instruments only once. However should we use derivative
instruments to hedge exposure to price risk, we would account for those
derivative transactions in accordance with Statement of Financial Accounting
Standards No. 133 "Accounting for Derivative Instruments and Hedging
Activities", as amended and interpreted. Derivative transactions, which can
include forward contracts and futures positions on the NYMEX, are recorded on
the balance sheet as assets and liabilities based on the derivative's fair
value. Changes in the fair value of derivative contracts are recognized
currently in earnings unless specific hedge accounting criteria are met. If the
derivatives meet those criteria, the derivative's gains and losses offset
related results on the hedged item in the income statement. We must formally
designate the derivative as a hedge and document and assess the effectiveness of
derivatives associated with transactions that receive hedge accounting.

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SFAS No. 133 designates derivatives that hedge exposure to variable
cash flows of forecasted transactions as cash flow hedges and the effective
portion of the derivative's gain or loss is initially reported as a component of
other comprehensive income (outside earnings) and subsequently reclassified into
earnings when the forecasted transaction affects earnings. The ineffective
portion of the gain or loss is reported in earnings immediately. If a derivative
transaction qualifies for and is designated as a normal purchase and sale, it is
exempted from the fair value accounting requirements and is accounted for using
traditional accrual accounting.

Net Income Per Common Unit

Basic and diluted net income per common unit is calculated on the
weighted average number of outstanding common units, after exclusion of the 2
percent general partner interest from net income. The weighted average number of
common units outstanding was 9,546,529, 9,313,811, and 8,714,845 for the years
ended December 31, 2005, 2004 and 2003, respectively. Diluted net income per
common unit did not differ from basic net income per common unit for any period
presented. See Note 9 for a computation of net (loss) income per common unit.

Recent and Proposed Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123 (revised December 2004),
"Share-Based Payment". This statement replaces SFAS No. 123 and requires that
compensation costs related to share-based payment transactions be recognized in
the financial statements. This statement is effective for us in the first
quarter of 2006. The adoption of this statement will require that the
compensation cost associated with our stock appreciation rights plans be
re-measured each reporting period based on the fair value of the rights. Before
the adoption of SFAS 123 (R), we accounted for the stock appreciation rights in
accordance with FASB Interpretation No. 28, "Accounting for Stock Appreciation
Rights and Other Variable Stock Option or Award Plans" which required that the
liability under the plan be measured at each balance sheet date based on the
market price of our common units on that date. Under SFAS 123 (R), the liability
will be calculated using a fair value method that will take into consideration
the expected future value of the rights at their expected exercise dates. At
December 31, 2005, we had a recorded liability of $0.8 million, computed under
the provisions of FASB Interpretation No. 28. Two significant factors in
determining the fair value of this liability under FAS 123(R) are the expected
volatility of the market price for our common units, which we expect to increase
the recorded liability, and the expected rate of employee forfeitures of rights
granted due to termination of employment, which is expected to decrease the
liability. Another factor impacting the fair value is the expected life of the
rights, which is the period of time we would expect between the date when the
rights vest and when the employee exercises the rights. We have not completed
the calculation of the impact of the adoption of FAS 123(R) on our financial
position or results of operations and such impact cannot be estimated; however
we do not expect it to have any effect on our cash flows.

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. INVENTORIES

Inventories consisted of the following (in thousands).

December 31,
----------------------------------------
2005 2004
---------------- ----------------

Crude oil inventories, at lower of cost or market............................... $ 411 $ 1,802
Fuel and supplies inventories, at lower of cost or market....................... 87 64
---------------- ----------------
Total inventories........................................................... $ 498 $ 1,866
================ ================

4. FIXED ASSETS AND ASSET RETIREMENT OBLIGATIONS

Fixed Assets

Fixed assets consisted of the following (in thousands).

December 31,
----------------------------------------
2005 2004
---------------- ----------------

Land and buildings.............................................................. $ 967 $ 1,167
Pipelines and related assets.................................................... 57,706 60,296
Vehicles and transportation equipment........................................... 1,169 1,416
Office equipment, furniture and fixtures........................................ 2,724 2,791
Construction in progress........................................................ - 841
Other ........................................................................ 7,142 6,512
---------------- ----------------
69,708 73,023
Less - Accumulated depreciation................................................. (35,939) (39,237)
----------------- ----------------
Net fixed assets................................................................ $ 33,769 $ 33,786
================ ================

In 2005 and 2004, $35,000 and $76,000 of interest cost, respectively, was
capitalized related to the construction of pipelines and related assets. No
interest was capitalized in 2003.

Depreciation expense, including discontinued operations, was $3,579,000,
$4,846,000, and $5,970,000 for the years ended December 31, 2005, 2004, and
2003, respectively. In 2004, depreciation expense included $933,000 of
impairment recorded to value the Liberty to Baton Rouge segment of our
Mississippi System at its estimated salvage value.

Asset Retirement Obligations

In 2003, we recorded a charge of $700,000 for an accrual for the removal
of an abandoned offshore pipeline. In 2004, we received permission to abandon
the pipeline in place, and reversed the amount of the accrual that had not been
spent. Additionally, in 2004, we agreed to remove certain pipeline facilities
from land we sold. This obligation was completed in 2005.

On December 31, 2005, we adopted FASB Interpretation No. 47, "Accounting
for Conditional Asset Retirement Obligations, an interpretation of FASB
Statement No. 143" (FIN 47). FIN 47 clarified that the term "conditional asset
retirement obligation", as used in SFAS No. 143, "Accounting for Asset
Retirement Obligations", refers to a legal obligation to perform an asset
retirement activity in which the timing and/or method of settlement are
conditional upon a future event that may or may not be within our control.
Although uncertainty about the timing and/or method of settlement may exist and
may be conditional upon a future event, the obligation to perform the asset
retirement activity is unconditional. Accordingly, we are required to recognize
a liability for the fair value of a conditional asset retirement obligation if
the fair value of the liability can be reasonably estimated.

Upon adoption of FIN 47, we recorded a fixed asset and a liability for the
estimated fair value of the asset retirement obligations at the time we acquired
the related assets. This $0.3 million fixed asset is being depreciated over the
life of the related assets. The accretion of the discount on the liability and
the depreciation through December 31, 2005 were recorded in the statement of
operations as a cumulative effect adjustment totaling $0.5 million.
Additionally, we reflected our share of the asset retirement obligation recorded
in accordance with FIN 47 of our equity method joint venture as a cumulative
affect adjustment of $0.1 million.

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A reconciliation of our liability for asset retirement obligations is
as follows (in thousands):

Asset retirement obligations as of December 31, 2004....................................... $ 146
Addition to asset retirement obligations due to FIN 47..................................... 651
Asset retirement liability obligations incurred during 2005................................ 34
Asset retirement obligations settled during 2005........................................... (183)
Revisions to asset retirement obligations.................................................. 9
--------
Asset retirement obligations as of December 31, 2005........................................ $ 657
========

The pro forma impact for the periods ended December 31, 2005, 2004 and
2003 of the adoption of FIN 47 if it had been adopted at the beginning of each
of those periods is as follows:

Year Ended December 31,
---------------------------------------------------
2005 2004 2003
---------------- ---------------- -----------
(Unaudited)
(in thousands)

Income (loss) from continuing operations - as reported...................... $ 3,689 $ (949) $ (419)
Impact of change in accounting principle.................................... (85) (67) (63)
---------------- ---------------- -----------
Pro forma income (loss) from continuing operations.......................... $ 3,604 $ (1,016) $ (482)
================ ================ ===========

Net income (loss) - as reported............................................. $ 3,415 $ (1,412) $ 13,322
Add back cumulative effect adjustment....................................... 586 - -
Impact of change in accounting principle.................................... (85) (67) (63)
---------------- ---------------- -----------
Pro forma net income (loss)................................................. $ 3,916 $ (1,479) $ 13,259
================ ================ ===========

Basic and diluted net income per common unit:
Income from continuing operations - as reported......................... $ 0.38 $ (0.10) $ (0.05)
Impact of change in accounting principle................................ (0.01) (0.01) 0.00
---------------- ---------------- -----------
Pro forma income from continuing operations............................. $ 0.37 $ (0.11) $ (0.05)
================ ================ ===========

Net income - as reported............................................... $ 0.35 $ (0.15) $ 1.50
Impact of change in accounting principle and add
back of cumulative effect adjustment................................. 0.05 (0.01) (0.01)
---------------- ---------------- -----------
Pro forma net income.................................................... $ 0.40 $ (0.16) $ 1.49
================ ================ ===========

5. NET INVESTMENT IN DIRECT FINANCING LEASES

In the fourth quarter of 2004, we constructed two segments of crude oil
pipeline and a CO2 pipeline segment to transport crude oil from and CO2 to
producing fields operated by Denbury. Denbury pays us a minimum payment each
month for the right to use these pipeline segments. These arrangements have been
accounted for as direct financing leases.

The following table lists the components of the net investment in direct
financing leases (in thousands):

December 31,
----------------------------------------
2005 2004
---------------- ----------------

Total minimum lease payments to be received..................................... $ 9,410 $ 6,806
Estimated residual values of leased property (unguaranteed) 1,287 1,092
Less unearned income (4,225) (3,333)
---------------- ----------------
Net investment in direct financing leases....................................... $ 6,472 $ 4,565
================ ================

At December 31, 2005, minimum lease payments to be received for each of
the five succeeding fiscal years are $1.2 million per year.

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6. CO(2) AND OTHER ASSETS

Carbon Dioxide (CO(2)) Assets

CO(2) assets consisted of the following (in thousands).

December 31,
----------------------------------------
2005 2004
---------------- ----------------

CO(2) volumetric production payments............................................ $ 43,570 $ 29,124
Less - Accumulated amortization (5,922) (2,780)
---------------- ----------------
Net CO(2) assets................................................................ $ 37,648 $ 26,344
================ ================

The volumetric production payments entitle us to a maximum daily quantity
of CO(2) of 92,625 million cubic feet (Mcf) per day through December 31, 2009,
83,125 Mcf per day for the calendar years 2010 through 2012 and 65,125 Mcf per
day beginning in 2013 until we have received all volumes under the production
payments. Under the terms of transportation agreements with Denbury, Denbury
will process and deliver this CO(2) to our industrial customers and receive a
fee of $0.16 per Mcf, subject to inflationary adjustments.

The terms of the contracts with the industrial customers include minimum
take-or-pay and maximum delivery volumes. The seven industrial contracts expire
at various dates between 2010 and 2016.

The CO(2) assets are being amortized on a units-of-production method.
After purchase price adjustments, we had 276.7 Bcf of CO(2) at acquisition, and
the total $43.6 million cost is being amortized based on the volume of CO(2)
sold each month. For 2005 and 2004, we recorded amortization of $3,142,000 and
$2,452,000, respectively. For the two months in 2003 when we owned the CO(2)
assets, we recorded amortization of $328,000. We have 237.1 Bcf of CO(2)
remaining under the volumetric production payments at December 31, 2005. Based
on the historical deliveries of CO(2) to the customers (which have exceeded
minimum take-or-pay volumes), we would expect that amortization for the next
five years to be approximately $4,186,000 annually.

Other Assets

Other assets consisted of the following (in thousands).

December 31,
----------------------------------------
2005 2004
---------------- ----------------

Credit facility fees............................................................ $ 1,491 $ 1,491
Other........................................................................... 28 108
---------------- ----------------
1,519 1,599
Less - Accumulated amortization................................................. (591) (218)
---------------- ----------------
Net other assets................................................................ $ 928 $ 1,381
================ ================

Amortization expense of credit facility fees for the years ended December
31, 2005, 2004 and 2003 was $373,000, $373,000, and $298,000, respectively
Additionally, in 2003, we charged to expense $733,000 of fees related to the
facility that existed at the end of 2002.

In accordance with SFAS No. 142, "Goodwill and Other Intangible Assets,"
which we adopted January 1, 2002, we test other intangible assets periodically
to determine if impairment has occurred. An impairment loss is recognized for
intangibles if the carrying amount of an intangible asset is not recoverable and
its carrying amount exceeds its fair value. As of December 31, 2005, no
impairment has occurred of our remaining intangible assets.

We had a covenant-not-to-compete that was amortized over a five-year
period that expired in 2003. Amortization expense for the
covenant-not-to-compete was $205,000 for the year ended December 31, 2003.

7. INVESTMENT IN T&P SYNGAS SUPPLY COMPANY

On April 1, 2005, we acquired a 50% interest in T&P Syngas Supply Company
(T&P Syngas), a Delaware general partnership, for $13.4 million in cash from a
subsidiary of ChevronTexaco Corporation. Praxair Hydrogen Supply Inc. owns the
remaining 50% partnership interest in T&P Syngas. We paid for our interest in
T&P Syngas with proceeds from our credit facilities.

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

steam. Praxair provides the raw materials to be processed and receives the
syngas and steam produced by the facility under a long-term processing
agreement. T&P Syngas receives a processing fee for its services. Praxair
operates the facility.

We are accounting for our 50% ownership in T&P Syngas under the equity
method of accounting. We reflect in our consolidated statements of operations
our equity in T&P Syngas' net income, net of the amortization of the excess of
our investment over our share of partners' capital of T&P Syngas. We paid $4.0
million more for our interest in T&P Syngas than our share of partners' capital
on the balance sheet of T&P Syngas at the date of the acquisition. This excess
amount of the purchase price over the equity in T&P Syngas is being amortized
using the straight-line method over the remaining useful life of the assets of
T&P Syngas of eleven years. Our consolidated statements of operations for the
year ended December 31, 2005 included $765,000 as our share of the operating
earnings of T&P Syngas for the period beginning April 1, 2005, reduced by
amortization of the excess purchase price of $264,000. Additionally, our
consolidated statements of operations include our share of the cumulative effect
adjustment to record asset retirement obligations of $54,000 of T&P Syngas.

The table below reflects summarized financial information for T&P Syngas
at December 31, 2005, for the period since we acquired our interest in T&P
Syngas.

Nine Months Ended
December 31, 2005
-----------------
(in thousands)

Revenues........................................................................ $ 3,073
Operating expenses and depreciation............................................. (1,553)
Other income.................................................................... 9
Cumulative effect adjustment for adoption of accounting change.................. (108)
-----------
Net income...................................................................... $ 1,421
===========

December 31, 2005
-----------------
(in thousands)

Current assets.................................................................. $ 1,358
Non-current assets.............................................................. 16,956
----------
Total assets.................................................................... $ 18,314
==========

Current liabilities............................................................. $ 1,016
Partners' capital............................................................... 17,298
----------
Total liabilities and partners' capital......................................... $ 18,314
==========

The following pro forma information represents the effects on our
consolidated statements of operations assuming the investment in T&P Syngas had
occurred at the beginning of each period presented:

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Year Ended December 31,
---------------------------------------------------
2005 2004 2003
------------ ------------- -----------
(Unaudited)
(in thousands, except per unit amounts)

Revenues............................................................... $ 1,078,739 $ 927,143 $ 657,897
Operating income (loss)................................................ $ 5,220 $ (23) $ 567
Equity in earnings of T&P Syngas....................................... $ 751 $ 664 $ 724
Net interest expense................................................... $ (2,255) $ (1,649) $ (1,466)
Income (loss) from continuing operations............................... $ 3,716 $ (1,008) $ (175)
Net income (loss)...................................................... $ 3,442 $ (1,471) $ 13,366

Basic and diluted net income (loss) per common unit:

Income (loss) from continuing operations........................... $ 0.38 $ (0.11) $ (0.02)
Income (loss) from discontinued operations.............................. 0.03 (0.05) 1.55
Cumulative effect adjustment............................................ (0.05) - -
------------ ------------- ------------
Net income (loss)....................................................... $ 0.36 $ (0.16) $ 1.53
============ ============= ============

8. DEBT

We have a $100 million credit facility comprised of a $50 million
revolving line of credit for acquisitions and a $50 million working capital
revolving facility. The working capital portion of the credit facility is
composed of two components - up to $15 million for loans and up to $35 million
for letters of credit. In total we may borrow up to $65 million in loans under
our credit facility. At December 31, 2005, we had $10.1 million in letters of
credit outstanding under the working capital portion. We had no debt outstanding
under the working capital or acquisition portions of our credit facility, as we
paid off the balances with the proceeds of our limited partner unit offering
completed in December 2005. At December 31, 2004, we had $15.3 million borrowed
under the working capital portion and no debt outstanding under the acquisition
portion of our credit facility. Due to the revolving nature of loans under our
credit facility, additional borrowings and periodic repayments and re-borrowings
may be made until the maturity date of June 1, 2008.

The aggregate amount that we may have outstanding at any time in loans and
letters of credit under the working capital portion of our credit facility is
subject to a borrowing base calculation. The borrowing base is limited to $50
million and is calculated monthly. At December 31, 2005, the borrowing base was
$33.0 million. The total amount available for borrowings at December 31, 2005
was $15.0 million under the working capital portion and $50.0 million under the
acquisition portion of our credit facility.

The key terms of the Credit Facility are as follows:

- Letter of credit fees are based on the usage of the working
capital portion of the Credit Facility in relation to the
borrowing base and will range from 1.75% to 2.75%. The rate
can fluctuate daily. At December 31, 2005, the rate was 1.75%.

- The interest rate on working capital borrowings is also based
on the usage of the Credit Facility in relation to the
borrowing base. Loans may be based on the prime rate or the
LIBOR rate, at our option. The interest rate on prime rate
loans can range from the prime rate plus 0.25% to the prime
rate plus 1.25%. The interest rate for LIBOR-based loans can
range from the LIBOR rate plus 1.75% to the LIBOR rate plus
2.75%. The rate can fluctuate daily.

- The interest rate on acquisition borrowings may be based on
the prime rate or the LIBOR rate, at our option. The interest
rate on prime rate loans will be the prime rate plus 1.50%.
The interest rate for LIBOR-based loans will be the LIBOR rate
plus 3.00%. The rate can fluctuate daily.

- We pay a commitment fee on the unused portion of the $100
million commitment. The commitment fee on the working capital
portion is based on the usage of that portion of the Credit
Facility in relation to the borrowing base and will range from
0.375% to 0.50%. At December 31, 2005, the commitment fee rate
was 0.375%. The commitment fee rate on the acquisition portion
is 0.50%.

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

- Collateral under the Credit Facility consists of our accounts
receivable, inventory, cash accounts, margin accounts and
fixed assets.

Certain restrictive covenants in the credit facility limit our ability to
make distributions to our unitholders and the general partner. The credit
facility requires we maintain a cash flow coverage ratio of 1.1 to 1.0. In
general, this calculation compares operating cash inflows (as adjusted in
accordance with the credit facility), less maintenance capital expenditures, to
the sum of interest expense and distributions. At December 31, 2005, the
calculation resulted in a ratio of 1.3 to 1.0. The credit facility also requires
that the level of operating cash inflows during the prior twelve months, as
adjusted in accordance with the credit facility, be at least $8.5 million. At
December 31, 2005, the result of this calculation was $13.2 million. Our credit
facility also requires that we meet certain other financial ratios, such as a
current ratio, leverage ratio and funded indebtedness to capitalization ratio.
If we meet these covenants, we are otherwise not limited in making
distributions.

9. PARTNERS' CAPITAL AND DISTRIBUTIONS

Partners' Capital

Partner's capital at December 31, 2005 consists of 13,784,441 common
units, including 1,019,441 units owned by our general partner, representing a
98% aggregate ownership interest in the Partnership and its subsidiaries, (after
giving affect to the general partner interest), and a 2% general partner
interest.

During the three years ended December 31, 2005, we issued new common
units to the public and our general partner as follows:

Purchaser of Gross Proceeds GP Net
Period Common Units Units Unit Price from Sale Contributions Costs Proceeds
- ------------- --------------- ------------ ---------- ---------- ------------- -------- --------
(in thousands, except per unit amounts)

December 2005 Public 4,140 $ 10.50 $ 43,470 $ 887 $ 2,889 $ 41,468
December 2005 General Partner 331 $ 9.975 $ 3,298 $ 67 $ - $ 3,365
November 2003 General Partner 689 $ 7.150 $ 4,925 $ 101 $ 14 $ 5,012

Our general partner owns all of our general partner interest, all of
the 0.01% general partner interest in our operating partnership (which is
reflected as a minority interest in the consolidated balance sheet at December
31, 2005) and operates our business.

Our partnership agreement authorizes our general partner to cause us to
issue additional limited partner interests and other equity securities, the
proceeds from which could be used to provide additional funds for acquisitions
or other needs.

Distributions

Generally, we will distribute 100% of our available cash (as defined by
our partnership agreement) within 45 days after the end of each quarter to
unitholders of record and to our general partner. Available cash consists
generally of all of our cash receipts less cash disbursements adjusted for net
changes to reserves. Beginning with the distribution for the first quarter of
2003, we paid a regular quarterly distribution of $0.05 per unit ($0.4 million
in total per quarter). For the fourth quarter of 2003, we increased our
quarterly distribution to $0.15 per unit ($1.4 million in total), which was paid
in February 2004. We paid distributions of $0.15 per unit ($1.4 million in
total) for each quarter of 2004, and for the first two quarters of 2005. For the
third quarter of 2005 we paid a distribution of $0.16 per unit ($1.5 million in
total). In February 2006, we paid a distribution of $0.17 per unit ($2.4 million
in total) for the fourth quarter of 2005.

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Net Income (Loss) Per Common Unit

The following table sets forth the computation of basic net income (loss)
per common unit for 2005, 2004, and 2003 (in thousands, except per unit
amounts).

Year Ended December 31,
--------------------------------
2005 2004 2003
-------- -------- --------

Numerators for basic and diluted net income (loss) per common unit:
Income (loss) from continuing operations ........................ $ 3,689 $ (949) $ (419)
Less general partner 2% ownership ............................... 74 (19) (8)
-------- -------- --------
Income (loss) from continuing operations available for
common unitholders ............................................ $ 3,615 $ (930) $ (411)
======== ======== ========
Income (loss) from discontinued operations ...................... $ 312 $ (463) $ 13,741
Less general partner 2% ownership ............................... 6 (9) 275
-------- -------- --------
Income (loss) from discontinued operations available for
common unitholders ........................................... $ 306 $ (454) $ 13,466
======== ======== ========

Loss from cumulative effect adjustment .......................... $ (586) $ - $ -
Less general partner 2% ownership ............................... (12) - -
-------- -------- --------
Loss from cumulative effect adjustment available for
common unitholders ........................................... $ (574) $ - $ -
======== ======== ========
Denominator for basic and diluted per common unit - weighted
average number of common units outstanding ...................... 9,547 9,314 8,715
======== ======== ========

Basic and diluted net (loss) income per common unit:
Income (loss) from continuing operations .................... $ 0.38 $ (0.10) $ (0.05)
Income (loss) from discontinued operations .................... 0.03 (0.05) 1.55
Loss from cumulative effect adjustment ...................... (0.06) - -
-------- -------- --------
Net income (loss) ........................................... $ 0.35 $ (0.15) $ 1.50
======== ======== ========

10. BUSINESS SEGMENT INFORMATION

Our operations consist of three operating segments: (1) Pipeline
Transportation - interstate and intrastate crude oil, natural gas and CO(2)
pipeline transportation; (2) Industrial Gases - the sale of CO(2) acquired under
volumetric production payments to industrial customers and our investment in a
syngas processing facility, and (3) Crude Oil Gathering and Marketing - the
purchase and sale of crude oil at various points along the distribution chain.
In prior periods, our Industrial Gases segment was called CO(2) Marketing. The
tables below reflect all periods presented as though the current segment
designations had existed, and include only continuing operations data.

We evaluate segment performance based on segment margin. We calculate
segment margin as revenues less costs of sales and operations expenses, and we
include income from investments in joint ventures. We do not deduct depreciation
and amortization. All of our revenues are derived from, and all of our assets
are located in the United States. The pipeline transportation segment
information includes the revenue, segment margin and assets of the direct
financing leases. See Notes 2 and 5.

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Crude Oil
Pipeline Industrial Gathering and
Transportation Gases(a) Marketing Total
-------------- ---------- ------------- ----------
(in thousands)

Year Ended December 31, 2005
Segment margin excluding depreciation and
amortization (b)......................... $ 9,804 $ 8,154 $ 3,661 $ 21,619

Capital expenditures ...................... $ 5,425 $ 27,863 $ 547 $ 33,835
Maintenance capital expenditures .......... $ 1,256 $ - $ 287 $ 1,543
Net fixed and other long-term
assets (c)............................... $ 34,725 $ 50,690 $ 5,913 $ 91,328

Revenues:

External Customers ........................ $ 25,613 $ 11,302 $1,038,549 $1,075,464

Intersegment (d) .......................... 3,275 - - 3,275
---------- ---------- ---------- ----------
Total revenues of reportable segments ..... $ 28,888 $ 11,302 $1,038,549 $1,078,739
========== ========== ========== ==========

Year Ended December 31, 2004

Segment margin excluding depreciation and
amortization (b) ...................... $ 8,543 $ 5,762 $ 4,034 $ 18,339

Capital expenditures ...................... $ 8,187 $ 4,723 $ 284 $ 13,194

Maintenance capital expenditures .......... $ 655 $ - $ 284 $ 939

Net fixed and other long-term
assets (c)............................... $ 33,347 $ 26,344 $ 6,067 $ 65,758

Revenues:

External Customers ........................ $ 13,212 $ 8,561 $ 901,902 $ 923,675

Intersegment (d)........................... 3,468 - - 3,468
---------- ---------- ---------- ----------
Total revenues of reportable segments ..... $ 16,680 $ 8,561 $ 901,902 $ 927,143
========== ========== ========== ==========

Year Ended December 31, 2003

Segment margin excluding depreciation and
amortization (b) ........................ $ 5,108 724 $ 7,908 $ 13,740

Capital expenditures ...................... $ 2,302 $ 24,401 $ 635 $ 27,338

Maintenance capital expenditures .......... $ 2,226 $ - $ 635 $ 2,861

Net fixed and other long-term
assets (c).............................. $ 29,351 $ 24,073 $ 5,480 $ 58,904

Revenues:

External Customers ........................ $ 11,799 $ 1,079 $ 641,684 $ 654,562

Intersegment(d)............................ 3,335 - - 3,335
---------- ---------- ---------- ----------
Total revenues of reportable segments ..... $ 15,134 $ 1,079 $ 641,684 $ 657,897
========== ========== ========== ==========

(a) Industrial gases includes our CO(2) marketing operations and the income
from our investment in T&P Syngas Supply Company.

(b) Segment margin was calculated as revenues less cost of sales and
operations expense. It includes our share of the operating income of
equity joint ventures. A reconciliation of segment margin to income from
continuing operations for each year presented is as follows:

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Year Ended December 31,
------------------------------------------
2005 2004 2003
------------ ----------- ------------
(in thousands)

Segment margin excluding depreciation and
amortization....................... $ 21,619 $ 18,339 $ 13,740
General and administrative expenses............ 9,656 11,031 8,768
Depreciation, amortization and impairment...... 6,721 7,298 4,641
Net loss (gain) on disposal of surplus assets.. (479) 33 (236)
Interest expense, net.......................... 2,032 926 986
------------ ----------- ------------

Income (loss) from continuing operations....... $ 3,689 $ (949) $ (419)
============ =========== ============

(c) Net fixed and other long-term assets are the measure used by management in
evaluating the results of its operations on a segment basis. Current
assets are not allocated to segments as the amounts are shared by the
segments or are not meaningful in evaluating the success of the segment's
operations.

(d) Intersegment sales were conducted on an arm's length basis.

11. DISCONTINUED OPERATIONS

In the fourth quarter of 2003, we sold a significant portion of our Texas
Pipeline System and the related crude oil gathering and marketing operations to
TEPPCO Crude Oil, L.P. Additionally we sold other segments of our Texas Pipeline
System that had been idled in 2002 to Blackhawk Pipeline, L.P., an affiliate of
Multifuels, Inc., which plans to convert the segments to natural gas service.
Some remaining segments not sold to these parties were abandoned in place.

We agreed not to compete with TEPPCO in a 40-county area in Texas
surrounding the pipeline for a five year period. We retained responsibility for
environmental matters related to the operations sold to TEPPCO for the period
prior to October 31, 2003, subject to certain conditions. TEPPCO will pay the
first $25,000 for any environmental claim up to an aggregate of $100,000. We
would be responsible for any environmental claim in excess of these amounts up
to an aggregate total of $2 million. TEPPCO has purchased an environmental
insurance policy for amounts in excess of our $2 million responsibility and we
reimbursed TEPPCO for one-half of the policy premium. Our responsibility to
indemnify TEPPCO will cease in 2013.

Under the terms of the sale to Blackhawk, we received no consideration
from Blackhawk for the sale. We retained responsibility for any environmental
matters related to the pipeline segments acquired by Blackhawk through December
31, 2003, however that responsibility will cease in ten years.

The assets we abandoned had been idle since 2002 or earlier. The net book
value of these assets was charged to impairment expense in 2001.

Operating results from the discontinued operations for the years ended
December 31, 2005, 2004 and 2003 were as follows:

Year Ended December 31,
-------------------------------
2005 2004 2003
-------- -------- --------
(in thousands)

Revenues ............................................... $ - $ - $270,410
Total costs and expenses ............................... - 463 269,696
-------- -------- --------
Operating (loss) income from discontinued operations ... - (463) 714
Gain on disposal of assets ............................. 312 - 13,028
-------- -------- --------
(Loss) income from operations from discontinued
Texas System before minority interests .............. $ 312 $ (463) $ 13,742
======== ======== ========

12. TRANSACTIONS WITH RELATED PARTIES

Sales, purchases and other transactions with affiliated companies, in the
opinion of management, are conducted under terms no more or less favorable than
then-existing market conditions.

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Year Ended December 31,
------------------------
2005 2004 2003
------ ------ ------
(in thousands)

Transactions with Denbury and our General Partner

Crude oil purchases from Denbury ............................ 4,647 77,998 59,653
Crude oil sales to Denbury .................................. 176 - -
Truck transportation services provided to Denbury ........... 796 213 -
Pipeline transportation services provided to Denbury ........ 3,853 1,111 -
Payments received under direct financing lease from Denbury 1,186 76 -
Pipeline transportation income portion of direct financing
lease fees ................................................ 689 36 -
Pipeline monitoring services provided to Denbury ............ 30 22 -
Directors' fees paid to Denbury ............................. 120 120 -
CO(2) transportation services provided by Denbury ........... 3,501 2,694 355
Purchase of CO(2) volumetric payment from Denbury ........... 14,363 4,663 24,042
Operations, general and administrative services provided
by our general partner ...................................... 15,145 14,065 16,028
Distributions to our general partner on its limited partner
units and general partner interest ........................ 536 527 27

Sales and Purchases of Crude Oil

Denbury began shipping its own crude oil on our Mississippi System in
September 2004, so our purchases of crude oil from Denbury (and our related
crude oil sales) have declined.

Transportation Services

In September 2004, we entered into an agreement with Denbury where we
would provide truck transportation services to Denbury to move their crude oil
from the wellhead to our Mississippi pipeline. Previously we had purchased
Denbury's crude oil and trucked the oil for our own account. Denbury pays us a
fee for this trucking service that varies with the distance the crude oil is
trucked. These fees are reflected in the statement of operations as gathering
and marketing revenues.

In September 2004, Denbury also became a shipper on our Mississippi
pipeline. We also earned fees from Denbury under the direct financing lease
arrangements for the Olive and Brookhaven crude oil pipelines and the Brookhaven
CO(2) pipeline and recorded pipeline transportation income from these
arrangements. See Note 5.

We also provide pipeline monitoring services to Denbury. This revenue is
included in pipeline revenues in the statement of operations.

Directors' Fees

We pay Denbury for the services of each of four of Denbury's officers who
serve as directors of our general partner, the same rate at which our
independent directors were paid.

CO(2) Operations and Transportation

We acquired contracts, along with volumetric production payments, from
Denbury in 2005, 2004 and 2003. Denbury charges us a transportation fee of $0.16
per Mcf (adjusted for inflation) to deliver the CO(2) for us to our customers.
See Note 6.

Operations, General and Administrative Services

We do not directly employ any persons to manage or operate our business.
Those functions are provided by our general partner. We reimburse the general
partner for all direct and indirect costs of these services.

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Amounts due to and from Related Parties

At December 31, 2005 and 2004, we owed Denbury $1.9 million and $1.2
million, respectively, for purchases of crude oil and CO(2) transportation
charges. Denbury owed us $0.5 million and $0.4 million for transportation
services at December 31, 2005 and 2004, respectively. We owed our general
partner $1.1 million at December 31, 2005, for administrative services. We had
advanced $0.1 million to our general partner at December 31, 2004 for
administrative services.

Financing

Our general partner, a wholly owned subsidiary of Denbury, guarantees our
obligations under our credit facility. Our general partner's principal assets
are its general and limited partnership interests in us. The obligations are not
guaranteed by Denbury or any of its other subsidiaries.

13. SUPPLEMENTAL CASH FLOW INFORMATION

Cash received by us for interest during the years ended December 31, 2005,
2004 and 2003 was $46,000, $44,000, and $34,000, respectively. Payments of
interest and commitment fees were $1,468,000, $674,000, and $1,194,000, during
the years ended December 31, 2005, 2004 and 2003, respectively.

At December 31, 2005 and 2004, we had incurred liabilities for fixed asset
additions totaling $14,000 and $149,000, respectively, that had not been paid at
the end of the year and, therefore, are not included in the caption "Additions
to property and equipment" on the Consolidated Statements of Cash Flows.

14. EMPLOYEE BENEFIT PLANS

We do not directly employ any of the persons responsible for managing or
operating our activities. Employees of our general partner provide those
services and are covered by various retirement and other benefit plans.

In order to encourage long-term savings and to provide additional funds
for retirement to our employees, our general partner sponsors a profit-sharing
and retirement savings plan. Under this plan, our general partner's matching
contribution is calculated as an equal match of the first 3% of each employee's
annual pretax contribution and 50% of the next 3% of each employee's annual
pretax contribution. Our general partner also made a profit-sharing contribution
of 3% of each eligible employee's total compensation (subject to IRS
limitations). The expenses included in the consolidated statements of operations
for costs relating to this plan were $620,000, $635,000, and $507,000 for the
years ended December 31, 2005, 2004 and 2003, respectively.

Our general partner also provided certain health care and survivor
benefits for its active employees. Our health care benefit programs are
self-insured, with a catastrophic insurance policy to limit our costs. Our
general partner plans to continue self-insuring these plans in the future. The
expenses included in the consolidated statements of operations for these
benefits were $1,773,000, $1,219,000, and $1,368,000 in 2005, 2004 and 2003,
respectively.

Stock Appreciation Rights Plan

In December 2003, the Board approved a Stock Appreciation Rights (SAR)
plan for all employees of our general partner. Under the terms of this plan, all
regular, full-time active employees and the members of the Board are eligible to
participate in the plan. The plan is administered by the Compensation Committee
of the Board, who shall determine, in its full discretion, the number of rights
to award, the grant date of the units and the formula for allocating rights to
the participants and the strike price of the rights awarded. Each right is
equivalent to one common unit.

The rights have a term of 10 years from the date of grant. The initial
award to a participant will vest one-fourth each year beginning with the first
anniversary of the grant date of the award. Subsequent awards to participants
will vest on the fourth anniversary of the grant date. If the right has not been
exercised at the end of the ten year term and the participant has not terminated
his employment with us, the right will be deemed exercised as of the date of the
right's expiration and a cash payment will be made as described below.

Upon vesting, the participant may exercise his rights and receive a cash
payment calculated as the difference between the average of the closing market
price of our common units for the ten days preceding the date of exercise over
the strike price of the right being exercised. The cash payment to the
participant will be net of any applicable withholding taxes required by law. If
the Committee determines, in its full discretion, that it would cause

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

significant financial harm to the Partnership to make cash payments to
participants who have exercised rights under the plan, then the Committee may
authorize deferral of the cash payments until a later date.

At December 31, 2005, awards of 596,128 rights were outstanding, of which
168,863 were vested on December 31, 2005. The value of the total rights
outstanding at December 31, 2005 was $0.8 million. The vested rights had a value
to participants of $0.4 million at December 31, 2005. In 2005, we recorded a
non-cash credit of $0.5 million in general and administrative expense for the
decrease in the value of the outstanding rights due to the decrease in the
closing market price for common units between December 31, 2005 and December 31,
2004. In 2004 and 2003, we recorded non-cash expense of $1,151,000 and $228,000,
respectively, for the increase in the value of the outstanding rights.

Bonus Plan

In March 2003, the Compensation Committee of the Board of Directors of our
general partner approved a Bonus Plan (the "Bonus Plan") for all employees of
the general partner. The Bonus Plan is designed to enhance the financial
performance of the Partnership by rewarding all employees for achieving
financial performance objectives. The Bonus Plan will be administered by the
Compensation Committee. Under this plan, amounts will be allocated for the
payment of bonuses to employees each time our operating partnership earns $1.6
million of available cash. The amount allocated to the bonus pool increases for
each $1.6 million earned, such that a bonus pool of $2.3 million will exist if
the Partnership earns $14.6 million of available cash. We accrued $1.2 million
and $0.2 million for the bonus pool for 2005 and 2004, respectively.

Bonuses will be paid to employees after the end of the year, but only if
distributions are made to the common unitholders. The amount in the bonus pool
will be allocated to employees based on the group to which they are assigned.
Employees in the first group can receive bonuses that range from zero to ten
percent of base compensation. The next group includes employees who could earn a
total bonus ranging from zero to twenty percent. Certain members are eligible to
earn a total bonus ranging from zero to thirty percent. Lastly, our officers and
other senior management are eligible for a total bonus ranging from zero to
forty percent. The Bonus Plan will be at the discretion of the Compensation
Committee, and our general partner can amend or change the Bonus Plan at any
time.

Severance Protection Plan

A change in control is defined in the Severance Plan. Generally, a change
in control is a change in the control of Denbury, a disposition by Denbury of
more than 50% of our general partner, or a transaction involving the disposition
of substantially all of the assets of Genesis.

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

15. MAJOR CUSTOMERS AND CREDIT RISK

We have established various procedures to manage our credit exposure,
including initial credit approvals, credit limits, collateral requirements and
rights of offset. Letters of credit, prepayments and guarantees are also
utilized to limit credit risk to ensure that our established credit criteria are
met.

Occidental Energy Marketing, Inc. and Shell Oil Company accounted for
26.5% and 12.5% of total revenues in 2005, respectively. Occidental Energy
Marketing, Inc., Marathon Ashland Petroleum LLC and Plains Marketing, L.P.
accounted for 20.4%, 12.8% and 10.0% of total revenues in 2004, respectively.
Marathon Ashland Petroleum LLC, ExxonMobil Corporation and Shell Oil Company
accounted for 22.5%, 15.4% and 11.0% of total revenues in 2003, respectively.
The majority of the revenues from these five customers in all three years relate
to our gathering and marketing operations.

16. FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying values of cash and cash equivalents, accounts receivable,
accounts payable and accrued liabilities in the Consolidated Balance Sheets
approximated fair value due to the short maturity of these instruments.

The carrying value of the direct financing leases in the Consolidated
Balance Sheets approximated fair value as these leases began at the end of 2004
when the assets were constructed.

17. DERIVATIVES

Our market risk in the purchase and sale of crude oil contracts is the
potential loss that can be caused by a change in the market value of the asset
or commitment. In order to hedge our exposure to such market fluctuations, we
may enter into various financial contracts, including futures, options and
swaps. Historically, any contracts we have used to hedge market risk were less
than one year in duration, although we have the flexibility to enter into
arrangements with a longer term.

We may utilize crude oil futures contracts and other financial derivatives
to reduce our exposure to unfavorable changes in crude oil prices. Every
derivative instrument (including certain derivative instruments embedded in
other contracts) must be recorded in the balance sheet as either an asset or
liability measured at its fair value. Changes in the derivative's fair value
must be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a derivative's
gains and losses to offset related results on the hedged item in the income
statement. Companies must formally document, designate and assess the
effectiveness of transactions that receive hedge accounting.

We mark to fair value our derivative instruments at each period end, with
changes in the fair value of derivatives that are not designated as hedges being
recorded as unrealized gains or losses. Such unrealized gains or losses will
change, based on prevailing market prices, at each balance sheet date prior to
the period in which the transaction actually occurs. The effective portion of
unrealized gains or losses on derivative transactions qualifying as cash flow
hedges are reflected in other comprehensive income. Derivative transactions
qualifying as fair value hedges are evaluated for hedge effectiveness and the
resulting hedge ineffectiveness is recorded as a gain or loss in the
consolidated statements of operations.

We review our contracts to determine if the contracts meet the definition
of derivatives pursuant to SFAS 133. At December 31, 2005, we had forward and
futures contracts that were considered free-standing derivatives that are
accounted for at fair value. The fair value of these contracts was determined
based on the closing price for such contracts on December 31, 2005. We marked
these contracts to fair value at December 31, 2005. During the year ended
December 31, 2005, we recorded income of $14,000 related to derivative
transactions, which are included in the consolidated statements of operations
under the caption "Crude Oil Costs".

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

During the year ended December 31, 2005, we recognized gains, due to hedge
ineffectiveness, on the fair value hedge of 60,000 barrels of inventory totaling
$73,000. This gain is included in the caption "Crude Oil Costs" in the
consolidated statements of operations. The time value component of the
derivative gain or loss excluded from the assessment of hedge effectiveness was
not material.

The consolidated balance sheet at December 31, 2005 includes an increase
in other current assets of $6,000 as a result of these derivative transactions.

We determined that the remainder of our derivative contracts qualified for
the normal purchase and sale exemption and were designated and documented as
such at December 31, 2005, 2004 and 2003.

18. COMMITMENTS AND CONTINGENCIES

Commitments and Guarantees

We lease office space for our headquarters office under a long-term lease.
The lease extends until October 31, 2008. We lease office space for two field
offices under leases that expire in 2007 and 2013. Ryder Transportation, Inc.
and Paccar Leasing Services provide tractors and trailers to us under operating
leases that also include full-service maintenance. We pay a fixed monthly rental
charge for each tractor and trailer and a fee based on mileage for the
maintenance services. We lease tanks for use in our pipeline operations.
Beginning in 2005, we are reimbursed for the costs of the tank lease by a
customer, under a reimbursement agreement covering the period of the tank lease.
Additionally, we lease a segment of pipeline. Under the terms of that lease, we
make lease payments based on throughput, and we have no minimum volumetric or
financial requirements remaining. We also lease service vehicles for our field
personnel.

The future minimum rental payments under all non-cancelable operating
leases as of December 31, 2005, were as follows (in thousands).

Office Tractors and Service
Space Trailers Tanks Vehicles Total
------ ------------ ----------- -------- -------

2006 .......................... $ 342 $ 1,730 $ 493 $ 251 $ 2,816
2007 .......................... 363 1,702 508 177 2,750
2008 .......................... 300 1,702 134 2,136
2009 .......................... 54 1,638 - - 1,692
2010 .......................... 54 950 - - 1,004
2011 and thereafter ........... 120 244 - - 364
------- ------- -------- -------- -------
Total minimum lease obligations $ 1,233 $ 7,966 $ 1,001 $ 562 $10,762
======= ======= ========= ======== =======

Total operating lease expense was as follows (in thousands).

Year ended December 31, 2005.................................................... $ 3,929
Year ended December 31, 2004.................................................... $ 3,824
Year ended December 31, 2003.................................................... $ 4,736

We guaranteed $1.4 million of residual value related to the leases of
tractors and trailers from Ryder. We believe the likelihood we would be required
to perform or otherwise incur any significant losses associated with this
guaranty is remote.

Along with our general partner, we have guaranteed the payments by our
operating partnership to the banks under the terms of our credit facility
related to borrowings and letters of credit. To the extent liabilities exist
under the letters of credit, such liabilities are included in the consolidated
balance sheet. We had no outstanding borrowings at December 31, 2005.

In general, we expect to incur expenditures in the future to comply with
increasing levels of regulatory safety standards. While the total amount of
increased expenditures cannot be accurately estimated at this time, we
anticipate that we will expend a total of approximately $0.2 million in 2006 and
2007 for testing, repairs and improvements under regulations requiring
assessment of the integrity of crude oil pipelines. After 2007 we expect

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

that our annual expenditures for integrity testing, repairs and improvements to
average from $1.0 million to $1.5 million.

Pennzoil Litigation

We were named a defendant in a complaint filed on January 11, 2001, in the
125th District Court of Harris County, Texas, Cause No. 2001-01176.
Pennzoil-Quaker State Company (PQS) was seeking from us property damages, loss
of use and business interruption suffered as a result of a fire and explosion
that occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on
January 18, 2000. PQS claimed the fire and explosion were caused, in part, by
crude oil we sold to PQS that was contaminated with organic chlorides. In
December 2003, our insurance carriers settled this litigation for $12.8 million.

PQS is also a defendant in five consolidated class action/mass tort
actions brought by neighbors living in the vicinity of the PQS Shreveport,
Louisiana refinery in the First Judicial District Court, Caddo Parish,
Louisiana, Cause Nos. 455,647-A, 455,658-B, 455,655-A, 456,574-A, and 458,379-C.
PQS has brought a third party claims against us and others for indemnity with
respect to the fire and explosion of January 18, 2000. We believe that the
demand against us is without merit and intend to vigorously defend ourselves in
this matter. We currently believe that this matter will not have a material
financial effect on our financial position, results of operations, or cash
flows.

Environmental

We were formed in 1996 by the sale and contribution of assets from Howell
and Basis Petroleum, Inc. Anadarko's liability with respect to the Jay Station
is derived largely from contractual obligations entered into upon our formation.
We believe that Basis has contractual obligations under the same formation
agreements. We intend to seek recovery of Basis' share of potential liabilities
and defense costs with respect to Jay Station.

We have contacted the appropriate state regulatory agencies regarding
developing a plan of remediation for certain affected soils at the Jay Station.
It is possible that we will also need to develop a plan for other affected soils
and/or affected groundwater. We have accrued an estimate of our share of
liability for this matter in the amount of $0.5 million. The time period over
which our liability would be paid is uncertain and could be several years. This
liability may decrease if indemnification and/or cost reimbursement is obtained
by us for Basis' potential liabilities with respect to this matter. At this
time, our estimate of potential obligations does not assume any specific amount
contributed on behalf of the Basis obligations, although we believe that Basis
is responsible for a significant part of these potential obligations.

We are subject to various environmental laws and regulations. Policies and
procedures are in place to monitor compliance and to detect and address any
releases of crude oil from our pipelines or other facilities, however no
assurance can be made that such environmental releases may not substantially
affect our business.

Other Matters

We have taken additional security measures since the terrorist attacks of
September 11, 2001 in accordance with guidance provided by the Department of
Transportation and other government agencies. We cannot assure you that these
security measures would prevent our facilities from a concentrated attack. Any
future attacks on us or our

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

customers or competitors could have a material effect on our business, whether
insured or not. We believe we are adequately insured for public liability and
property damage to others and that our coverage is similar to other companies
with operations similar to ours. No assurance can be made that we will be able
to maintain adequate insurance in the future at premium rates that we consider
reasonable.

We are subject to lawsuits in the normal course of business and
examination by tax and other regulatory authorities. We do not expect such
matters presently pending to have a material adverse effect on our financial
position, results of operations or cash flows.

19. SUBSEQUENT EVENTS

Distribution

On January 23, 2006, the Board of Directors of the general partner
declared a cash distribution of $0.17 per unit for the quarter ended December
31, 2005. The distribution was paid on February 14, 2006, to our general partner
and all common unitholders of record as of the close of business on February 3,
2006.

EXHIBIT INDEX

Exhibit no. Description
----------- -----------
3.1 Certificate of Limited Partnership of Genesis Energy, L.P.
("Genesis") (incorporated by reference to Exhibit 3.1 to
Registration Statement, File No. 333-11545)